diff --git a/raw/filings/0000077877/2005/0000077877-06-000037/item13.txt b/raw/filings/0000077877/2005/0000077877-06-000037/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..6df376e7fdbe87981001154f9d0ce06315e2bad1 --- /dev/null +++ b/raw/filings/0000077877/2005/0000077877-06-000037/item13.txt @@ -0,0 +1,7 @@ +Item 13. Certain Relationships and Related Transactions +During the year ended December 31, 2005, there was no transaction or +series of transactions to which we were or are a party in which the amount +involved exceeded or exceeds $60,000 and in which any director, executive +officer, holder of more than 5% of our common stock or any member of the +immediate family of any of the foregoing persons had or will have a direct or +indirect material interest. \ No newline at end of file diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/filing.txt b/raw/filings/0000077877/2012/0000077877-13-000017/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..3762cc2592efc257d2f19f0d9de95b998af83e97 --- /dev/null +++ b/raw/filings/0000077877/2012/0000077877-13-000017/filing.txt @@ -0,0 +1,8101 @@ +10-K +1 +pdce-10kxfy12.htm +10-K +PDCE-10K-FY12 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2012 +or +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 000-07246 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer x +Accelerated filer o +Non-accelerated filer £ +(Do not check if a smaller reporting company) +Smaller reporting company o +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2012 was $735,547,944 (based on the then closing price of $24.52 per share). +As of February 8, 2013 , there were 30,316,670 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2012 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +2 +Item 1A. +Risk Factors +19 +Item 1B. +Unresolved Staff Comments +31 +Item 3. +Legal Proceedings +31 +Item 4. +Mine Safety Disclosures +31 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +32 +Item 6. +Selected Financial Data +34 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +35 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +52 +Item 8. +Financial Statements and Supplementary Data +55 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +55 +Item 9A. +Controls and Procedures +55 +Item 9B. +Other Information +55 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +56 +Item 11. +Executive Compensation +56 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +56 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +56 +Item 14. +Principal Accounting Fees and Services +56 +PART IV +Item15. +Exhibits, Financial Statement Schedule +56 +Signatures +60 +Glossary of Units of Measurements and Industry Terms +61 +PART I +REFERENCES TO THE REGISTRANT +At our annual meeting of stockholders held on June 7, 2012, the stockholders approved a change of the Company's legal name from Petroleum Development Corporation to PDC Energy, Inc. Reflecting this change, on July 16, 2012, our common stock began trading on the NASDAQ Global Select Market under the ticker symbol "PDCE." Information contained on or linked to our website, www.pdce.com, is not part of this report and is not hereby incorporated by reference and should not be considered part of this report. +Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our," "ours" or "ourselves" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture currently owned 50% each by PDC and Lime Rock Partners, LP, formed for the purpose of exploring and developing the Marcellus Shale formation in the Appalachian Basin. Unless the context otherwise requires, references in this report to "Appalachian Basin" includes PDC's proportionate share of our affiliated partnerships' and the PDCM's assets, results of operations, cash flows and operating activities. +See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report, are set in boldface type the first time they appear. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated natural gas, natural gas liquids (“ NGLs ”) and crude oil reserves ; future production (including the components of such production), expenses, cash flows, margins and liquidity; anticipated capital projects, expenditures and opportunities, including drilling locations and downspacing potential; future exploration and development activities; availability of additional midstream facilities and services in the Wattenberg Field and timing of that availability; availability of sufficient funding for our capital program and sources of that funding; potential for infrastructure projects to improve our NGL pricing; our compliance with debt covenants and the renewal of a letter of credit under our revolving credit facility; adequacy of our insurance; the future effect of contracts, policies and procedures we believe to be customary; effectiveness of our derivative program in providing a degree of price stability; our future dividend policy; closing of, and expected proceeds from, our pending asset disposition; and our future strategies, plans and objectives. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in production volumes and worldwide demand, including economic conditions that might impact demand; +• +volatility of commodity prices for natural gas, NGLs and crude oil; +• +the impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• +potential declines in the values of our natural gas and crude oil properties resulting in impairments; +• +changes in estimates of proved reserves ; +• +inaccuracy of reserve estimates and expected production rates; +• +potential for production decline rates from our wells to be greater than expected; +• +timing and extent of our success in discovering, acquiring, developing and producing reserves; +• +our ability to acquire leases, drilling rigs, supplies and services at reasonable prices; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of natural gas and crude oil wells; +• +our future cash flows, liquidity and financial condition; +• +competition in the oil and gas industry; +1 +• +availability and cost of capital to us; +• +reductions in the borrowing base under our revolving credit facility; +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production, particularly in the Wattenberg Field, and the impact of these facilities on the prices we receive for our production; +• +our success in marketing natural gas, NGLs and crude oil; +• +effect of natural gas and crude oil derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital expenditures; +• +potential obstacles to completing our pending asset disposition or other transactions, in a timely manner or at all, and purchase price or other adjustments relating to those transactions that may be unfavorable to us; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for future operations of the Company. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, develops, explores and produces natural gas, NGLs and crude oil with operations in the Western and Eastern regions of the United States. Our Western Operating Region is primarily focused on development in the Wattenberg Field in Colorado, particularly in the liquid-rich horizontal Niobrara and Codell plays. In our Eastern Operating Region, we are currently focused on development activity in the liquid-rich portion of the Utica Shale play in Ohio. We are also pursuing horizontal development in the Marcellus Shale in northern West Virginia through our 50% joint venture interest in PDCM. We own an interest in approximately 7,200 gross producing wells and maintained an average production rate of 135.6 MMcfe per day for the year ended December 31, 2012 , which was comprised of 65.3% natural gas, 10.2% NGLs and 24.5% crude oil. This represents production growth of 10.2% from continuing operations as compared to the year ended December 31, 2011 . As of December 31, 2012 , we had approximately 1.2 Tcfe of proved reserves with a present value of future net revenues (“PV-10”) value, which is not a financial measure under Accounting Principles Generally Accepted in the United States of America (“U.S. GAAP”), of $1.7 billion , representing growth of 141 Bcfe and $359 million , respectively, relative to the totals as of December 31, 2011 . The percentage of our proved reserves represented by NGLs and crude oil rose to 48% as of December 31, 2012 , up from 34% as of December 31, 2011 . See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10% and a reconciliation of our PV-10% value to our standardized measure . +The increase in our estimated proved reserves and production is primarily attributable to liquid-rich horizontal drilling activities in the Wattenberg Field and our June 2012 acquisition of certain Wattenberg Field properties and related assets from affiliates of Merit Energy (the "Merit Acquisition") for $304.6 million , after certain post-closing adjustments. The acquired assets comprise approximately 29,800 net acres , after post-closing adjustments, located almost entirely in the core Wattenberg Field with significant overlay with our existing acreage position. We believe that the Merit Acquisition should provide us with an opportunity to continue our rapid growth in the Wattenberg Field and to substantially increase our oil and NGL production. We drilled 37 horizontal Niobrara and Codell wells, completed 160 refracture and recompletion projects and participated in 19 non-operated drilling projects in the Wattenberg Field in 2012. +In our Eastern Operating Region, we have acquired an estimated 45,000 net acres targeting the wet gas and crude oil windows of the Utica Shale in southeast Ohio. Our year-end 2012 proved reserves do not include reserves associated with our Utica Shale properties. We drilled and completed two horizontal Utica Shale wells in 2012, both of which are currently shut-in awaiting pipeline connections. We also drilled one vertical Utica Shale well and completed two vertical Utica test wells in 2012 for the primary purpose of providing engineering and geological data in support of the horizontal play. In addition, PDCM drilled three and completed six horizontal Marcellus wells and constructed various midstream projects in 2012. +2 +The following table presents our historical proved reserve estimates as of December 31, 2012 based on a reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm: +Proved Reserves at December 31, 2012 +Proved Reserves (Bcfe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years) +Production (MMcfe) +Western +Wattenberg Field +893.5 +77 +% +41 +% +62 +% +33.4 +26,748 +Other +84.6 +8 +% +100 +% +1 +% +5.1 +16,672 +Total Western +978.1 +85 +% +46 +% +56 +% +22.5 +43,420 +Eastern +Appalachian Basin +178.8 +15 +% +23 +% +— +% +28.9 +6,192 +Total Eastern +178.8 +15 +% +23 +% +— +% +28.9 +6,192 +Total proved reserves +1,156.9 +100 +% +42 +% +48 +% +23.3 +49,612 +On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives, for aggregate cash consideration of approximately $200 million, subject to certain adjustments. As of December 31, 2012, total estimated proved reserves related to these assets were 84.6 Bcfe. See Note 19, Subsequent Events , to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture. +In addition to our oil and gas exploration and production activities, we engage in natural gas marketing through our subsidiary Riley Natural Gas (“RNG”). +Our Strengths +• +Multi-year project inventory targeting highly economic oil and NGL production growth. We have a significant operational presence in three key U.S. onshore basins and have identified a substantial inventory of approximately 4,100 gross capital projects across our assets. This inventory includes approximately 3,300 gross projects in the liquid-rich Wattenberg Field, of which approximately 1,400 are horizontal Niobrara and Codell proved and probable locations that we expect to be capable of providing liquid-rich production growth for the next several years at attractive rates of return based on current strip prices. Potential downspacing of future drill sites would provide the opportunity for additional locations. In the core area of the Wattenberg Field, we have achieved an average of 335 MBoe gross reserves per horizontal well, with approximately 75% liquids contribution. In the Appalachian Basin, we have approximately 600 gross Marcellus Shale drilling locations in inventory, of which approximately 360 gross wells in our core focus area would be expected to generate reserves of 5 to 7 Bcfe per well. In addition, our leasehold position in the emerging Utica Shale play is expected to provide approximately 200 horizontal drilling opportunities in liquid rich areas. With the development of the horizontal Niobrara and Codell and exploration and delineation of acreage in the Utica Shale, we are focused on transitioning our portfolio to a higher mix of oil and NGLs that we believe is capable of delivering higher margins and improved capital efficiencies. +• +Track record of reserve and production growth. Our proved reserves have grown from 323 Bcfe at December 31, 2006 to approximately 1.2 Tcfe at December 31, 2012, representing a compound annual growth rate (“CAGR”) of 23.7%. During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 52.7%. Our annual production grew from 16.9 Bcfe in 2006 to 49.6 Bcfe in 2012 from continuing operations, representing a CAGR of 19.7%. +• +Horizontal drilling and completion experience. We have a proven track record of applying technical expertise toward developing unconventional resources through horizontal drilling, having drilled 108 Niobrara, Codell, Marcellus and Utica horizontal wells as of December 31, 2012. We have begun multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We have approximately 2,000 gross horizontal proved and probable locations in inventory from our Wattenberg and Marcellus positions. Our current leasehold position in the emerging Utica Shale play is expected to provide approximately 200 horizontal drilling opportunities in liquid-rich areas. +• +Significant operational control in our core areas. As a result of successfully executing our strategy over time of acquiring largely concentrated acreage positions with a high working interest , we operate and manage approximately 89% of our oil and natural gas properties. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas. +• +Access to liquidity. As of December 31, 2012, we had $2.5 million of cash and cash equivalents and $396.1 million available for +3 +borrowing under our revolving credit facility. We have no near-term debt maturities, although we periodically repay borrowings outstanding under our revolving credit facility. We actively hedge our future exposure to commodity price fluctuations by entering into oil and natural gas swaps and collars. We have hedged approximately 28.7 Bcf of our natural gas production for 2013 at an average minimum price of $4.15 per Mcf. We have hedged approximately 2,326 MBbls of our oil production in 2013 at an average minimum price of $88.75 per Bbl. As of December 31, 2012, the net fair value of all of our hedges was approximately $30.3 million. +• +Management experience and operational expertise. We have a management team with a proven track record of performance and a technical and operational staff with significant expertise in the basins in which we operate, particularly with horizontal well development activities. +Business Strategy +Our business strategy focuses on generating shareholder value through the organic growth of our reserves, production and cash flows in our high-value, liquid-rich horizontal drilling programs. We also engage in targeted exploratory drilling of unconventional resources and maintain an active acquisition program. We pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins and maintain a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +Drill and Develop +Our leasehold interests consist of developed and undeveloped natural gas, NGLs and crude oil resources located in our Western and Eastern Operating Regions. Based on our prior acreage holdings and recent acquisitions, we have identified a substantial inventory of approximately 4,100 gross capital projects for development primarily through horizontal drilling in high-return, liquid-rich plays, as well as refracture and recompletion opportunities. +Western Operating Region . Our primary focus in the liquid-rich Wattenberg Field is the horizontal Niobrara and Codell plays. We have begun multi-well pad drilling to further optimize costs and enhance horizontal drilling efficiencies in the Wattenberg Field. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We also maintain a vertical drilling inventory in the Niobrara and Codell formations. We currently estimate that we have 3,300 gross capital projects, which include over 1,400 gross proved and probable projects for the horizontal Niobrara and Codell. Depending upon commodity prices and the number of drilling rigs operating, we believe that this inventory of projects provides us with over 10 years of drilling activity. +Of our total capital budget of $324 million for 2013, approximately 75%, or $245 million , is expected to be spent on development activities, substantially all of which is expected to be invested in the Wattenberg Field for an expanded horizontal Niobrara and Codell drilling program and participation in various non-operated projects. We plan to run a two-rig program in the Wattenberg Field through the second quarter of the year and add a third rig during the third quarter. Under this drilling program, we expect to drill approximately 63 horizontal Niobrara or Codell wells in 2013. +Additionally, we operate natural gas assets in the Piceance Basin in western Colorado and in northeast Colorado ("NECO"), where we focused on production optimization and increasing operating margins in 2012. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives. See Note 19, Subsequent Events , to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture. +Eastern Operating Region . We continue to delineate and develop our leasehold position in the Utica Shale. To date, we have drilled two vertical test wells to collect geologic data and two horizontal wells to test the productivity of the acreage. We currently estimate we have approximately 200 gross projects for horizontal drilling in the Utica Shale. In 2013, we expect to devote approximately $53 million of our 2013 capital program primarily toward drilling and completion activity in the Utica Shale, where we plan to drill approximately five horizontal wells targeting the wet gas and crude oil windows of the play. +Our other focus in the Eastern Operating Region is on horizontal drilling in the Marcellus Shale in West Virginia. In 2012, PDCM completed a total of six gross (three net) horizontal wells and constructed various midstream assets to gather and compress its Marcellus gas. We currently estimate we have approximately 600 gross projects for horizontal drilling in the Marcellus Shale. PDCM expects to drill a total of 14 gross horizontal Marcellus wells in 2013. +Strategically acquire +We typically pursue the acquisition of assets that have a balance of value in producing wells, behind-pipe reserves and high-quality undeveloped drilling locations. In 2010, we began seeking liquid-rich properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. We have an experienced team of management, engineering and geosciences professionals who identify and evaluate acquisition opportunities. +In June 2012, we completed the Merit Acquisition for an aggregate purchase price of approximately $304.6 million , after certain post-closing adjustments. We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit +4 +facility. The acquired assets comprise approximately 29,800 net acres, after post-closing adjustments, located almost entirely in the core Wattenberg Field and with significant overlay with our existing acreage position. Following the closing of the Merit Acquisition, our total position in the core Wattenberg Field is approximately 98,600 net acres. +During 2011 and 2012, we acquired approximately 45,000 net acres of Utica leaseholds, targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio, for a purchase price of approximately $92.3 million. As an early entrant into the development of the Utica Shale, we believe we have gained valuable experience and expertise in proactively addressing title and other issues associated with the development of the play. +In October 2011, PDCM acquired 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur”) from an unrelated third-party for $139.2 million . The acquisition included approximately 1,340 gross wells producing natural gas from the shallow Devonian Shale and Mississippian formations and all rights and depths to an estimated 100,000 net acres in West Virginia, of which 90,000 acres are prospective for the Marcellus Shale. Substantially all of the acreage acquired is held by production and is in close proximity to PDCM's existing properties. Pursuant to our joint venture interest in PDCM, our portion of the purchase price was $69.6 million and we hold a 50% interest in both the wells and acreage acquired. +In 2010, we initiated a plan to purchase our affiliated partnerships. As of December 31, 2012, we had acquired a total of 12 affiliated partnerships for an aggregate purchase price of $107.7 million . The acquisition of these partnerships have provided us with immediate growth in both production and proved reserves from assets in which we currently own an operated working interest. +Manage operational and financial risk +We focus on development drilling programs in resource plays that offer repeatable results capable of driving growth in reserves, production and cash flows. We regularly review acquisition opportunities in our core areas of operation as we believe we can extract additional value from such assets through production optimization, refractures and recompletions and development drilling. In addition, core acquisitions can potentially provide synergies that result in economies of scale from a combined position. While we believe development drilling will remain the foundation of our capital programs, we continue our disciplined approach to acquisitions and exploratory drilling, both of which have the potential to identify new development opportunities. +We believe we proactively employ strategies to help reduce the financial risks associated with the oil and gas industry. One such strategy is to maintain a balanced production mix of natural gas and liquids. Our Western Operating Region produces natural gas, NGLs and crude oil, with a production mix of approximately 60.5% natural gas to 39.5% liquids during 2012. We expect that the Merit Acquisition and our horizontal drilling program will allow us to substantially increase our crude oil and NGL production. While our legacy properties in the Eastern Operating Region primarily produce natural gas, our Ohio properties are prospective in the wet gas and crude oil windows of the Utica Shale. This strategy of a diversified commodity mix helps to mitigate the financial impact from a decline in the market price in any one of our commodities. In addition, we utilize commodity-based derivative instruments to manage a substantial portion of our exposure to price volatility with regard to our natural gas and crude oil sales and natural gas marketing. As of December 31, 2012, we had natural gas and crude oil derivative positions in place for 2013 covering approximately 28.7 Bcfe of our natural gas production and approximately 2,326 MBbls of our crude oil production. Currently, we do not hedge our NGL production. See Part II, Item 7A , Quantitative and Qualitative Disclosures about Market Risk, for a detailed summary of our open derivative positions. +Selective exploration +We believe that our disciplined exploration program has the potential to consistently replenish our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years. Due to the continued decline in natural gas prices, we have focused our efforts toward liquid-rich plays to take advantage of the current attractive economics associated with crude oil and NGL weighted projects. We strive to identify potential plays in their early stages in an attempt to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry. We seek investment in leasehold positions that are in the proximity of existing or emerging pipeline infrastructures. We believe the leasehold we acquired targeting the Utica Shale meets these criteria and we see the derisking and delineation of this leasehold as our primary exploration focus during for 2013. +Business Segments +We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +Oil and Gas Exploration and Production +Our Oil and Gas Exploration and Production segment primarily reflects revenues and expenses from the production and sale of natural gas, NGLs and crude oil. +• +Natural gas . We primarily sell our natural gas to midstream marketers, utilities, industrial end-users and other wholesale purchasers. We generally sell the natural gas that we produce under contracts with indexed or NYMEX monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers +5 +to a gathering or transmission line and the quality of the natural gas. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, our revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. We believe that the pricing provisions of our natural gas contracts are customary in the industry. +• +NGLs . The majority of our NGLs are sold to one NGL marketer in the Wattenberg Field. Our NGL production is sold under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price. +• +Crude oil . We do not refine any of our crude oil production. We sell our crude oil to oil marketers and refiners. Our crude oil production is sold to purchasers at or near our wells under both short- and long-term purchase contracts with monthly pricing provisions based on an average daily price. +We enter into financial derivatives in order to reduce the impact of possible price volatility regarding the physical sales market. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations - Commodity Price Risk Management, Net, Natural Gas and Crude Oil Derivative Activities , Item 7A, Quantitative and Qualitative Disclosures about Market Risk, and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report. +Our Oil and Gas Exploration and Production segment also reflects revenues and expenses related to well operations and pipeline services. We are paid a monthly operating fee for the portion of each well we operate that is owned by others, including our affiliated partnerships. We believe the fee is competitive with rates charged by other operators in the area. As we acquire the working interest of our non-affiliated investor partners in our affiliated partnerships, revenues related to well operations and pipeline services will decrease. +We construct, own and operate gathering systems in some of our areas of operations. Pipelines and related facilities can represent a significant portion of the capital costs of developing wells, particularly in new areas located at a distance from existing pipelines. We consider these costs in the evaluation of our leasing, development and acquisition opportunities. +Our natural gas is transported through our own and third-party gathering systems and pipelines, and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based upon the volume and distance shipped, as well as the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally interrupted due to operational issues, repairs or improvements. A portion of our natural gas is transported under interruptible contracts and the remainder under firm transportation agreements, either directly with RNG or through third-party processors or marketers. Therefore, interruptions in natural gas sales could result if pipeline space is constrained. As discussed in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Operational Overview, our 2012 production was adversely affected by high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure was the result of a series of operational issues and capacity constraints, primarily in the second and third quarters. The operational issues included downtime on downstream third-party NGL transportation and fractionation facilities and abnormally warm weather, which limited third-party gathering system compression capacity. We are working closely with our primary midstream provider who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, we do not expect the impact of this increased capacity to substantially benefit us until late 2013. While our ability to market these volumes of natural gas has been only infrequently limited or delayed, if transportation space is restricted or is unavailable, our production and cash flows from the affected properties could be adversely affected. +In certain instances, we enter into firm transportation agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. In order to meet pipeline specifications, we are required, in some cases, to process our natural gas before we can transport it. We typically contract with third parties in the NECO area of our Western Operating Region and our Eastern Operating Region for firm transportation of our natural gas. We also may enter into firm sales agreements to ensure that we are selling to a purchaser who has contracted for pipeline capacity. See Note 11, Commitments and Contingencies - Firm Transportation Agreements , to our consolidated financial statements included elsewhere in this report for our long-term firm sales, processing and transportation agreements for pipeline capacity. +Our crude oil production is marketed directly to purchasers in the Wattenberg Field area under a combination of annual and short-term monthly agreements. The majority of our crude oil is delivered to local area refineries with other volumes being either trucked or shipped via pipeline out of the Wattenberg area. +See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results, for production, sales, prices and lifting cost data for each of the years in the three-year period ended December 31, 2012. +Gas Marketing +Our Gas Marketing segment is comprised solely of the operating activities of RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in the Eastern Operating Region. RNG purchases for resale natural gas produced by third-party producers, as well as natural gas produced by us, PDCM and our affiliated partnerships. The natural gas is marketed to third-party marketers, natural gas utilities and industrial and commercial customers, either directly through our gathering system or through transportation services provided by regulated interstate pipeline companies. Additionally, RNG markets our natural gas production in the NECO area. +6 +For additional information regarding our business segments, see Note 18, Business Segments , to our consolidated financial statements included elsewhere in this report. +Areas of Operations +The following map presents the general locations of our development, production and exploration activities as of December 31, 2012. With the divestiture of our Permian Basin assets on February 28, 2012, our development, production and exploration efforts are primarily focused in two geographic areas of the U.S. +___________ +(1) On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus, pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture. +Western Operating Region +Our primary focus in the Western Operating Region for 2013, and we expect for the next several years, is on horizontal Niobrara and Codell development drilling. We divide our Western Operating Region into the following areas: +• +Wattenberg Field, DJ Basin, Colorado. Currently, wells drilled in this area are horizontal wells targeting the liquid-rich reservoirs in the Codell and Niobrara formations. These horizontal wells have a vertical depth range from approximately 7,000 to 8,000 feet, with an average lateral length of 4,000 feet. We drill multi-well pads to further optimize costs and enhance horizontal drilling efficiencies in the Wattenberg Field. Pad drilling enables us to streamline the transition to increased well density in the horizontal Niobrara and Codell plays. We have approximately 3,300 gross projects, including over 1,400 proved and probable horizontal projects, in the liquid-rich Wattenberg Field. +In June 2012, we completed an acquisition of approximately 29,800 net acres in the core area, which positions us as the third largest producer and leaseholder in the core Wattenberg area. We estimate that the Wattenberg Field has approximately 400 horizontal drilling locations based on 4 gross wells per section for our proved undeveloped reserves ("PUDs"). Additional potential upside exists as we continue testing the Codell formation and plan to test downspacing to 10 gross wells per section in the play as part of our 2013 horizontal program, which is the basis for our estimate of over 1,400 horizontal wells in our proved and probable inventory. +• +Piceance Basin, Colorado. Wells in this area predominately target natural gas from the Williams Fork formation. For 2012, we removed all PUD reserves in the Piceance Basin due to low natural gas prices. Our 2012 Piceance natural gas reserves were 66.5 Bcfe, or approximately 6% of our total proved equivalent reserves. Our Piceance reserves represent approximately 2% of our +7 +PV-10% as of December 31, 2012. See table in the Properties - Proved Reserves section below for information regarding our proved reserves and PV-10% as of December 31, 2012. +The majority of the wells drilled in this area are drilled directionally from multi-well drilling pads, generally range from two to ten wells per pad and range from 7,000 to 9,500 feet in depth. Reserves in this area originate from multiple sandstone reservoirs in the Mesaverde Williams Fork formation. Well spacing is approximately ten acres per well. +• +Northeastern Colorado . Wells drilled in this area range from 1,500 to 3,000 feet in depth and target natural gas reserves in the shallow Niobrara reservoir. Well spacing is approximately 40 acres per well. +As noted above, on February 4, 2013, we entered into a purchase and sale agreement with Caerus pursuant to which Caerus agreed to purchase our Piceance Basin, NECO and other non-core Colorado leasehold mineral interests and various other assets within these basins for an aggregate cash consideration of approximately $200 million, subject to post-closing adjustments. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus as part of the transaction. The effective date of the transaction is January 1, 2013. We intend to use the proceeds from the sale to repay a portion of amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. There can be no assurance we will be successful in closing such divestiture. +Eastern Operating Region +Our primary focus in the Eastern Operating Region is on horizontal drilling in the Utica Shale in southeastern Ohio and the Marcellus Shale play in northern West Virginia. +• +Utica Shale, Ohio. We have acquired approximately 45,000 net acres targeting the wet natural gas and crude oil windows of the Utica Shale play throughout southeastern Ohio. To date, we have drilled and completed two horizontal wells in Guernsey County that are currently waiting on first production, as well as two stratigraphic vertical test wells to collect engineering and geologic data to test the productivity of the acreage. The horizontal wells have a vertical depth range of approximately 7,000 feet, with an average lateral length of 4,000 feet. +• +Marcellus Shale, West Virginia. Through our joint venture, PDCM, we have over 236,000 net acres in the Appalachian Basin, with approximately 152,000 acres prospective for the Marcellus Shale, the majority of which is in northern West Virginia. PDCM is primarily focused on horizontal drilling and has approximately 600 Marcellus Shale gross drilling locations on the West Virginia acreage. These wells have a vertical depth range from approximately 7,000 to 8,000 feet, with lateral lengths ranging from 4,000 to 6,000 feet. +In addition to our ownership interest in the wells held by PDCM, we own an interest in approximately 236 gross (77.9 net) natural gas and crude oil wells in West Virginia and Pennsylvania. +Properties +Productive Wells +The following table presents our productive wells : +Productive Wells +As of December 31, 2012 +Natural Gas +Crude Oil +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Western +Wattenberg Field +2,523 +2,181.2 +91 +71.8 +2,614 +2,253.0 +Other +1,057 +800.7 +— +— +1,057 +800.7 +Total Western +3,580 +2,981.9 +91 +71.8 +3,671 +3,053.7 +Eastern +Appalachian Basin +3,565 +1,654.5 +6 +3.7 +3,571 +1,658.2 +Total Eastern +3,565 +1,654.5 +6 +3.7 +3,571 +1,658.2 +Total productive wells +7,145 +4,636.4 +97 +75.5 +7,242 +4,711.9 +8 +Proved Reserves +Our proved reserves are sensitive to future natural gas, NGLs and crude oil sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located onshore in the U.S. Our reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff regulations, interpretations and guidance. As of December 31, 2012, all of our proved reserves, including the reserves of all subsidiaries consolidated for the purposes of our financial statements, have been estimated by independent petroleum engineers. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data, as well as production performance data. The process includes a review of applicable working and net revenue interests and cost and performance data. The internal team compiles the reviewed data and forwards the data to an independent engineering firm engaged to estimate our reserves. +Our reserve estimates as of December 31, 2012 were based on a reserve report prepared by Ryder Scott. When preparing our reserve estimates, Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties and sales of production. +Ryder Scott prepares an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined by acceptable industry methods and to a level of detail we deem appropriate. Ryder Scott's final estimated reserve report is reviewed and approved by our engineering staff and management. +The professional qualifications of the internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates meet the standards of Reserves Estimator, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This employee holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 35 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado. +The SEC's reserve rules expanded the technologies that a registrant may use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. +We used a combination of production and pressure performance, wireline wellbore measurements, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserve estimates, including the material additions to the 2012 reserve estimates. +Reserve estimates involve judgments and, therefore, cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the unaudited Supplemental Information - Natural Gas and Crude Oil Information provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves: +As of December 31, +2012 (5) +2011 (4)(5) +2010 (4)(5) +Proved reserves +Natural gas (MMcf) +604,038 +672,145 +657,306 +Crude oil and condensate (MBbls) (1) +59,310 +37,636 +23,236 +NGLs (MBbls) (1) +32,827 +19,588 +10,649 +Total proved reserves (MMcfe) +1,156,860 +1,015,489 +860,616 +Proved developed reserves (MMcfe) (2) +490,515 +471,347 +301,141 +Estimated future net cash flows (in millions) +$ +2,756 +$ +2,290 +$ +1,315 +PV-10% ( in millions ) (3) +$ +1,709 +$ +1,350 +$ +693 +Standardized measure (in millions) +$ +1,168 +$ +941 +$ +488 +9 +___________ +(1) +Approximately 49% of the increase in crude oil and condensate and 38% of the increase in NGLs from December 31, 2011 to December 31, 2012 is due to the addition of horizontal Niobrara and Codell proved developed and undeveloped reserves in the Wattenberg Field. +(2) +Approximately 73% of the increase in proved developed reserves from December 31, 2010 to December 31, 2011 was due to the reclassification of our estimated Wattenberg refracture reserves from PUDs to proved developed as a result of the greater cost differential between the cost of a refracture versus the cost of drilling a new well. +(3) +PV-10% is a non-U.S. GAAP financial measure. This non-U.S. GAAP measures is not a measure of financial or operating performance under U.S. GAAP and it is not intended to represent the current market value of our estimated reserves. PV-10% should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10% and a reconciliation of our PV-10% value to the standardized measure. +(4) +Includes estimated reserve data related to our Permian assets, which were classified as held for sale as of December 31, 2011. On February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +The following table sets forth information regarding estimated proved reserves for our Permian assets: +As of December 31, +2011 +2010 +Proved reserves +Natural gas (MMcf) +6,242 +4,979 +Crude oil and condensate (MBbls) +7,825 +3,331 +NGLs (MBbls) +1,971 +1,190 +Total proved reserves (MMcfe) +65,018 +32,105 +Proved developed reserves (MMcfe) +15,940 +11,416 +Estimated future net cash flows (in millions) +$ +348 +$ +129 +(5) +Includes estimated reserve data related to our Piceance and NECO assets, which are to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. +The following table sets forth information regarding estimated proved reserves for our Piceance and NECO assets: +As of December 31, +2012 +2011 +2010 +Proved reserves +Natural gas (MMcf) +83,656 +354,080 +454,886 +Crude oil and condensate (MBbls) +148 +441 +548 +NGLs (MBbls) +— +— +— +Total proved reserves (MMcfe) +84,544 +356,726 +458,174 +Proved developed reserves (MMcfe) +84,544 +141,802 +142,949 +Estimated future net cash flows (in millions) +$ +43 +$ +32 +$ +52 +10 +As of December 31, 2012 +Operating Region/Area +Natural Gas +(MMcf) +NGLs +(MBbls) +Crude Oil and Condensate (MBbls) +Natural Gas +Equivalent +(MMcfe) +Percent +Proved developed +Western +Wattenberg Field +158,192 +14,353 +20,226 +365,666 +74 +% +Piceance Basin +65,609 +— +148 +66,497 +14 +% +Other +18,047 +— +— +18,047 +4 +% +Total Western +241,848 +14,353 +20,374 +450,210 +92 +% +Eastern +Appalachian Basin +40,077 +— +38 +40,305 +8 +% +Total Eastern +40,077 +— +38 +40,305 +8 +% +Total proved developed +281,925 +14,353 +20,412 +490,515 +100 +% +Proved undeveloped +Western +Wattenberg Field +183,618 +18,474 +38,898 +527,850 +79 +% +Total Western +183,618 +18,474 +38,898 +527,850 +79 +% +Eastern +Appalachian Basin +138,495 +— +— +138,495 +21 +% +Total Eastern +138,495 +— +— +138,495 +21 +% +Total proved undeveloped +322,113 +18,474 +38,898 +666,345 +100 +% +Proved reserves +Western +Wattenberg Field +341,810 +32,827 +59,124 +893,516 +77 +% +Piceance Basin +65,609 +— +148 +66,497 +6 +% +Other +18,047 +— +— +18,047 +2 +% +Total Western +425,466 +32,827 +59,272 +978,060 +85 +% +Eastern +Appalachian Basin +178,572 +— +38 +178,800 +15 +% +Total Eastern +178,572 +— +38 +178,800 +15 +% +Total proved reserves +604,038 +32,827 +59,310 +1,156,860 +100 +% +11 +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage : +As of December 31, 2012 +Developed +Undeveloped (1) +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Western +Wattenberg Field +92,300 +81,700 +33,100 +23,300 +125,400 +105,000 +Piceance Basin +3,100 +3,100 +4,900 +4,900 +8,000 +8,000 +NECO +23,600 +19,600 +64,600 +54,600 +88,200 +74,200 +Other +— +— +21,800 +17,700 +21,800 +17,700 +Total Western +119,000 +104,400 +124,400 +100,500 +243,400 +204,900 +Eastern +Appalachian Basin, other +— +263,900 +107,300 +32,000 +17,950 +295,900 +125,250 +Utica Shale +800 +400 +48,200 +45,300 +49,000 +45,700 +Total Eastern +264,700 +107,700 +80,200 +63,250 +344,900 +170,950 +Total acreage +383,700 +212,100 +204,600 +163,750 +588,300 +375,850 +__________ +(1) +With the exception of our Eastern Operating Region properties prospective for the Utica Shale, substantially all of our undeveloped acreage is related to leaseholds that are held by production. Approximately 10% of our undeveloped leaseholds expire during 2013, none of which is material to any one specific area. +Drilling Activity +The following table presents information regarding the number of wells drilled or participated in and the number of wells for which refractures and/or recompletions were performed: +Drilling Activity +Year Ended December 31, +2012 +2011 +2010 +Operating Region +Gross +Net +Gross +Net +Gross +Net +Western (1) +57 +39.0 +186 +139.6 +204 +164.9 +Eastern +6 +4.0 +9 +5.2 +9 +5.2 +Total wells drilled +63 +43.0 +195 +144.8 +213 +170.1 +Refractures and Recompletions (2) +85 +79.9 +192 +177.6 +46 +33.7 +__________ +(1) +Includes drilling activity in the Permian Basin. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +(2) +83 of the refractures and recompletions in 2012 occurred in the Wattenberg Field. +12 +The following tables set forth our developmental and exploratory well drilling activity. There is no correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded , turned-in-line and producing during the period. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection during the period. +Net Development Well Drilling Activity +Year Ended December 31, +2012 +2011 +2010 +Operating Region/Area +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Western +Wattenberg Field +31.3 +7.7 +(2) +— +86.5 +13.1 +— +106.9 +26.5 +— +Piceance Basin +— +— +— +14.0 +3.0 +— +18.0 +7.0 +— +Permian Basin (1) +— +— +— +14.5 +5.5 +2.0 +— +5.0 +— +Other +— +— +— +— +— +— +0.5 +— +— +Total Western +31.3 +7.7 +— +115.0 +21.6 +2.0 +125.4 +38.5 +— +Eastern +Appalachian Basin +1.5 +— +— +0.9 +2.0 +— +0.6 +1.1 +— +Total Eastern +1.5 +— +— +0.9 +2.0 +— +0.6 +1.1 +— +Total net development wells +32.8 +7.7 +— +115.9 +23.6 +2.0 +126.0 +39.6 +— +__________ +(1) +As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +(2) +On a gross basis, wells in-process as of December 31, 2012 consisted of 10 wells in the Wattenberg Field. +Net Exploratory Well Drilling Activity +Year Ended December 31, +2012 +2011 +2010 +Operating Region/Area +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Western +Wattenberg Field +— +— +— +— +— +— +— +1.0 +— +Other +— +— +— +— +1.0 +— +— +— +— +Total Western +— +— +— +— +1.0 +— +— +1.0 +— +Eastern +Appalachian Basin +— +1.5 +1.0 +— +2.3 +— +2.8 +0.7 +— +Total Eastern +— +1.5 +1.0 +— +2.3 +— +2.8 +0.7 +— +Total net exploratory wells +— +1.5 +1.0 +— +3.3 +— +2.8 +1.7 +— +Title to Properties +We believe that we hold good and defensible leasehold title to our natural gas and crude oil properties, in accordance with standards generally accepted in the industry. As is customary in the industry, a preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty , overriding royalty and other outstanding interests customary in the industry. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under natural gas and crude oil leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our natural gas and crude oil properties, excluding properties held by PDCM and our share of the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. Substantially all of our Eastern Operating Region properties, excluding our Ohio properties, have been pledged as security for PDCM's credit facility. See Note 8, Long-Term Debt , to our consolidated financial statements included elsewhere in this report. +13 +Facilities +We lease 41,710 square feet of office space in Denver, Colorado, which serves as our corporate offices, through December 2015. We own a 32,000 square feet administrative office building located in Bridgeport, West Virginia, where we also lease approximately 18,600 square feet of office space in a second building through October 2014. +We own or lease field operating facilities in the following locations: +• +Colorado: Evans, Parachute and Wray +• +Pennsylvania: Indiana and Mahaffey +• +West Virginia: Bridgeport, Buckhannon and Glenville +• +Ohio: Marietta +Governmental Regulation +While the prices of natural gas and crude oil are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for natural gas and crude oil production depends on several factors that are beyond our control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas and crude oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and oppressive control, reduce environmental and health risks from the development and transportation of natural gas and crude oil, prevent misuse of natural gas and crude oil and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., governments own a large percentage of the land and control the right to develop natural gas and crude oil. Government leases may be subject to additional regulations and controls not common to private leases. We believe that we are in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion on the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental directives to which our operations may be subject. +Regulation of Natural Gas and Crude Oil Exploration and Production . Our exploration and production business is subject to various federal, state and local laws and regulations on the taxation of natural gas and crude oil, the development, production and marketing of natural gas and crude oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +well locations; +• +drilling and casing methods; +• +surface use and restoration of well properties; +• +well plugging and abandoning; +• +fluid disposal; and +• +air emissions. +In addition, our drilling activities involve hydraulic fracturing , which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors . +Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. State laws may establish maximum rates of production from natural gas and crude oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. State or federal leases often include additional regulations and conditions. The effect of these regulations may limit the amount of natural gas and crude oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and crude oil wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Regulation of Sales and Transportation of Natural Gas . We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the +14 +extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through FERC's rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure and related income taxes; and +• +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. Competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures and the courts. The industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and restrictive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken restricting drilling or imposing environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements. +Hydraulic fracturing is commonly used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations. We routinely apply fracturing in our natural gas and crude oil production programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA"), and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. +Certain states in which we operate, including Colorado, Pennsylvania and Ohio, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, transparency and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In December 2011, Colorado adopted a fracturing chemical disclosure rule, wherein all chemicals used in the hydraulic fracturing of a well must be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The new rules also require operators seeking new location approvals to provide certain disclosures regarding fracturing to surface owners and adjacent property owners within 500 feet of a new well. In December 2012 and February 2013, Colorado finalized a baseline groundwater sampling rule and a new rule governing setback distances of oil and gas wells located near population centers. See further discussion in Item 1A, Risk Factors . +In December 2011, West Virginia enacted the Natural Gas Horizontal Well Control Act and amendments to existing laws that together establish a comprehensive, detailed system for permitting and regulation of horizontal natural gas wells. The new law applies to most proposed new natural gas wells. The law imposes far more detailed permitting and regulatory requirements than prior law, and requires further study and authorizes potential rulemaking by the West Virginia Department of Environmental Protection ("DEP"). Among the new regulatory requirements are: detailed surface owner compensation requirements; performance standards applicable to disposal of drilling cuttings and associated drilling mud, protection of quantity and quality of surface and groundwater systems; advance designation of water withdrawal locations to the DEP and recordkeeping and reporting for all flowback and produced water; and restrictions on well locations. In early 2012, officials of the Ohio Department +15 +of Natural Resources imposed a moratorium on injection drilling of wastewater from fracturing operations within a five-mile radius of a well that was suspected as contributing to the cause of earthquakes in the area. Regulation was also enacted requiring the disclosure of chemicals used in hydraulic fracturing and any chemicals used when drilling through a drinking water zone. +The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with final results expected by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. The U.S. Department of the Interior is conducting a rule making, likely to result in new disclosure requirements and other mandates for hydraulic fracturing on federal lands. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. +In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements, and conduct air quality studies to identify potential public health impacts. For instance, the City of Fort Collins, Colorado, adopted on February 19, 2013 a ban on drilling and fracturing of new wells within city limits. If new laws or regulations that significantly restrict hydraulic fracturing or well locations are adopted at the state and local level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves. +We currently own or lease numerous properties that for many years have been used for the exploration and production of natural gas and crude oil. Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may have operated prior to the enactment of applicable laws now governing these areas, or may not have utilized similar practices and techniques and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of natural gas and crude oil wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and groundwater contamination) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of natural gas and crude oil wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have been developing regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. The New Source Performance Standards regarding oil and gas operations ("NSPS 0000") introduced by the EPA in 2011 became effective in 2012, adding administrative and operational costs. Colorado partially adopted the requirements of NSPS 0000 in 2012 and will consider full adoption in 2013. +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement additional SPCC measures relating to the possible discharge of crude oil into surface waters. The +16 +Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil enhances our risks related to soil and water contamination. +Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2013 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies , to our consolidated financial statements included elsewhere in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as gas leaks, ruptures and discharges of natural gas and crude oil. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver gas. +Competition and Technological Changes +We believe that our exploration, drilling and production capabilities and the experience of our management and professional staff generally enable us to compete effectively. We encounter competition from numerous other natural gas and crude oil companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing natural gas and crude oil and obtaining desirable natural gas and crude oil leases on producing properties. Many of these competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to explore for natural gas and crude oil prospects and to acquire additional properties in the future depends upon our ability to conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. We also face intense competition in the marketing of natural gas from competitors including other producers, as well as marketing companies. Also, international developments and the possible improved economics of domestic natural gas exploration may influence other companies to increase their domestic natural gas and crude oil exploration. Furthermore, competition among companies for favorable prospects can be expected to continue and it is anticipated that the cost of acquiring properties will increase in the future. +Recently, certain regions experienced strong demand for drilling services and supplies, which resulted in increasing costs. Our Wattenberg Field and Eastern Operating Region experienced intense competition for drilling and pumping services. Factors affecting competition in the industry include price, location of drilling, availability of drilling prospects and drilling rigs, fracturing services, pipeline capacity, quality of production and volumes produced. We believe that we can compete effectively in the industry in each of the areas where we have operations. Nevertheless, our business, financial condition and results of operations could be materially adversely affected by competition. We also compete with other natural gas and crude oil companies, as well as companies in other industries, for the capital we need to conduct our operations. Should economic conditions deteriorate and financing become more expensive and difficult to obtain, we may not have adequate capital to execute our business plan and we may be forced to curtail our drilling and acquisition activities. +The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be materially adversely affected. +Employees +As of December 31, 2012, we had 421 employees. Our employees are not covered by a collective bargaining agreement. We consider relations with our employees to be good. +17 +Our engineers, supervisors and well tenders are responsible for the day-to-day operation of wells and some pipeline systems. Much of the work associated with drilling, completing and connecting wells, including fracturing, logging and pipeline construction, is performed under our direction by subcontractors specializing in these activities as is common in the industry. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle-blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not hereby incorporated by reference. +18 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Natural gas, crude oil and NGL prices fluctuate and a decline in these prices can significantly affect the value of our assets and our financial results and impede our growth. +Our revenue, profitability and cash flows depend in large part upon the prices and demand for natural gas, NGLs and crude oil. The markets for these commodities can be volatile, and significant drops in prices can negatively affect our financial results and impede our growth. For example, in much of 2012, natural gas prices were too low to economically justify drilling operations in several areas, and the outlook for natural gas prices remains weak due largely to increased supply and large inventories in storage. Similarly, NGL prices have decreased in some recent periods due to increased development activities in a variety of basins across the U.S. Changes in commodity prices have a significant effect on our cash flows and on the value and quantity of our reserves, which can in turn reduce the borrowing base under our revolving credit facility. Prices for natural gas, NGLs and crude oil may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including national and international economic and political factors and federal and state legislation. For example, any substantial reduction in the growth rate of China could affect global oil prices significantly, and continued weakness in the overall economic environment could adversely affect all commodity prices. In addition to factors affecting the price of oil, NGLs and natural gas generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. Pricing can be influenced by, among other things, local or regional supply and demand factors (such as refinery or pipeline capacity issues, trade restrictions and governmental regulations) and the terms of our sales contracts. +Lower commodity prices may not only reduce our revenues, but also may reduce the amount of natural gas, NGLs and crude oil that we can produce economically. As a result, we may have to make substantial downward adjustments to our estimated proved reserves if prices decline or remain at depressed levels for extended periods. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write-down operating assets to fair value, as a non-cash charge to earnings. We assess impairment of capitalized costs of proved properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products may be sold. For example, in 2011, we recorded an impairment charge related to our NECO proved natural gas and crude oil properties of $22.5 million and in 2012 we recorded an impairment charge of $161.2 million related to our Piceance Basin proved oil and natural gas properties. We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations. +The marketability of our production is dependent upon limited transportation and processing facilities over which we may have no control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting gathering and transportation systems, could hinder our access to natural gas, crude oil and NGL markets or delay production and thereby adversely affect our profitability. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate gathering, processing and transportation facilities are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, due to increased drilling activities by third parties and unusually hot temperatures in Colorado in the second half of 2012, the principal third-party provider we use in the Wattenberg area for these facilities and services experienced high line pressure, and the resulting capacity constraints impacted the productivity of some of our older wells and limited the incremental production impact of our newer horizontal wells. As a result, we have seen an impact on our production and a related decrease in revenue from the impacted wells. Thus, our profitability has been adversely affected, and will continue to be affected until available capacity increases or alternative arrangements are available. Additional pipelines and facilities are being planned for the area but are not expected to be completed until the latter part of 2013. Capacity constraints affecting natural gas production also impact our ability to produce the associated NGLs. We may face similar risks in other areas, including our Utica operating area, as gathering/processing infrastructure is currently in the development phase. We are also dependent on third party pipeline infrastructure to deliver our natural gas production to market in the Marcellus and Piceance Basin areas. +Federal, state and local legislative and regulatory initiatives and litigation relating to hydraulic fracturing could result in increased costs and additional drilling and operating restrictions or delays in the production of natural gas, NGLs and crude oil, including from the development of shale plays. A decline in the drilling of new wells and related servicing activities caused by these initiatives and litigation could adversely affect our financial condition, results of operations and cash flows. +Most of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the oil and natural gas industry in fracturing fluids under the Safe Drinking Water Act (“SDWA”), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. The Chairman of the House Energy and Commerce Committee has initiated an investigation +19 +of the potential impacts of hydraulic fracturing, which has involved seeking information about fracturing activities and chemicals from certain companies in the oil and natural gas sector. The Environmental Protection Agency (the “EPA”) has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue which have been well publicized and well attended. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The EPA issued an initial report about the study in December 2012. The initial report described the focus of the continuing study but did not include any data concerning EPA's efforts to date, nor did it draw any conclusions about the safety of hydraulic fracturing. Final results, including data and conclusions, are expected in 2014. +The EPA has also begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. EPA also has finalized major new Clean Air Act (“CAA”) standards (New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPs) applicable to hydraulically fractured natural gas wells. The standards will require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions from well completions as well as new controls applicable to a wide variety of storage tanks. While most key provisions in the new CAA standards are not effective until 2015, the rules associated with such standards are substantial and may increase future costs of our operations and will require us to make modifications to our operations and install new equipment. EPA has also issued and is in the process of finalizing permitting guidance for hydraulically fractured wells where diesel is used. It remains to be seen how broadly applicable the diesel guidance will be, but it has the potential to create duplicative requirements, further slow down the permitting process in certain areas, and increase the costs of operations. Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The U.S. Department of the Interior, through the Bureau of Land Management, is currently conducting a rulemaking that will require, among other things, disclosure of chemicals and more stringent well integrity measures associated with hydraulic fracturing operations on public land. +In addition, certain state governments, including the states of Colorado, Pennsylvania, Ohio, and West Virginia, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting, disclosure, wastewater disposal, baseline sampling, well construction and well location requirements on hydraulic fracturing operations or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. Some municipalities and local governments, including most recently the city of Fort Collins in Colorado, have adopted or are considering similar actions. In addition, lawsuits have been filed against unrelated third parties in Pennsylvania, New York, Arkansas and several other states alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to natural gas, crude oil and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, or litigation could also lead to operational delays or lead us to incur increased operating costs in the production of natural gas, NGLs and crude oil, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, and litigation initiatives cause a material decrease in the drilling of new wells and in related servicing activities, our profitability could be materially impacted. +Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased our costs to plan, design, drill, install, operate and abandon natural gas and crude oil wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. +In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat and protection of correlative rights by state governments. These regulations affect our operations, increase our costs of exploration and production and limit the quantity of natural gas, NGLs and crude oil that we can produce and market. A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from state and local authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore or develop our properties. +Additionally, the natural gas and crude oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. At the state level, for instance, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a new rule governing mandatory minimum spacing, or setbacks, between oil and gas wells and occupied buildings and other areas. Similarly, it is expected that the COGCC may undertake a rulemaking focused on wellbore integrity in 2013 that would increase requirements in this area. In addition to increasing costs of operation, these rules could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. The COGCC has also recently concluded a rulemaking that will require baseline sampling of certain +20 +ground and surface water in most areas of Colorado. These new sampling requirements could increase the costs of developing wells in certain locations. +Some local governmental bodies, for instance Longmont, Colorado, have adopted or are considering regulations regarding, among others things, land use, requiring the posting of bonds to secure restoration obligations and limiting hydraulic fracturing and other drilling activities, and these regulations may limit, delay or prohibit exploration and development activities or make those activities more expensive. Additionally, state and local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies may result in the imposition of additional regulatory requirements on oil and gas operations. +The BP crude oil spill in the Gulf of Mexico and generally heightened industry scrutiny has resulted and may result in new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. The EPA has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities, and conducted public meetings around the country on this issue which have been well publicized and well attended. This renewed focus could lead to additional federal, state and local laws and regulations affecting our drilling, fracturing and other operations. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Pennsylvania. This could adversely affect the existing operations in these states and the economic viability of future drilling. Additional laws, regulations or other changes could significantly reduce our future growth, increase our costs of operations and reduce our cash flows, in addition to undermining the demand for the natural gas, NGLs and crude oil we produce. +Our ability to produce natural gas and crude oil could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. +Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, Colorado and other western states have recently experienced a drought. As a result, future availability of water from certain sources used in the past may be limited. Moreover, the imposition of new environmental initiatives and conditions could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The federal Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated state waters. Permits or other approvals must be obtained to discharge pollutants to regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters has, and will continue to, complicate and increase the cost of obtaining such permits or other approvals. The CWA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations, and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into coastal waters. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. In October 2011, the EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the pretreatment rules will require coalbed methane and shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in 2013 for coalbed methane production and in 2014 for shale gas production. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There has been recent nationwide concern, particularly in Ohio, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. It is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. Finally, the EPA study noted above has focused and will continue to focus on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion of EPA's study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells or the disposal or recycling of water will increase our operating costs and may cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. In addition, our inability to meet our water supply needs to conduct our completion operations may impact our business, and any such future laws and regulations could negatively affect our financial condition and results of operations. +Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing properties and undeveloped properties have been an important part of our historical and recent growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, environmental, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our +21 +ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. +Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges. +A substantial part of our natural gas, NGLs and crude oil production is located in the Wattenberg Field, making it vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Our operations are focused primarily on the Wattenberg Field in our Western Operating Region, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas, NGLs and crude oil produced from the wells in the area, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. For example, the recent increase in activity in the Wattenberg Field has contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations, in particular the Niobrara, Codell and Marcellus formations, exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. +Our estimated natural gas and crude oil reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Natural gas, crude oil and NGL reserve engineering requires subjective estimates of underground accumulations of natural hydrocarbons and assumptions concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of natural gas, NGLs and crude oil reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of natural gas, NGLs and crude oil attributable to any particular group of properties; +• +future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of the future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to utilize under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Further, reserve estimates are based on the volumes of natural gas, NGLs and crude oil that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of natural gas, NGLs and crude oil recovered would be different than the reserve estimates since they would not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves and are less likely to be recovered. +22 +At December 31, 2012, approximately 57.6% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $1.6 billion during the five years ending in 2017. You should be aware that the estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to downgrade any PUDs that are not developed within this five-year time frame to probable or possible. +The present value of our estimated future net cash flows from proved reserves is not necessarily the same as the current market value of our estimated natural gas and crude oil reserves. The estimated discounted future net cash flows from proved reserves were based on the prior 12-month average natural gas and crude oil index prices. However, factors such as actual prices we receive for natural gas and crude oil and hedging instruments, the amount and timing of actual production, amount and timing of future development costs, supply of and demand for natural gas, NGLs and crude oil, and changes in governmental regulations or taxation also affect our actual future net cash flows from our natural gas and crude oil properties. +The timing of both our production and incurrence of expenses in connection with the development and production of natural gas, crude oil and NGL properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. +Producing natural gas, crude oil and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we estimated. The rate can change due to other circumstances as well. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We may not be able to consummate additional prospective acquisitions of our drilling partnerships, which could adversely affect our business operations. +We have previously disclosed our intention to pursue, beginning in the fall of 2010 and extending through 2013, the acquisition of the limited partnership units held by non-affiliated investor partners in the drilling partnerships that we have sponsored. We have not budgeted for the acquisition of the largest remaining partnership in 2013. We also may be unable to make additional acquisitions of such affiliated drilling partnerships since consummation of any such acquisitions may be subject to the same procedural processes that were utilized in connection with our previously completed acquisitions of public drilling partnerships. Such procedural hurdles previously included, and may in the future include, among others: +• +negotiation and execution of a merger agreement with a special committee, comprised entirely of non-employee directors, of our board of directors; +• +clearance from the SEC upon completion by each of the partnerships of their SEC proxy disclosure review process before the partnerships can request approval of the merger transactions from their non-affiliated investors; and +• +approval by the holders of a majority of the limited partnership units held by the non-affiliated investors of each respective partnership. +In addition, certain former non-affiliated investor partners have initiated litigation concerning our acquisition of twelve limited partnerships in 2010 and 2011. Litigation challenges to further acquisitions are also possible. In addition, we will have incurred, and will remain liable for, transaction costs, including legal, accounting, financial advisory and other costs relating to any prospective acquisitions, including the costs of the financial and legal consultants to the special committee of our board of directors, whether or not the acquisitions are consummated. We currently do not have any drilling partnership acquisitions pending or planned in 2013. The occurrence of any of the risks associated with these potential transactions individually or in combination could have an adverse effect on our business, financial condition or results of operations. +When drilling prospects, the wells we drill may not yield natural gas, NGLs or crude oil in commercially viable quantities. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether natural gas, NGLs or crude oil will be present at all or in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. If a well is determined to be dry or uneconomic, which can occur even though it contains some natural gas, NGLs or crude oil, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells +23 +that are completed and placed into production may not produce sufficient natural gas, NGLs and crude oil to be profitable. If we drill a dry hole or unprofitable well on current and future prospects, the profitability of our operations will decline and the value of our properties will likely be reduced. These risks are greater in developing areas such as the Utica Shale, where we are currently investing substantial capital. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing natural gas, NGLs and crude oil are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. Our drilling risk exposure may be increased as we have allocated most of our 2013 capital budget to drilling horizontal wells. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for natural gas and crude oil can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delivery delays of equipment and services; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during these activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or the governmental response to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. See Note 11, Commitments and Contingencies - Environmental , to our consolidated financial statements included elsewhere in this report. +Our business strategy focuses on production in our liquid-rich and high impact shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Historically, most of the wells we drilled were vertical wells. In 2012 and 2013, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells, including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore, and thus the risk of failure is greater than the risk involved in drilling vertical wells. Additionally, drilling horizontal wells is far costlier than drilling vertical wells. Consequently, because we are drilling far fewer total wells during 2013 as compared to many prior years, the risk of drilling a non-economic well will be relatively higher than if we were to drill a similar number of wells as we did in those prior years. Furthermore, because of the relatively higher cost in drilling horizontal wells, a completed well to be successful economically will need to have production that will cover the higher drilling costs. While we believe that we will be better served by our drilling horizontal wells, the risk component involved in such drilling will be increased, with the result that we might find it more difficult to achieve economic success in our horizontal drilling program. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed and could have a negative effect on our debt covenants. +Increasing finding and development costs may impair our profitability. +24 +In order to continue to grow and maintain our profitability, we must add new reserves that exceed our production over time at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most natural gas and crude oil basins in North America and the high level of activity in the industry, the cost of finding new reserves through exploration and development operations has been increasing in some basins. The acquisition market for properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude oil properties climbed in 2010 and 2011 and these values may continue to increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in crude oil finding and development costs continues, we will be exposed to an increased likelihood of a write-down in the carrying value of our crude oil properties in response to any future decrease in commodity prices and/or reduction in the profitability of our operations. +Depressed natural gas prices could result in significant impairment charges and significant downward revisions of proved natural gas reserves. +The domestic natural gas market remains weak. Low natural gas prices could result in significant impairment charges in the future. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management's estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward natural gas prices alone could result in a significant impairment for our properties that are sensitive to declines in natural gas prices. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved oil and natural gas properties and similar charges could occur in the future. In addition, low natural gas prices could result in significant downward revisions to our proved natural gas reserves. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of natural gas, crude oil and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of natural gas, NGLs and crude oil we are able to produce from existing wells; +• +the prices at which natural gas, NGLs and crude oil are sold; +• +the costs to produce natural gas, NGLs and crude oil; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources would increase. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. There can be no assurance as to the availability or terms of any additional financing. Our inability to obtain additional financing, or sufficient financing on favorable terms, would adversely affect our financial condition and profitability. We intend to fund a portion of our 2013 capital expenditures with proceeds from our sale of Piceance Basin and certain other properties to Caerus. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. As of December 31, 2012 , we had $676.6 million in outstanding indebtedness and approximately $382.3 million available to be borrowed under our revolving credit facility, subject to limitation under our financial covenants. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend upon our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flows from operations, or that future borrowings will be available to us under our revolving credit facility or otherwise, in an amount sufficient to fund our liquidity needs. +25 +A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. +Our substantial indebtedness could adversely impact our business, results of operations and financial condition. +In addition to making it more difficult for us to satisfy our debt and other obligations, our substantial indebtedness could limit our ability to respond to changes in the markets in which we operate and otherwise limit our activities. For example, our indebtedness, and the terms of agreements governing that indebtedness, could: +• +require us to dedicate a substantial portion of our cash flows from operations to service our existing debt obligations, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate; +• +increase our vulnerability to economic downturns and impair our ability to withstand sustained declines in commodity prices; +• +subject us to covenants that limit our ability to fund future working capital, capital expenditures, exploration costs and other general corporate requirements; +• +prevent us from borrowing additional funds for operational or strategic purposes (including to fund future acquisitions), disposing of assets or paying cash dividends; +• +limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; +• +require us to devote a substantial portion of our cash flows from operations to payments on our indebtedness, thereby reducing the availability of our cash flows to fund exploration efforts, working capital, capital expenditures and other general corporate purposes; and +• +place us at a competitive disadvantage relative to our competitors that have less debt outstanding. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +The indenture governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries' ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility will mature on November 5, 2015, and is secured by all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable. +26 +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas, crude oil and NGL properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our revolving credit facility to avoid being in default. If we breach our covenants under our revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face. +Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate. +Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in our Western Operating Region. In certain areas, including parts of the Piceance Basin in Colorado, drilling and other activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during parts of 2012 adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 89% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator's timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator's breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. +27 +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or could limit our potential gains from increases in prices. +We use derivatives for a portion of the production from our own wells, our partnerships and for natural gas purchases and sales by our marketing subsidiary to achieve a more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counterparty to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. +In addition, derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity. They may also require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our natural gas, NGLs and crude oil sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce natural gas, NGLs and crude oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local +28 +and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability. +Certain federal income tax deductions currently available with respect to natural gas and crude oil and exploration and development may be eliminated as a result of future legislation. +In February 2012, U.S. President Barack Obama and his administration released its budget proposals for the fiscal year 2013, which included numerous proposed tax changes. The proposed budget, if enacted, would eliminate certain key U.S. federal income tax preferences currently available with respect to natural gas and crude oil exploration and production. Similar changes have been in previous budget proposals from the Obama administration but were not adopted into law. The changes in the current budget proposal related to oil and gas drilling and production include, but are not limited to (i) the repeal of the percentage depletion allowance for natural gas and crude oil properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. +New derivatives legislation and regulation could adversely affect our ability to hedge natural gas and crude oil prices and increase our costs and adversely affect our profitability. +In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may decrease our ability to enter into hedging transactions, and this would expose us to additional risks related to commodity price volatility; commodity price decreases would then have an immediate adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties will be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +• +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, NGLs and crude oil that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (the “CAA”). In June 2010, the EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the CAA's Prevention of Significant Deterioration (“PSD”), and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according to “best available control technology,” ("BACT") standards. In its permitting guidance for greenhouse gases, issued on November 10, 2010, the EPA recommended options for BACT, which include improved energy efficiency, among others. EPA has recently issued a final rule retaining the current “tailored” permitting thresholds, opting not to extend greenhouse gas permitting requirements to smaller stationary sources at this time. The EPA, however, intends to revisit these thresholds again by 2016. In addition, on June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency , No. 09-1322, upholding EPA's greenhouse gas-related rules, including the “Tailoring Rule,” against challenges from various state and industry group petitioners. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce and monitor emissions of greenhouse gases associated with our operations and also adversely affect demand for the natural gas and crude oil that we produce. +In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the U.S. on an annual basis, beginning in 2011 for emissions occurring in 2010. On November 8, 2010, the EPA finalized rules to expand its greenhouse gas reporting rule to include onshore natural gas and crude oil production, processing, transmission, storage and distribution facilities. We are required to report our greenhouse gas emissions on an annual basis, beginning in 2012 for emissions occurring in 2011. +In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (“ACESA”), which would establish an economy-wide cap on emissions of greenhouse gases in the U.S. and would require most sources of greenhouse gas +29 +emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. By steadily reducing the number of available allowances over time, ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020, increasing up to an 83 percent reduction of such emissions by 2050. The ACESA was not passed by the U.S. Senate. However, many states and regions have taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Recently, increased focus has been directed to methane emissions, including a lawsuit by several Northeastern states that would require the EPA to more stringently regulate methane emissions from the oil and gas sector. The passage of legislation, or other initiatives, that limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our operations, and it could also adversely affect demand for the natural gas and crude oil that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damage to our facilities from powerful winds or increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +The cost of defending any suits brought against us with respect to our royalty payment practices, and any judgments resulting from such suits, could have an adverse effect on our results of operations and financial condition. +In recent years, litigation has commenced against us and other companies in our industry regarding royalty practices and payments in jurisdictions where we conduct business. We intend to defend ourselves vigorously in these cases. The costs of defending these suits can be significant, even when we ultimately succeed in having them dismissed. These costs would be reflected in terms of dollar outlay, as well as the amount of time, attention and other resources that our management would have to appropriate to the defense. A judgment in favor of a plaintiff in a suit of this type could have a material adverse effect on our financial condition and profitability. +We may not be able to identify and acquire enough attractive prospects on a timely basis to meet our development needs, which could limit our future development opportunities and adversely affect our profitability. +Our geologists have identified a number of potential drilling locations on our existing acreage. These drilling locations must be replaced as they are drilled for us to continue to grow our reserves and production. Our ability to identify and acquire new drilling locations depends on a number of factors, including the availability of capital, regulatory approvals, commodity prices, competition, costs, availability of drilling rigs, drilling results and the ability of our geologists to successfully identify potentially successful new areas to develop. All of these factors are subject to numerous uncertainties. Because of these uncertainties, our profitability and growth opportunities may be limited by the timely availability of new drilling locations. As a result, our operations and profitability could be adversely affected. +PDCM is dependent upon our equity partner and poses exit-related risks for us. +The board of managers of the joint venture consists of three representatives appointed by us and three representatives appointed by our equity partner Lime Rock Partners, LP, each with equal voting power. The joint venture agreement generally requires the affirmative vote of a majority of the members of the board to approve an action, and we and Lime Rock may not always agree on the best course of action for the joint venture. If such a disagreement were to occur, we would not be able to cause the joint venture to take action that we believed to be in the best interests of the joint venture. Consequently, our best interests may not be advanced and our investment in the joint venture could be adversely affected. If there is a disagreement about a development plan and budget for the joint venture, Lime Rock is entitled to unilaterally suspend substantially all of the operations of the joint venture, which could have a material adverse impact on the results of operations of the joint venture and our investment. Such a suspension could last for up to two years, at which point either party could elect to dissolve the joint venture or to sell its ownership interests to a third party. Lime Rock is entitled to a preference with respect to liquidating distributions and proceeds from significant sales of ownership interests up to the amount of its contributed capital, which would diminish our returns if the value of the joint venture had declined at the time of the liquidation or sale. +After a “restricted period” which generally lasts for the four years following the closing of the joint venture, Lime Rock can seek to sell its interest in the joint venture to a third party, subject to rights of first offer and refusal in favor of us. If we do not exercise those rights in a sale involving all of Lime Rock's ownership interests, Lime Rock can exercise “drag-along” rights and compel us to sell all of our interests in the proposed transaction. Accordingly, if we possessed insufficient funds and were unable to obtain financing necessary to purchase Lime Rock's interest under the rights of first offer and refusal, Lime Rock might sell its interests in the joint venture to a third party with whom we might have a difficult time dealing and in managing the joint venture or we may be required to sell our interest in the joint venture at a time when we may not wish to do so. Under these circumstances, our investment in the joint venture could be adversely affected. +30 +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. +Our articles of incorporation, bylaws, stockholders rights plan and Nevada law contain provisions that may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt, which may adversely affect the market price of our common stock. +Our articles of incorporation authorize our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. We previously adopted a stockholders rights plan that will dilute the stock ownership of certain acquirers of our common stock upon the occurrence of certain events. In addition, some provisions of our articles of incorporation, bylaws and Nevada law could make it more difficult for a third party to acquire control of us, including: +• +the organization of our board of directors as a classified board, which allows no more than one-third of our directors to be elected each year; +• +limitations on the ability of our shareholders to call special meetings; and +• +certain antitakeover provisions of the Nevada private corporations statute. +Because we have no plans to pay dividends on our common stock, stockholders must look solely to stock appreciation for a return on their investment in us. +We have never declared or paid cash dividends on our common stock. We currently intend to retain all future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our revolving credit facility and the indenture governing our senior notes limit our ability to pay cash dividends on our common stock. Any future dividends may also be restricted by any other debt agreements which we may enter into from time to time. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +31 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock for each of the periods presented: +Price Range +High +Low +January 1 - March 31, 2011 +$ +49.60 +$ +39.93 +April 1 - June 30, 2011 +48.51 +28.67 +July 1 - September 30, 2011 +39.50 +19.35 +October 1 - December 31, 2011 +37.77 +15.08 +January 1 - March 31, 2012 +40.26 +28.61 +April 1 - June 30, 2012 +37.63 +19.33 +July 1 - September 30, 2012 +34.25 +23.27 +October 1 - December 31, 2012 +36.55 +25.76 +As of February 8, 2013 , we had approximately 726 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility and the indenture governing our 2022 Senior Notes and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt , to our consolidated financial statements included elsewhere in this report. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2012 : +Period +Total Number +of Shares +Purchased (1) +Average Price +Paid per Share +Total Number +of Shares +Purchased as +Part of Publicly +Announced Plans +or Programs +Maximum Number +of Shares that May +Yet Be Purchased +Under the Plans +or Programs +October 1 - 31, 2012 +709 +$ +31.93 +— +— +November 1 - 30, 2012 +9,786 +31.53 +— +— +December 1 - 31, 2012 +254 +33.25 +— +— +Total fourth quarter purchases +10,749 +31.59 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +32 +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2012 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 254 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2007 and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +33 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended December 31, +2012 +2011 +2010 +2009 +2008 +(in millions, except per share data and as noted) +Statement of Operations: +Natural gas, NGLs and crude oil sales +$ +270.3 +$ +276.6 +$ +205.0 +$ +171.2 +$ +304.9 +Commodity price risk management gain (loss), net +32.3 +46.1 +59.9 +(10.1 +) +127.8 +Total revenues +356.1 +396.0 +343.0 +230.9 +572.5 +Income (loss) from continuing operations +(144.8 +) +3.1 +6.0 +(80.1 +) +105.8 +Earnings per share from continuing operations +Basic +$ +(5.23 +) +$ +0.13 +$ +0.33 +$ +(4.76 +) +$ +7.19 +Diluted +(5.23 +) +0.13 +0.32 +(4.76 +) +7.13 +Statement of Cash Flows: +Net cash from: +Operating activities +$ +174.7 +$ +166.8 +$ +151.8 +$ +143.9 +$ +139.1 +Investing activities +(451.9 +) +(456.4 +) +(300.9 +) +(142.3 +) +(323.0 +) +Financing activities +271.4 +243.4 +171.5 +(20.6 +) +150.1 +Capital expenditures +347.7 +334.5 +162.7 +143.0 +323.2 +Acquisitions of natural gas and crude oil properties +312.2 +145.9 +158.1 +— +— +Balance Sheet: +Total assets +$ +1,826.8 +$ +1,698.0 +$ +1,389.0 +$ +1,250.3 +$ +1,402.7 +Working capital (deficit) +(31.4 +) +(22.0 +) +16.2 +32.9 +31.3 +Long-term debt +676.6 +532.2 +295.7 +280.7 +394.9 +Total equity +703.2 +664.1 +642.2 +538.6 +512.3 +Pricing and Lifting Costs Relating to Continuing Operations (per Mcfe): +Average sales price (excluding gains/losses on derivatives) +$ +5.45 +$ +6.15 +$ +5.63 +$ +4.19 +$ +8.37 +Average sales price (including realized gains/losses on derivatives) +6.44 +6.53 +6.89 +6.77 +8.62 +Average lifting cost (1) +0.85 +0.92 +1.05 +0.78 +1.04 +Production (Bcfe): +Production from continuing operations +49.6 +45.0 +37.0 +41.6 +36.9 +Production from discontinued operations +0.4 +2.5 +1.6 +1.7 +1.8 +Total production +50.0 +47.5 +38.6 +43.3 +38.7 +Total proved reserves (Bcfe) (2) +1,156.9 +1,015.5 +860.6 +717.3 +753.1 +______________ +(1) +Lifting costs represent lease operating expenses, excluding production taxes, on a per unit basis. +(2) +Includes total proved reserves related to our Permian Basin assets of 65.0 Bcfe and 32.1 Bcfe as of December 31, 2011 and 2010, respectively. As of December 31, 2011, our Permian assets were held for sale and, on February 28, 2012, the divestiture closed. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian assets. +34 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2012 Financial Overview +In 2012, our natural gas, NGLs and crude oil production from continuing operations averaged 135.6 MMcfe per day, an increase of approximately 10% compared to the prior year. The increase in production is primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field and the Merit Acquisition. Crude oil production from continuing operations increased 18.5% in 2012, while NGL production from continuing operations increased 17.0% . As a result, our liquids percentage of total production from continuing operations was 34.7% in 2012 compared 32.4% in 2011. Natural gas production increased 6.5% in 2012 compared to 2011. As discussed under "Operational Overview-Production" below, production growth in 2012 was adversely affected by high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure, primarily experienced during the second and third quarters, was the result of two primary factors: a series of operational issues experienced by the third-party midstream service provider facilities and abnormally warm weather. While natural gas production increased when compared to prior year, significant declines in the average price of natural gas during 2012 resulted in a decrease in natural gas sales, excluding hedges, of 28.9% year-over-year. The price of natural gas, however, rebounded significantly during the fourth quarter of 2012. During 2012, we recorded an impairment charge of $161.2 million related to our Piceance Basin proved oil and natural gas properties. While the significant decrease in natural gas prices from prior years has impacted our results of operations, we believe our derivative program was effective in providing a degree of price stability. Realized gains from derivative transactions increased considerably to $49.4 million in 2012, compared to $17.2 million in 2011, an addition of approximately $0.99 per Mcfe sold during 2012. +Available liquidity as of December 31, 2012 was $398.6 million , including $14.1 million through our joint venture PDCM, compared to $196.4 million, including $16.6 million related to PDCM, as of December 31, 2011. Available liquidity is comprised of cash, cash equivalents and funds available under our revolving credit facility. In May 2012, we completed a public offering of 6.5 million shares of our common stock for net proceeds of approximately $164.5 million, after deducting underwriting discounts and offering expenses. These funds were used to complete the Merit Acquisition noted below. In October 2012, we issued $500 million aggregate principal amount of our 2022 Senior Notes in a private placement. The net proceeds from the issuance of the notes of approximately $489 million were used to fund the redemption of our 2018 Senior Notes for a total redemption price of approximately $222 million, repay a portion of the amount outstanding under our revolving credit facility and for general corporate purposes. The early redemption of the 2018 Senior Notes resulted in a pre-tax loss on debt extinguishment of approximately $23.3 million. On October 31, 2012, we completed the semi-annual redetermination of our revolving credit facility's borrowing base. Our available borrowing base was reduced from $525 million to $450 million as a result of issuance of our 2022 Senior Notes. +Operational Overview +Acquisitions. We continued to make strides in 2012 toward our strategic goal of growing production while increasing our mix of crude oil and natural gas liquids. In June, we completed the Merit Acquisition for cash consideration of approximately $304.6 million , after certain post-closing adjustments. The acquired assets comprise approximately 29,800 net acres, after post-closing adjustments, located almost entirely in the core Wattenberg Field and with significant overlay with our existing acreage position. Ryder Scott prepared a reserve report with respect to the Merit Acquisition properties and estimated net proved reserves of 29.2 MMBoe (175 Bcfe) based on our development plan, using year-end 2011 SEC pricing and an effective date of April 1, 2012. Following the closing of the Merit Acquisition, our total position in the core Wattenberg Field was approximately 98,600 net acres. +Drilling Activities. During 2012, we continued to focus our operations primarily in the oil- and liquid-rich Wattenberg Field in Colorado and the emerging Utica Shale play in Ohio. We currently have two drilling rigs operating in the Wattenberg Field. We drilled 37 horizontal wells and one vertical well in the Wattenberg Field in 2012, of which 30 were completed and turned-in-line as of December 31, 2012 , and we participated in 19 non-operated drilling projects. We also executed 160 refracture and/or recompletion projects on 83 wells in the Wattenberg Field. The shift in the Wattenberg Field from drilling both vertical and horizontal wells to our current program of drilling horizontal wells has resulted in significantly fewer wells being drilled at a considerably higher cost per well and higher production and reserves per well. The remaining activity in our Western Operating Region in 2012 was the first quarter completion of our final three Piceance wells drilled in 2011. +In our Eastern Operating Region, we drilled and completed two horizontal Utica wells during the year. At December 31, 2012 , these wells are currently shut-in awaiting pipeline connections. We also drilled and completed one vertical Utica stratigraphic test well and completed one vertical Utica stratigraphic test well drilled in late 2011. In 2012, the costs related to the two vertical stratigraphic test wells were expensed at a cost of $12.2 million. We currently plan to continue to de-risk and develop our approximate 45,000 net acres without materially adding to our leasehold position. We estimate our total gross horizontal Utica Shale drilling inventory to be approximately 200 locations. In addition, PDCM drilled three horizontal Marcellus wells in 2012, all of which were completed and turned-in-line during the year. +Natural Gas and Crude Oil Properties Divestitures. In October 2011, we announced our intent to divest our Permian Basin assets to focus our efforts on our horizontal drilling programs. During the fourth quarter of 2011, we sold certain non-core Permian assets to unrelated +35 +third parties for a total of $13.2 million. On December 20, 2011, we executed a purchase and sale agreement with another unrelated third-party for the sale of our core Permian assets for a total price of $173.9 million, subject to customary post-closing adjustments. On February 28, 2012, the divestiture of the core Permian assets closed. Upon final post-closing adjustments on June 29, 2012, total proceeds received for the core Permian assets was $189.2 million, resulting in a pre-tax gain on sale of $19.9 million. The proceeds from these sales were used to pay down amounts outstanding under our revolving credit facility and to provide partial funding for our 2012 capital budget. The results of operations related to our Permian Basin assets are reported as discontinued operations for all applicable periods presented in the accompanying statements of operations included elsewhere in this report. +2013 Planned Divestiture. On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives, for aggregate cash consideration of approximately $200 million. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. We intend to use the proceeds from the sale to repay a portion of amounts outstanding under our revolving credit facility and partially fund our 2013 capital program. The assets being sold do not include any of our core Wattenberg Field acreage. As of December 31, 2012, total estimated proved reserves related to these assets were 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 84,544 Mmcfe of natural gas equivalent. See Note 19, Subsequent Events , to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. There can be no assurance that this transaction will close as planned. In addition, purchase price adjustments may reduce our proceeds from the transaction. +Production. Production from continuing operations increased significantly in 2012 as compared to 2011. In particular, primarily as a result of our Wattenberg Field drilling activities, oil production increased 18.5% and NGL production increased 17% . This production growth was achieved despite high line pressures experienced by our principal third-party provider of natural gas gathering, processing and transportation facilities in the Wattenberg Field. The high line pressure was the result of a series of operational issues experienced by third-party midstream service provider, primarily during the second and third quarter of 2012. The operational issues included downtime on third-party NGL transportation and fractionation facilities and abnormally warm weather, which limited the gathering system compression capacity. We are working closely with this primary midstream provider who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity in the Wattenberg Field. However, we do not expect the impact of this increased capacity to substantially benefit us until late 2013. +Our NGL pricing has also decreased significantly relative to the same period in 2011. Our NGLs are priced at Conway, Kansas, where ethane and propane are valued at a significant discount to Mt. Belvieu gulf coast NGL pricing. The planned 2013 infrastructure projects include a new NGL pipeline that will provide direct access for our NGLs to Mt. Belvieu where we anticipate improved pricing. +Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "adjusted net income (loss) attributable to shareholders," "adjusted EBITDA" and "PV-10%," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, cash flows from operations, investing or financing activities, and should not be viewed as a liquidity measure or indicator of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure. +36 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations: +Year Ended December 31, +Change +2012 +2011 +2010 +2012-2011 +2011-2010 +(dollars in millions, except per unit data) +Production (1) +Natural gas (MMcf) +32,409.8 +30,429.7 +26,239.1 +6.5 +% +16.0 +% +NGLs (MBbls) +841.3 +719.2 +569.6 +17.0 +% +26.3 +% +Crude oil (MBbls) +2,025.9 +1,709.9 +1,231.4 +18.5 +% +38.9 +% +Natural gas equivalent (MMcfe) (2) +49,612.4 +45,004.8 +37,044.9 +10.2 +% +21.5 +% +Average MMcfe per day +135.6 +123.3 +101.5 +10.0 +% +21.5 +% +Natural Gas, NGLs and Crude Oil Sales +Natural gas +$ +70.8 +$ +99.6 +$ +94.6 +(28.9 +)% +5.3 +% +NGLs +23.0 +27.2 +22.6 +(15.4 +)% +20.4 +% +Crude oil +176.5 +149.8 +91.1 +17.8 +% +64.4 +% +Provision for underpayment of natural gas sales +— +— +(3.3 +) +— +% +(100.0 +)% +Total natural gas, NGLs and crude oil sales +$ +270.3 +$ +276.6 +$ +205.0 +(2.3 +)% +34.9 +% +Realized Gain (Losses) on Derivatives, net (3) +Natural gas +$ +49.9 +$ +29.1 +$ +40.0 +71.5 +% +(27.3 +)% +Crude oil +(0.5 +) +(11.9 +) +7.1 +(95.8 +)% +(267.6 +)% +Total realized gain on derivatives, net +$ +49.4 +$ +17.2 +$ +47.1 +187.2 +% +(63.5 +)% +Average Sales Price (excluding gain/loss on derivatives) +Natural gas (per Mcf) +$ +2.18 +$ +3.27 +$ +3.61 +(33.3 +)% +(9.4 +)% +NGLs (per Bbl) +27.36 +37.82 +39.66 +(27.7 +)% +(4.6 +)% +Crude oil (per Bbl) +87.14 +87.63 +73.96 +(0.6 +)% +18.5 +% +Natural gas equivalent (per Mcfe) +5.45 +6.15 +5.63 +(11.4 +)% +9.2 +% +Average Sales Price (including realized gain/loss on derivatives) +Natural gas (per Mcf) +$ +3.72 +$ +4.23 +$ +5.13 +(12.1 +)% +(17.5 +)% +NGLs (per Bbl) +27.36 +37.82 +39.66 +(27.7 +)% +(4.6 +)% +Crude oil (per Bbl) +86.87 +80.69 +79.70 +7.7 +% +1.2 +% +Natural gas equivalent (per Mcfe) +6.44 +6.53 +6.89 +(1.4 +)% +(5.2 +)% +Average Lifting Cost (per Mcfe) (4) +Western operating region +$ +0.77 +$ +0.87 +$ +1.01 +(11.5 +)% +(13.9 +)% +Eastern operating region +1.38 +1.33 +1.55 +3.8 +% +(14.2 +)% +Weighted-average +0.85 +0.92 +1.05 +(7.6 +)% +(12.4 +)% +Natural Gas Marketing Contribution Margin (5) +$ +0.5 +$ +0.9 +$ +1.1 +(44.4 +)% +(18.2 +)% +Other Costs and Expenses +Exploration expense +$ +22.6 +$ +6.3 +$ +13.7 +261.5 +% +(54.3 +)% +Impairment of natural gas and crude oil properties +168.1 +25.2 +6.5 +* +288.2 +% +General and administrative expense +58.8 +61.5 +42.2 +(4.3 +)% +45.7 +% +Depreciation, depletion, and amortization +146.9 +128.9 +108.1 +13.9 +% +19.3 +% +Loss on extinguishment of debt +$ +23.3 +$ +— +$ +— +100.0 +% +— +% +Interest Expense +$ +48.3 +$ +37.0 +$ +33.3 +30.6 +% +11.2 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +37 +______________ +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data included in this report. +(2) +Six Mcf of natural gas equals one Bbl of crude oil or NGL. +(3) +Represents realized derivative gains and losses related to natural gas, NGLs and crude oil sales, which do not include realized derivative gains and losses related to natural gas marketing. +(4) +Represents lease operating expenses, exclusive of production taxes, on a per unit basis. +(5) +Represents sales from natural gas marketing, net of costs of natural gas marketing, including realized and unrealized derivative gains and losses related to natural gas marketing activities. +Natural Gas, NGLs and Crude Oil Sales +The following tables present natural gas, NGLs and crude oil production and weighted-average sales price for continuing operations: +Year Ended December 31, +Change +Production by Operating Region +2012 +2011 +2010 +2012-2011 +2011-2010 +Natural gas (MMcf) +Western +Wattenberg Field +9,845.2 +8,980.2 +7,229.7 +9.6 +% +24.2 +% +Piceance Basin (1) +13,226.9 +13,350.0 +12,001.5 +(0.9 +)% +11.2 +% +NECO, other (1) +3,194.3 +3,709.6 +4,481.9 +(13.9 +)% +(17.2 +)% +Total Western +26,266.4 +26,039.8 +23,713.1 +0.9 +% +9.8 +% +Eastern +6,143.4 +4,389.9 +2,526.0 +39.9 +% +73.8 +% +Total +32,409.8 +30,429.7 +26,239.1 +6.5 +% +16.0 +% +Crude oil (MBbls) +Western +Wattenberg Field +1,979.7 +1,670.9 +1,190.3 +18.5 +% +40.4 +% +Piceance Basin (1) +37.7 +33.2 +33.1 +13.6 +% +0.3 +% +NECO, other (1) +0.4 +1.0 +2.1 +(60.0 +)% +(52.4 +)% +Total Western +2,017.8 +1,705.1 +1,225.5 +18.3 +% +39.1 +% +Eastern +8.1 +4.8 +5.9 +68.8 +% +(18.6 +)% +Total +2,025.9 +1,709.9 +1,231.4 +18.5 +% +38.9 +% +NGLs (MBbls) +Western +Wattenberg Field +837.3 +712.1 +561.1 +17.6 +% +26.9 +% +NECO, other (1) +4.0 +7.1 +8.5 +(43.7 +)% +(16.5 +)% +Total +841.3 +719.2 +569.6 +17.0 +% +26.3 +% +Natural gas equivalent (MMcfe) +Western +Wattenberg Field +26,747.0 +23,278.4 +17,738.4 +14.9 +% +31.2 +% +Piceance Basin (1) +13,453.1 +13,549.3 +12,199.9 +(0.7 +)% +11.1 +% +NECO, other (1) +3,220.1 +3,758.2 +4,545.2 +(14.3 +)% +(17.3 +)% +Total Western +43,420.2 +40,585.9 +34,483.5 +7.0 +% +17.7 +% +Eastern +6,192.2 +4,418.9 +2,561.4 +40.1 +% +72.5 +% +Total +49,612.4 +45,004.8 +37,044.9 +10.2 +% +21.5 +% +Amounts may not recalculate due to rounding. +______________ +(1) +On February 4, 2013, we entered into a purchase and sale agreement pursuant to which we have agreed to sell our Piceance Basin, NECO and certain non-core Colorado oil and gas properties. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture. There can be no assurance we will be successful in closing such divestiture. +38 +Year Ended December 31, +Average Sales Price by Operating Region +Change +(excluding gain/loss on derivatives) +2012 +2011 +2010 +2012-2011 +2011-2010 +Natural gas (per Mcf) +Western +Wattenberg Field +$ +2.61 +$ +3.52 +$ +3.70 +(25.9 +)% +(4.9 +)% +Piceance Basin (1) +1.67 +2.82 +3.38 +(40.8 +)% +(16.6 +)% +NECO, other (1) +2.08 +3.26 +3.60 +(36.2 +)% +(9.4 +)% +Western +2.07 +3.12 +3.52 +(33.7 +)% +(11.4 +)% +Eastern +2.66 +4.15 +4.44 +(35.9 +)% +(6.5 +)% +Weighted-average price +2.18 +3.27 +3.61 +(33.3 +)% +(9.4 +)% +Crude oil (per Bbl) +Western +Wattenberg Field +87.27 +87.93 +74.46 +(0.8 +)% +18.1 +% +Piceance Basin (1) +80.20 +78.50 +56.60 +2.2 +% +38.7 +% +NECO, other (1) +83.80 +(95.33 +) +40.23 +(187.9 +)% +(337.0 +)% +Western +87.14 +87.63 +73.95 +(0.6 +)% +18.5 +% +Eastern +86.43 +87.09 +77.10 +(0.8 +)% +13.0 +% +Weighted-average price +87.14 +87.63 +73.96 +(0.6 +)% +18.5 +% +NGLs (per Bbl) +Western +Wattenberg Field +27.33 +37.62 +39.56 +(27.4 +)% +(4.9 +)% +NECO, other (1) +32.80 +58.07 +46.29 +(43.5 +)% +25.4 +% +Weighted-average price +27.36 +37.82 +39.66 +(27.7 +)% +(4.6 +)% +Natural gas equivalent (per Mcfe) +Western +Wattenberg Field +8.27 +8.82 +7.81 +(6.2 +)% +12.9 +% +Piceance Basin (1) +1.87 +2.97 +3.40 +(37.0 +)% +(12.6 +)% +NECO, other (1) +2.12 +3.30 +3.65 +(35.8 +)% +(9.6 +)% +Western +5.83 +6.35 +5.71 +(8.2 +)% +11.2 +% +Eastern +2.76 +4.22 +4.55 +(34.6 +)% +(7.3 +)% +Weighted-average price +5.45 +6.15 +5.63 +(11.4 +)% +9.2 +% +Amounts may not recalculate due to rounding. +The year-over-year change in natural gas, NGLs and crude oil sales revenue were primarily due to the following: +Year Ended December 31, +2012 +2011 +(in millions) +Increase in production +$ +38.8 +$ +56.4 +Decrease in average natural gas price +(35.3 +) +(10.2 +) +Decrease in average NGL price +(8.8 +) +(1.3 +) +Increase (decrease) in average crude oil price +(1.0 +) +23.4 +Decrease in provision for underpayment of natural gas sales +— +3.3 +Total increase (decrease) in natural gas, NGLs and crude oil sales revenue +$ +(6.3 +) +$ +71.6 +Natural gas, NGLs and crude oil sales revenue in 2012 decreased 2.3% compared to 2011. The decrease was primarily attributable to the 33.3% and 27.7% declines in the average price of natural gas and NGLs, respectively, during 2012. The decrease was offset in part by significantly higher volumes sold, in particular liquids, which shifted our liquids percentage of total production to approximately 34.7% in 2012 compared to 32.4% in 2011 . Our average daily sales volumes increased to 135.6 MMcfe per day in 2012 compared to 123.3 MMcfe per day in 2011, primarily due to the success of the horizontal Niobrara and Codell drilling program in the Wattenberg Field and the Merit Acquisition. For December 2012, our average production exit rate from continuing operations was 143 MMcfe per day compared to 139 MMcfe per day in December 2011. +39 +The increase in 2011 production compared to 2010 was directly attributable to an increase in production in our Western Operating Region of 16.8 MMcfe per day as a result of increased drilling in the Wattenberg field, as well as a 5.1 MMcfe per day increase in production in our Eastern Operating Region associated with our Marcellus wells. The 2011 increase in production was directly attributable to our decision to increase our capital expenditures for new wells drilled in 2010 and 2011 and switching a majority of our drilling program from vertical to horizontal wells in the Niobrara formation and Marcellus Shale. +Natural Gas, NGLs and Crude Oil Pricing. Our results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and our ability to market our production effectively. Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on our financial results and capital expenditures. +Natural gas prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. The combination of increased drilling activity and curtailments due to limited capacity on local gathering and processing infrastructure resulted in capacity constraints during the second and third quarters of 2012, primarily in our Wattenberg Field. Like most producers, we rely on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond our control. The price we receive for our natural gas is impacted by our transportation, gathering and processing agreements. We currently use the "net-back" method of accounting for these arrangements related to our natural gas sales. We sell natural gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. +The price we receive for our natural gas produced in our Western Operating Region is based on a market basket of prices, which generally includes natural gas sold at, near or below Colorado Interstate Gas ("CIG") prices, as well as other nearby regional prices. In September 2012, we renegotiated our marketing agreement for our natural gas in the Piceance Basin, which added approximately $0.40 per MMbtu to our Piceance natural gas price realization, effective with November 1 production. We have experienced a decline in the price of NGLs, mainly at Conway hub in Kansas where our Wattenberg production is marketed. This is primarily due to the increase in ethane and propane volumes flowing to Conway with a limited market for these products out of the area. Crude oil pricing is predominately driven by the physical market, supply and demand, the financial markets and national and international politics. The majority of our crude oil is sold on a calendar-year basis at a fixed differential to NYMEX pricing. +Production Costs +Production costs include lease operating expenses, production taxes and certain production and engineering staff-related overhead costs, as well as other costs to operate wells and pipelines as follows: +Year Ended December 31, +2012 +2011 +2010 +(in millions) +Lease operating expenses (1) +$ +42.2 +$ +41.3 +$ +38.9 +Production taxes +16.1 +17.5 +11.7 +Cost of well operations, overhead and other production expenses +17.2 +8.6 +13.0 +Total production costs +$ +75.5 +$ +67.4 +$ +63.6 +Total production costs per Mcfe +$ +1.52 +$ +1.50 +$ +1.72 +______________ +(1) +Prior to 2012, accretion of asset retirement obligations was included in lease operating expenses. In 2012, accretion of asset retirement obligations was reclassified as its own line item in the statement of operations. The amounts reclassified from lease operating expenses for 2011 and 2010 were $1.7 million and $1.3 million, respectively. +Lease operating expenses. Lifting costs per Mcfe were $0.85 , $0.92 and $1.05 for 2012, 2011 and 2010, respectively. The 7.6% decrease in lifting costs per Mcfe in 2012 from 2011 was primarily due to an increase in production, which resulted in the non-production-based portion of our lease operating expenses being spread across an increased number of units. The increase in lease operating expenses in 2012 compared to 2011 was primarily related to the 10.2% increase in production, including an increase in production-related expenses in the amount of $6.7 million mostly related to the Merit Acquisition and the Seneca-Upshur acquisition, offset by a decrease in environmental compliance costs of $3.2 million due to the completion of many environmental projects during 2011 and a decrease in workover expense of $2.5 million due to a reduction in the amount of workover projects completed in 2012 compared to 2011. The increase in lease operating expenses in 2011 compared to 2010 was primarily related to the 21.5% increase in production, including an increase in production-related expenses of $2.4 million mostly related to the Seneca-Upshur acquisition and other production-related expenses. +Production taxes. Production taxes fluctuate with natural gas, NGLs and crude oil sales. The $1.4 million , or 8% , decrease in production taxes for 2012 compared to 2011 is primarily related to a combination of lower total natural gas and NGL sales and, to a lesser extent, a change in the production tax rate due to a change in the mix of production locations. The $5.8 million , or 49.6% , increase in production taxes for 2011 +40 +compared to 2010 was primarily related to the 34.9% increase in natural gas, NGLs and crude oil sales and, to a lesser extent, higher ad valorem rates in certain Colorado counties. +Overhead and other production expenses. Overhead and other production expenses increased $8.6 million in 2012 compared to 2011. The increase consisted of a $3.2 million oil inventory expense in 2012 associated with the Merit Acquisition and an increase of $3.0 million of prepaid well costs charged to expense in 2012 as a result of changes in our capital spending plan. In July 2011, we signed an amended firm transportation agreement which resulted in the reversal of the $3.1 million liability accrued in 2010 related to an expected volume shortfall. The reversal of this accrued liability resulted in a reduction in overhead and other production expenses in 2011 when comparing 2011 to 2012 and 2010. The remaining decrease in overhead and other production expenses in 2011 compared to 2010 related to reductions in costs incurred for the wells and pipeline systems we operate on behalf of our affiliated partnerships and other third parties as a result of our acquisition of 12 affiliated partnerships. +Commodity Price Risk Management, Net +Commodity price risk management, net, includes realized gains and losses and unrealized changes in the fair value of derivative instruments related to our natural gas and crude oil production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments. +The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management, net: +Year Ended December 31, +2012 +2011 +2010 +(in millions) +Commodity price risk management gain (loss), net: +Realized gains (losses): +Natural gas +$ +49.9 +$ +29.1 +$ +40.0 +Crude oil +(0.5 +) +(11.9 +) +7.1 +Total realized gains, net +49.4 +17.2 +47.1 +Unrealized gains (losses): +Reclassification of realized gains included in prior periods unrealized +(28.8 +) +(10.3 +) +(20.1 +) +Unrealized gains for the period +11.7 +39.2 +32.9 +Total unrealized gains (losses), net +(17.1 +) +28.9 +12.8 +Total commodity price risk management gain, net +$ +32.3 +$ +46.1 +$ +59.9 +Realized gains recognized in 2012 are primarily the result of lower natural gas prices at settlement compared to the respective strike price of our natural gas derivative positions. Realized gains on natural gas, exclusive of basis swaps, were $66.5 million reflective of a weighted-average strike price of $5.36 compared to a weighted-average settlement price of $2.86. These gains were offset in part by realized losses of $16.6 million on our basis swap positions as the negative basis differential between NYMEX and CIG was a weighted-average of $0.21 compared to a weighted-average strike price of $1.82. The realized gains on natural gas derivative positions in 2012 were offset in part by realized losses on our crude oil positions as a result of higher prices at settlement compared to the respective strike price of our derivative positions. For 2012, the realized losses were reflective of a weighted-average strike price of $93.33 compared to a weighted-average settlement price of $93.72. +Unrealized gains in 2012 were primarily related to the downward shift in the crude oil and natural gas forward curve and its impact on the fair value of our open positions, offset in part by the narrowing of the CIG basis forward curve. During 2012, unrealized gains on our crude oil and natural gas positions were $9.4 million and $2.9 million, respectively, offset slightly by unrealized losses on our CIG basis swaps of $0.6 million. +Realized gains recognized in 2011 were mainly the result of lower natural gas prices at settlement compared to the respective strike price, resulting in a $44 million realized gain on our natural gas derivatives. These realized gains were offset in part by realized losses of $14.9 million on our basis swap positions and realized losses on our crude oil positions. During 2011, we recorded unrealized gains of $46.1 million on our natural gas positions offset in part by unrealized losses of $3.9 million on our crude oil positions and $3 million on our CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow. +During 2010, realized gains recognized were the result of lower natural gas and crude oil prices at settlement compared to the respective strike price, offset in part by a $12.1 million realized loss due to the negative basis differential between NYMEX and CIG being narrower than the strike price of our derivative position. During 2010, we recorded unrealized gains of $47.3 million on our natural gas positions offset in part by unrealized losses of $10.6 million on our crude oil positions and $3.8 million on our CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow. +41 +We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our physical natural gas and crude oil at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2012. +Natural Gas Marketing +Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices and realized and unrealized, mark-to-market adjustments, gains and losses on open derivative positions, and, to a lesser extent, volumes sold and purchased. +The following table presents the components of sales from and costs of natural gas marketing: +Year Ended December 31, +2012 +2011 +2010 +(in millions) +Natural gas sales revenue +$ +46.6 +$ +63.6 +$ +63.3 +Realized derivative gains, net +2.2 +3.0 +6.4 +Unrealized derivative losses, net +(1.7 +) +(0.2 +) +(0.6 +) +Total sales from natural gas marketing +47.1 +66.4 +69.1 +Costs of natural gas purchases +44.8 +61.6 +61.4 +Realized derivative losses, net +2.0 +2.6 +5.9 +Unrealized derivative losses (gains), net +(1.6 +) +0.1 +(0.5 +) +Other +1.4 +1.2 +1.2 +Total costs of natural gas marketing +46.6 +65.5 +68.0 +Natural gas marketing contribution margin +$ +0.5 +$ +0.9 +$ +1.1 +The decrease in natural gas sales revenue and costs of natural gas purchases in 2012 compared to 2011 is primarily attributable to a 34% decrease in the average natural gas price, offset in part by a 10% increase in volumes. The increase in natural gas sales revenue and costs of natural gas purchases in 2011 compared to 2010 is primarily attributable to a 9% increase in volumes, offset in part by an 8% decrease in the average natural gas price. +Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and detailed presentation of our derivative positions as of December 31, 2012 . +Exploration Expense +The following table presents the major components of exploration expense: +Year Ended December 31, +2012 +2011 +2010 +(in millions) +Exploratory dry hole costs +$ +15.3 +$ +0.2 +$ +4.2 +Geological and geophysical costs +1.9 +1.8 +2.3 +Operating, personnel and other +5.4 +4.3 +7.2 +Total exploration expense +$ +22.6 +$ +6.3 +$ +13.7 +Exploratory dry hole costs. In 2012, two vertical stratigraphic test wells in eastern Ohio were expensed at a cost of $12.2 million. Additionally, three wells in south central Ohio and a well in southeast Colorado were determined to have found noncommercial quantities of +42 +hydrocarbons and were expensed at a cost of $1.2 million and $0.9 million, respectively. In 2010, exploratory dry hole costs included the fracturing and testing of several exploratory zones on a well drilled in the Piceance Basin and a crude oil well drilled in the north eastern Colorado area. +Operating, personnel and other . The $1.1 million increase in 2012 compared to 2011 is mainly attributable to a $2 million increase in payroll and employee benefits in the exploration division as a result of increased employee headcount in the Utica Shale, offset in part by a $0.7 million decrease in PDCM's lease prospecting costs. The decrease in operating, personnel and other in 2011 compared to 2010 was primarily related to a $3.9 million reduction in personnel costs resulting from the reassignment of former exploration department personnel during the first quarter of 2011 to development drilling or administrative activities, offset in part by a $1.1 million increase in PDCM's lease prospecting costs. +Impairment of Natural Gas and Crude Oil Properties +The following table sets forth the major components of our impairments of natural gas and crude oil properties expense: +Year Ended December 31, +2012 +2011 +2010 +(in millions) +Impairment of proved properties +$ +161.2 +$ +22.5 +$ +— +Impairment of individually significant unproved properties +1.9 +1.1 +1.5 +Amortization of individually insignificant unproved properties +5.0 +1.6 +5.0 +Total impairment of natural gas and crude oil properties +$ +168.1 +$ +25.2 +$ +6.5 +Impairment of proved properties. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from unrelated third-party bids, a Level 3 input, as we changed our development plans in the basin and decided to sell the related assets. See Note 19, Subsequent Events , to our consolidated financial statements included elsewhere in this report for additional information regarding our planned divestiture of our Piceance Basin and other crude oil and natural gas properties. There can be no assurance that this transaction will close as planned. In 2011, we recognized an impairment charge of $22.5 million related to our NECO assets. +General and Administrative Expense +General and administrative expense for 2012 decreased by $2.6 million , or 4.3% , compared to 2011. The decrease is mainly attributable to a $6.7 million charge recognized in 2011 related to the separation agreement with our former chief executive officer, a $1.6 million charge to legal fees recorded in 2011 related to the settlement agreement reached with regard to our West Virginia royalty lawsuit and a $1.6 million decrease in professional and consulting fees during 2012. These decreases were offset in part by an increase in payroll and employee benefits of $7.5 million in 2012. +General and administrative expense for 2011 increased by $19.3 million, or 45.7%, compared to 2010. The increase was primarily due to an increase in payroll and payroll-related expense of $13.8 million, of which $6.7 million was related to a separation agreement with a former chief executive officer. The increase in payroll and payroll-related expenses was also impacted by the reassignment of former exploration department personnel contributing $3.7 million to the increase, with the remaining increase in payroll and payroll-related expenses being attributable to new hires and an overall increase in employee benefits. Also contributing to the increase was a $1.6 million charge related to the settlement reached with regard to our West Virginia royalty lawsuit. +Depreciation, Depletion and Amortization +Natural gas and crude oil properties. Depreciation, Depletion and Amortization ("DD&A") expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A related to natural gas and crude oil properties was $139.4 million in 2012 compared to $122.2 million in 2011. The increase in 2012 compared to 2011 was comprised of $12.5 million due to higher production and $4.7 million due to a higher weighted-average depreciation, depletion and amortization rate. +43 +The following table presents our DD&A rates for natural gas and crude oil properties: +Year Ended December 31, +Operating Region/Area +2012 +2011 +2010 +(per Mcfe) +Western +Wattenberg Field +$ +3.07 +$ +3.21 +$ +3.08 +Piceance Basin +3.12 +2.53 +2.49 +Weighted-average Western +2.94 +2.80 +2.72 +Eastern +1.93 +2.00 +2.57 +Total weighted-average +2.81 +2.72 +2.71 +Non-natural gas and crude oil properties. Depreciation expense for non-natural gas and crude oil properties was $7.5 million for 2012 compared to $6.7 million for 2011 and $7.5 million for 2010. +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations ("ARO") for 2012 increased by $2.3 million , or 134.3% , compared to 2011 . The increase in 2012 is primarily attributable to the increase in ARO liability associated with the properties acquired in the Merit Acquisition in 2012 and the Seneca-Upshur acquisition in 2011. Accretion of ARO for 2011 increased by $0.4 million , or 30.4% , compared to 2010. The increase in 2011 is primarily attributable to the increase in ARO liability associated with the Seneca-Upshur acquisition in the fourth quarter of 2011. +Gain on Sale of Properties and Equipment +The 2012 increase in the gain on sale of properties and equipment of $4.2 million as compared to 2011 mainly relates to our proportionate share of the gain realized from PDCM's sale of certain leases in our Eastern Operating Region. The gain on sale of properties and equipment in 2011 and 2010 was not material. +Interest Expense +Interest expense increased by approximately $11.3 million in 2012 compared to 2011 . Approximately $6 million of the increase is related to the issuance of the 2022 Senior Notes and the result of incurring interest on both the 2022 Senior Notes and 2018 Senior Notes during the month of October. Additionally, approximately $3.6 million of the increase was the result of higher average borrowings on our revolving credit facility during 2012 as compared to 2011 and $1.1 million due to higher debt issuance amortization expense. The increase in interest expense in 2011 compared to 2010 was attributable to $6 million of interest and amortization of debt discount related to our convertible notes issued in November 2010. The increase was offset in part by a decrease in debt issuance costs of $1.5 million and an increase in capitalized interest of $1.4 million. Interest costs capitalized in 2012, 2011 and 2010 were $1.2 million , $1.7 million and $0.3 million , respectively. +Loss on Extinguishment of Debt +The $23.3 million pre-tax loss on extinguishment of debt relates to the redemption of the 2018 Senior Notes during the fourth quarter of 2012. The pre-tax loss consists of an $18.9 million make-whole premium and the write-off of both unamortized debt discount of $1.5 million and unamortized debt issuance costs of $2.9 million . +Provision for Income Taxes +The effective tax rate ("rate") on loss from continuing operations in 2012 was a 38% benefit, which reflects a small benefit for the percentage depletion deduction. The 2011 benefit on income rate of 6.3% was also favorably impacted by our deduction for percentage depletion, as well as a $0.6 million tax benefit related to a reduction of the accrual for uncertain tax positions, offset by the adjustment to the estimated state deferred rate. The 2010 rate of 9.7% was also favorably impacted by our deduction for percentage depletion, as well as a $1.7 million discrete tax benefit related to our state deferred rate change. Excluding the effect of discrete items, our 2012, 2011 and 2010 rates were 38.0%, 0.1% and 32.9%, respectively. See Note 7, Income Taxes , to our consolidated financial statements included elsewhere in this report for our rate reconciliation for each of the three years in the three-year period ended December 31, 2012 . +Beginning with our 2010 tax year, we were accepted into and have agreed to participate in the IRS Compliance Assurance Process ("CAP") program. As part of this program, we agreed to an accelerated timeline for the IRS examination of our 2007, 2008 and 2009 tax years. This examination was completed during the second quarter of 2011 without any significant increase or decrease in tax expense. See Note 7, Income Taxes , to the accompanying consolidated financial statements included elsewhere in this report for a discussion regarding the reduction of our uncertain tax liability due to the conclusion of this examination. Our 2011 CAP reviewed return was filed in September 2012. The IRS subsequently accepted our return without change. We are currently participating in the CAP program review of our 2012 tax year and have accepted an offer for continued participation in the IRS CAP program for our 2013 tax year. +44 +Discontinued Operations +Permian Basin. During the fourth quarter of 2011, we closed on the sale of our non-core Permian Basin assets to unrelated third parties for a sales price of $13.2 million. We then developed a plan to divest 100% of our core Permian Basin assets, consisting of producing wells and undeveloped leaseholds. Following the sale of our core Permian assets to the unrelated party on February 28, 2012, we do not have significant continuing involvement in the operations of or cash flows from these assets. Accordingly, the Permian Basin assets were reclassified as held for sale as of December 31, 2011 and the results of operations related to the core and non-core Permian Basin assets have been reported as discontinued operations for all periods presented in the accompanying consolidated statements of operations included in this report. Proceeds from the sale of our core Permian Basin assets were $189.2 million after closing adjustments and were received in the first quarter of 2012. The sale of our Permian Basin assets resulted in a pre-tax gain of $19.9 million . See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for further discussion of the Permian divestiture. +North Dakota. In February 2011, we executed a purchase and sale agreement for the sale of our North Dakota assets and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million, net of non-affiliated investor partners' share of $3.8 million, resulting in a pre-tax gain on sale of $3.9 million. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in 2010 and 2011 in our consolidated statements of operations included elsewhere in this report. +Michigan. In July 2010, we completed the sale of our Michigan assets for net proceeds of $22 million. Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of or cash flows from these assets. Accordingly, the results of operations related to the Michigan assets have been reported as discontinued operations in 2010 in our consolidated statements of operations included elsewhere in this report. Operating results related to these assets were immaterial to the financial statements with the following exception. In June 2010, in conjunction with our decision to divest our Michigan assets, we recorded a related pre-tax impairment charge of $4.7 million. See Note 6, Properties and Equipment , and Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this report for additional information regarding the divestiture of our Michigan assets. +For production data and operating results related to our discontinued operations, see Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report. +Net Income (Loss) Attributable to Shareholders/Adjusted Net Income (Loss) Attributable to Shareholders +The year-over-year changes in net income (loss) attributable to shareholders are discussed above. These same reasons similarly impacted adjusted net income (loss) attributable to shareholders, a non-U.S. GAAP financial measure, with the exception of the unrealized derivative gains and losses on derivatives and provision for underpayment of natural gas sales, adjusted for taxes. Adjusted net income (loss) attributable to shareholders excludes the impact of a tax adjusted unrealized derivative gain, net, and provision for underpayment of natural gas sales of $10.6 million , $17.7 million and $5.8 million in 2012 , 2011 and 2010 , respectively. Adjusted net loss attributable to shareholders, a non-U.S. GAAP financial measure, was $120.1 million and $4.3 million in 2012 and 2011 , respectively. Adjusted net income attributable to shareholders was $0.4 million in 2010 . See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in the debt and equity markets and asset monetization transactions. In 2012, our primary sources of liquidity were proceeds from the divestiture of our Permian assets in February 2012 for $189.2 million , $164.5 million in proceeds from the issuance of our common stock in May 2012, $489 million from the issuance of our 2022 Senior Notes in October 2012 and net cash flows from operating activities of $174.7 million . +Our primary source of cash flows from operating activities is the sale of natural gas, NGLs and crude oil. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives, which has also historically been a source of cash. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in two years or less, our debt covenants limit our holdings to 80% of our expected future production on total proved reserves (proved developed producing, proved developed not producing and proved undeveloped). For instruments that mature later than two years, but no more than our designated maximum maturity, our debt covenants limit our holdings to 80% of our expected future production from proved developed producing properties. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2012 , we had a working capital deficit of $31.4 million compared to a deficit of $22 million at December 31, 2011 . +We ended 2012 with cash and cash equivalents of $2.5 million and availability under our revolving credit facility and our proportionate share of PDCM's credit facility of $396.1 million , for a total liquidity position of $398.6 million , compared to $196.4 million at the end of 2011. +45 +The increase in liquidity of $202.2 million , or 102.9% , was primarily due to $189.2 million received from the divestiture of our Permian assets in February 2012, proceeds from issuance of common stock of $164.5 million in May 2012, proceeds from the issuance of our $500 million 2022 Senior Notes in October 2012 and cash flows from operating activities of $174.7 million , offset by $304.6 million in expenditures related to the Merit Acquisition in June 2012, capital expenditures of $347.7 million and the redemption of our $203 million 2018 Senior Notes in November 2012. Assuming that the planned divestiture of our Piceance and NECO assets for proceeds of approximately $200 million had closed as of December 31, 2012, our pro-forma liquidity, excluding any effect related to our borrowing base redetermination, would have been approximately $600 million. +With our current liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund operations. However, an acceleration of development activities or other changes to our business plans could increase our need for capital. We may also sell select assets from time to time in order to fund development projects, acquisitions or other capital needs. +Capital Expenditures +We establish a capital budget annually based upon our development and exploration opportunities, liquidity position and expected cash flows from operating activities. We may revise our capital budget during the year as a result of, among other things, acquisitions or dispositions of assets, drilling results, commodity prices, changes in our borrowing capacity and/or significant changes in cash flows. In December 2012, our Board of Directors approved our 2013 capital budget of $324 million , excluding our share of PDCM's capital budget. Based on our current forecast, we expect to allocate $254 million to be invested in the Wattenberg Field, of which $207 million is for developmental drilling in the horizontal Niobrara and Codell. We expect to allocate approximately $53 million to drilling, leasing and completion activity in the Utica Shale. We expect to allocate $17 million to acquisitions of properties and leased acreage, exploration and other capital needs. PDCM's 2013 capital budget is currently set at $95 million , of which $48 million represents our share, and is expected to be funded by PDCM's operating activities, its credit facility and funds received related to title defects discovered from its acquisition of Seneca-Upshur. PDCM's capital budget for 2013 includes funding for the drilling of 14 gross horizontal wells. We believe, based on the current commodity price environment, cash flows provided by operating activities, planned asset sales and proceeds from borrowings on our revolving credit facility will fund our 2013 capital budget. +Because natural gas and crude oil production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of natural gas, NGLs and crude oil production and cash flows from operating activities if capital markets and commodity prices were to become depressed and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future. +Financing Activities +In recent periods, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of debt and equity securities. See Note 8, Long-Term Debt , and Note 12, Common Stock , to our consolidated financial statements in this report for a detailed discussion of our May 2012 sale of common stock and October 2012 debt issuance, respectively. We cannot, however, assure this will continue to be the case in the future. We continue to monitor market conditions and circumstances and their potential impact on each of our revolving credit facility lenders. Our revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. Our November semi-annual redetermination was completed on October 31, 2012 and resulted in the reduction of our borrowing base from $525 million to $450 million. The $75 million borrowing base reduction was principally the result of the incurrence of additional term debt in the form of the 2022 Senior Notes. Our next scheduled redetermination is in May 2013. While we expect to continue to add producing reserves through our drilling operations, these reserve additions will be offset by the sale of our Piceance and NECO assets if that transaction is completed and could be offset by other factors including, among other things, a significant decrease in commodity prices. These events could result in a negative impact on our future borrowing base redeterminations. +On January 23, 2012, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants and purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold 6.5 million shares of our common stock in May 2012 in an underwritten public offering at a price to the public of $26.50 per share. We used the net proceeds of $164.5 million to pay off the outstanding balance on our revolving credit facility and for general corporate purposes. +Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.0 times earnings before interest, taxes, depreciation, depletion and amortization, unrealized derivative gains (losses), exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of natural gas and crude oil derivative instruments. Additionally, available borrowings under our revolving credit facility are added back to the current asset calculation. The current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2012 , we were in compliance with all debt covenants with a 2.53 times debt to EBITDAX ratio and a 2.79 to 1.0 current ratio. We expect to remain in compliance throughout the next year. +46 +The indenture governing our senior notes contains customary representations and warranties as well as typical restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase or redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At December 31, 2012 , we were in compliance with all covenants and expect to remain in compliance throughout the next year. +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +Cash Flows +Operating Activities. Our net cash flows from operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased in 2012 and 2011 compared to the respective prior years. In 2012 , the $7.9 million increase was mainly attributable to an increase in realized derivative gains of $31.9 million , offset by a $18.5 million loss of operating margins related to the divested Permian Basin assets and an increase in the cash component of interest expense and exploration expense of $9.7 million and $1.2 million, respectively. In 2011, the $15 million increase was primarily due to an increase in natural gas, NGLs and crude oil sales of $88 million, offset by a decrease in realized derivative gains related to natural gas and crude oil sales of $29.9 million, an increase in production costs of $8.5 million and an increase in general and administrative expense of $19.3 million. The remaining changes in cash flows provided by operating activities were primarily due to changes in our assets and liabilities related to the timing of cash payments and receipts. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, decreased in 2012 and increased in 2011 when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of our assets and liabilities. +Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $6.7 million in 2012 from 2011, primarily due to a $31.9 million increase in realized derivative gains, offset in part by a $16.4 million increase in exploration expense and a $8.1 million increase in production costs. Adjusted EBITDA increased by $39.4 million in 2011 from 2010, primarily due to a $71.6 million increase in natural gas, NGLs and crude oil sales and a $15.7 million increase in operating margins related to the divested Permian Basin assets, offset in part by a $29.9 million decrease in realized gains on derivatives and a $19.3 million increase in general and administrative expense. +See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of non-U.S. GAAP financial measures. +Investing Activities. Cash flows from investing activities primarily consist of the acquisition, exploration and development of natural gas and crude oil properties, net of dispositions of natural gas and crude oil properties. In 2012, our drilling program consisted of two rigs operating in the oil- and liquid-rich horizontal Niobrara and Codell play in our Wattenberg Field. See Part I, Operations - Drilling Activities , for additional details on our drilling activities. Our capital investment in natural gas and crude oil properties has increased significantly year-over-year as a result of our commitment to growth. Net cash used in investing activities of $451.9 million during 2012 was primarily related to the $304.6 million expended in June 2012 for the Merit Acquisition and drilling activity of $347.7 million , offset in part by $189.2 million received from the divestiture of our Permian assets in February 2012 and $28.9 million received related to title defects discovered from PDCM's Seneca-Upshur acquisition in October 2011, of which $14.5 million represents our share. In 2011, we increased our capital spending by $159.6 million, including acquisitions, over that in 2010, and sold our North Dakota assets and our non-core Permian Basin assets, receiving cash of $23.1 million. Approximately 70% of our investment spending was directed toward organic development and the remaining 30% going toward the acquisition of natural gas and crude oil properties. In 2010, as the economic condition showed signs of recovery and the differential between natural gas and liquids grew, we increased our capital spending to $320.8 million . Approximately 51% of our investment spending was directed toward organic development in our liquid-rich plays and the remaining 49% going toward the acquisition of natural gas and crude oil properties. In 2010, we sold our Michigan assets, which provided cash of $22 million. +Financing Activities. Net cash from financing activities in 2012 includes gross proceeds of $500 million from our October 2012 issuance of the 2022 Senior Notes and $164.5 million from our May 2012 sale of common stock. The net proceeds from the issuance of the 2022 Senior Notes were used to fund the redemption of our 2018 Senior Notes for a total redemption price of approximately $222 million and to repay a portion of amounts outstanding under our revolving credit facility. The proceeds from the sale of common stock were used to finance a portion of the Merit Acquisition. Cash flows provided by financing activities in 2011 were primarily comprised of net borrowings under our bank credit facility of $233.5 million to execute our capital budget. Additionally, financing cash flows include $12.5 million, representing our proportionate share of capital contributed to PDCM by our investing partner. Cash flows provided by financing activities in 2010 included gross proceeds of $132.5 million and $115 million from our November 2010 sale of common stock and issuance of convertible debt, respectively. During 2010, our investing partner in PDCM contributed $35 million, of which our proportionate share was $20.1 million. This capital raise was offset in part by the net repayment of borrowings under our bank credit facility of $80 million. See Note 8, Long-Term Debt , and Note 12, Common Stock , to our consolidated financial statements included elsewhere in this report for further discussion on our debt and equity offerings and the formation of our joint venture. +47 +Contractual Obligations and Contingent Commitments +The table below presents our contractual obligations and contingent commitments as of December 31, 2012 . +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheets (1) +Long-term debt (2) +$ +690.3 +$ +— +$ +75.3 +$ +115.0 +$ +500.0 +Derivative contracts (3) +28.6 +18.5 +6.2 +3.9 +— +Derivative contracts - affiliated partnerships (4) +4.7 +4.7 +— +— +— +Production tax liability +44.6 +25.9 +18.7 +— +— +Asset retirement obligations +62.6 +1.0 +2.5 +2.5 +56.6 +Other liabilities (5) +4.9 +0.3 +0.9 +0.6 +3.1 +835.7 +50.4 +103.6 +122.0 +559.7 +Commitments, contingencies and other arrangements (6) +Interest on long-term debt (7) +403.1 +47.0 +91.5 +78.9 +185.7 +Operating leases +8.5 +2.6 +4.3 +0.7 +0.9 +Drilling commitment +0.9 +— +— +0.9 +— +Firm transportation and processing agreements (8) +199.3 +25.8 +55.4 +44.9 +73.2 +Other +0.4 +0.1 +0.3 +— +— +612.2 +75.5 +151.5 +125.4 +259.8 +Total +$ +1,447.9 +$ +125.9 +$ +255.1 +$ +247.4 +$ +819.5 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $148.4 million , due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the balance sheet in that it excludes $13.7 million in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. +(3) +Represents our gross liability related to the fair value of derivative positions, including the fair value of derivative contracts we entered into on behalf of our affiliated partnerships as the managing general partner. We have a related receivable from the partnerships of $2.1 million . +(4) +Represents our affiliated partnerships' designated portion of the fair value of our gross derivative assets. +(5) +Includes funds held from revenue distribution to third-party investors, including our affiliated partnerships, for plugging liabilities related to wells we operate and deferred officer compensation. +(6) +Table does not include an undrawn $18.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 11, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report. +(7) +Amounts presented include $12.6 million payable to the holders of our 3.25% convertible senior notes due 2016 and $379.4 million to the holders of our 2022 Senior Notes. Amounts also include $11.1 million payable to the participating banks of our revolving credit facilities, of which interest of $5.6 million is related to unutilized commitments at a rate of 0.5% per annum, $5.3 million related to the outstanding borrowings on our revolving credit facilities of $75.3 million and $0.2 million related to our undrawn letters of credit. +(8) +Represents our gross commitment, including our proportionate share of PDCM. We will recognize in our financial statements our proportionate share based on our working interest; however, with the exception of contracts entered into by PDCM, the costs of all volume shortfalls will be borne by PDC only. See Note 11, Commitments and Contingencies - Firm Transportation Agreements, to our consolidated financial statements included elsewhere in this report. +As the managing general partner of 21 partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. From time to time, we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. +48 +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included elsewhere in this report. Our critical accounting policies and estimates are as follows: +Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves . Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our natural gas and crude oil reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating natural gas and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of natural gas and crude oil properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of natural gas and crude oil properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our natural gas and crude oil properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of natural gas and crude oil properties. The estimates of future prices may differ from current market prices of natural gas and crude oil. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our natural gas and crude oil properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Natural Gas, NGLs and Crude Oil Sales Revenue Recognition . Natural gas, NGLs and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our natural gas, NGLs and crude oil sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to three months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded up to two months later. Historically, differences have been immaterial. +49 +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. +The judgments used in applying the above policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of natural gas and crude oil properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing , proved undeveloped, unproved natural gas and crude oil properties and other non-natural gas and crude oil properties. To estimate the fair values of these properties, we prepare estimates of natural gas and crude oil reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +50 +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the Consolidated Statements of Cash Flows in this report. +Adjusted net income (loss) attributable to shareholders. We define adjusted net income (loss) attributable to shareholders as net income (loss) attributable to shareholders, plus unrealized derivative losses and provisions for underpayment of natural gas sales, less unrealized derivative gains, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss) attributable to shareholders, as well as net income (loss) attributable to shareholders. We believe it often provides more transparency into our operating trends, such as production, prices, operating costs, realized gains and losses from derivatives and related factors, without regard to changes in our net income (loss) attributable to shareholders from our mark-to-market adjustments resulting from unrealized gains and losses from derivatives. Additionally, other items, such as the provision for underpayment of natural gas sales, which are not indicative of future results, may be excluded to clearly identify operational trends. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus unrealized derivative loss, interest expense, net of interest income, income taxes, impairment of natural gas and crude oil properties, depreciation, depletion and amortization, accretion of asset retirement obligations and loss on debt extinguishment, less unrealized derivative gain. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by the Company and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as: +• +our operating performance and return on capital as compared to our peers; +• +the financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis; +• +our ability to generate sufficient cash to service our debt obligations; and +• +the viability of acquisition opportunities and capital expenditure projects, including the related rate of return. +PV-10% . We define PV-10% as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10% discount rate. We believe that PV-10% provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10% is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating the Company and our reserves. PV-10% is not intended to represent the current market value of our estimated reserves. +51 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2012 +2011 +2010 +(in millions) +Adjusted cash flows from operations: +Adjusted cash flows from operations +$ +163.9 +$ +167.7 +$ +132.2 +Changes in assets and liabilities +10.8 +(0.9 +) +19.6 +Net cash from operating activities +$ +174.7 +$ +166.8 +$ +151.8 +Adjusted net income (loss) attributable to shareholders: +Adjusted net income (loss) attributable to shareholders +$ +(120.1 +) +$ +(4.3 +) +$ +0.4 +Unrealized gain (loss) on derivatives, net +(17.1 +) +28.6 +12.6 +Provision for underpayment of natural gas sales +— +— +(3.3 +) +Tax effect of above adjustments +6.5 +(10.9 +) +(3.5 +) +Net income (loss) attributable to shareholders +$ +(130.7 +) +$ +13.4 +$ +6.2 +Adjusted EBITDA to net income (loss) attributable to shareholders: +Adjusted EBITDA +$ +196.9 +$ +190.2 +$ +150.8 +Unrealized gain (loss) on derivatives, net +(17.1 +) +28.6 +12.6 +Interest expense, net +(48.3 +) +(36.9 +) +(33.2 +) +Income tax provision +80.2 +(6.2 +) +(0.4 +) +Impairment of natural gas and crude oil properties +(168.2 +) +(25.2 +) +(11.1 +) +Depreciation, depletion and amortization +(146.9 +) +(135.2 +) +(111.1 +) +Accretion of asset retirement obligations +(4.0 +) +(1.9 +) +(1.4 +) +Loss on extinguishment of debt +(23.3 +) +— +— +Net income (loss) attributable to shareholders +$ +(130.7 +) +$ +13.4 +$ +6.2 +Adjusted EBITDA to net cash from operating activities: +Adjusted EBITDA +$ +196.9 +$ +190.2 +$ +150.8 +Interest expense, net +(48.3 +) +(36.9 +) +(33.2 +) +Exploratory dry hole costs +15.3 +0.2 +4.2 +Stock-based compensation +8.5 +7.4 +5.0 +Amortization of debt discount and issuance costs +7.9 +6.3 +4.6 +(Gain) loss from sale of properties and equipment +(24.3 +) +(4.3 +) +0.3 +Other +7.9 +4.8 +0.5 +Changes in assets and liabilities +10.8 +(0.9 +) +19.6 +Net cash from operating activities +$ +174.7 +$ +166.8 +$ +151.8 +PV-10%: +PV-10% +$ +1,708.9 +$ +1,350.3 +$ +693.1 +Present value of estimated future income tax discounted at 10% +(540.4 +) +(409.1 +) +(204.7 +) +Standardized measure of discounted future net cash flows +$ +1,168.5 +$ +941.2 +$ +488.4 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our senior notes and convertible notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +52 +As of December 31, 2012 , our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of December 31, 2012 was $6.4 million with an average interest rate of 0.1%. The $6.4 million represents our aggregate bank balances, which includes checks issued and outstanding. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2012 , it was estimated that if market interest rates would have increased or decreased by 1% in 2012, the impact on our annual interest income would have been immaterial. +As of December 31, 2012 , excluding the $18.7 million irrevocable standby letters of credit, we had outstanding borrowings on our corporate bank credit facility of $49 million and, representing our proportionate share, $26.3 million on PDCM's bank credit facility. We estimate that if market interest rates would have increased or decreased by 1%, our 2012 interest expense would have changed by approximately $0.8 million . +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of natural gas, NGLs and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments allow us to predict with greater certainty the effective natural gas and crude oil prices to be received for our hedged production as it is produced. We believe that our established derivative policies and procedures are effective in achieving our risk management objectives. +The following table presents our derivative positions (excluding the derivative positions designated to our affiliated partnerships) related to natural gas and crude oil sales in effect as of December 31, 2012 : +Floors +Collars +Fixed-Price Swaps +CIG +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity +(BBtu) (1) +Weighted- +Average +Contract +Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted-Average +Contract Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted- +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2012 (2) +(in millions) +Floors +Ceilings +Natural Gas +NYMEX +2013 +4,910.0 +$ +6.20 +— +$ +— +$ +— +22,574.5 +$ +4.62 +23,320.7 +$ +(0.83 +) +$ +23.3 +2014 +— +— +— +— +— +13,390.0 +4.03 +8,830.0 +(0.22 +) +(0.1 +) +2015 +720.0 +4.00 +— +— +— +9,120.0 +3.91 +— +— +(2.6 +) +2016 +— +— +— +— +— +7,200.0 +3.84 +— +— +(3.9 +) +CIG +2013 +— +— +235.0 +4.00 +5.45 +— +— +— +— +0.2 +2014 +— +— +1,115.0 +4.50 +5.67 +4,828.0 +4.00 +— +— +1.8 +2015 +— +— +— +1,040.0 +4.50 +5.67 +2,730.0 +4.01 +— +— +0.6 +PEPL +2013 +— +— +— +— +— +990.4 +6.18 +— +— +2.8 +Total Natural Gas (3) +5,630.0 +2,390.0 +60,832.9 +32,150.7 +22.1 +Crude Oil +NYMEX +2013 +— +— +1,105.6 +80.46 +103.58 +1,220.9 +96.26 +— +— +4.7 +2014 +— +— +1,032.0 +82.83 +102.55 +360.0 +97.36 +— +— +0.6 +2015 +— +— +36.0 +90.00 +106.15 +— +— +— +— +0.2 +Total Crude Oil +— +2,173.6 +1,580.9 +— +5.5 +Total Natural Gas and Crude Oil +$ +27.6 +_____________ +(1) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2) +Approximately 29.4% of the fair value of our derivative assets and 8% of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report. +(3) +Pursuant to a purchase and sale agreement entered into on February 4, 2013, approximately 36,546 BBtu of natural gas hedging positions will be assumed by certain affiliates of Caerus Oil and Gas LLC upon the closing of the planned sale. There can be no assurance we will be successful in closing such divestiture. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional information regarding the planned divestiture of certain of our natural gas properties. +53 +The following table presents annual average NYMEX and CIG closing prices for natural gas and crude oil for the years ended December 31, 2012 and 2011 , as well as average sales prices we realized for the respective commodities: +Year Ended December 31, +2012 +2011 +Average Index Closing Price: +Natural Gas (per MMBtu) +CIG +$ +2.58 +$ +3.79 +NYMEX +2.79 +4.04 +Crude Oil (per Bbl) +NYMEX +$ +94.92 +$ +94.01 +Average Sales Price Realized: +Excluding realized derivative gains/(losses) +Natural Gas (per Mcf) +$ +2.18 +$ +3.27 +Crude Oil (per Bbl) +87.14 +87.63 +Including realized derivative gains/(losses) +Natural Gas (per Mcf) +$ +3.72 +$ +4.23 +Crude Oil (per Bbl) +86.87 +80.69 +Based on a sensitivity analysis as of December 31, 2012 , it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, including those designated to our affiliated partnerships, would have resulted in a decrease in fair value of $52.6 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $51.9 million. Excluding the derivatives designated to our affiliated partnerships, the same 10% increase or decrease in natural gas and crude oil prices would have resulted in a decrease in fair value of $52.1 million and an increase in fair value of $51.5 million, respectively. +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. +Our Oil and Gas Exploration and Production segment's natural gas, NGLs and crude oil sales are concentrated with a few predominately large customers. This concentrates the significance of our credit risk exposure to a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. We monitor their creditworthiness through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses in either of our Oil and Gas Exploration and Production or Gas Marketing segments. See Note 5, Concentration of Risk , to our consolidated financial statements included elsewhere in this report. +Our derivative financial instruments may expose us to the credit risk of nonperformance by the instrument's contract counterparty. We use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. We monitor their creditworthiness through our credit committee which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included in this report for more detail on our derivative financial instruments. +Disruption in the credit market may have a significant adverse impact on a number of financial institutions. We monitor the creditworthiness of the financial institutions with which we transact, giving consideration to the reports of credit agencies and their related ratings. While we believe that our monitoring procedures are sufficient and customary, no amount of analysis can assure performance by a financial institution. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2012 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time, and interest rates and commodity prices at the time. +54 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The response to this Item is set forth herein in a separate section of this report, beginning on Page F-1. +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2012 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2012 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2012 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +55 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE +(a) +(1 +) +Financial Statements: +See Index to Financial Statements and Schedules on page F-1. +(2 +) +Financial Statement Schedule: +See Index to Financial Statements and Schedule on page F-1. +Schedules and Financial Statements Omitted +All other financial statement schedules are omitted because they are not required, inapplicable or the information is included in the Financial Statements or Notes thereto. +(3 +) +Exhibits: +See Exhibits Index on the following page. +56 +Exhibits Index +Incorporated by Reference +Exhibit +SEC File +Filed +Number +Exhibit Description +Form +Number +Exhibit +Filing Date +Herewith +3.1 +Third Amended and Restated Articles of Incorporation of PDC Energy, Inc. (the "Company") +10-Q +000-07246 +3.1 +8/2/2012 +3.2 +By-laws of the Company. +10-Q +000-07246 +3.2 +8/2/2012 +4.1 +Rights Agreement by and between the Company and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/17/2007 +4.2 +Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon, including the form of 3.25% Convertible Senior Note due 2016. +8-K +000-07246 +4.1 +11/24/2010 +4.3 +Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022. +8-K +000-07246 +4.1 +10/3/2012 +10.1* +Indemnification Agreement with Non-Employee Directors. +8-K +000-07246 +10.1 +6/13/2012 +10.2* +The Company 401(k) & Profit Sharing Plan. +10-K +000-07246 +10.6 +2/24/2011 +10.3* +Non-Employee Director Deferred Compensation Plan. +S-8 +333-118222 +99.1 +8/13/2004 +10.4* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1* +Form of SAR Agreement under the 2004 Plan. +10-K +000-07246 +10.26 +2/27/2009 +10.4.2* +Form of Restricted Stock Agreement under the 2004 Plan. +10-K +000-07246 +10.26 +2/27/2009 +10.5* +2010 Long-Term Equity Compensation Plan, dated as of April 11, 2010 ("2010 Plan"). +S-8 +333-167945 +99.1 +7/1/2010 +10.5.1* +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2010 Plan. +8-K +000-07246 +4/23/2010 +10.6* +Form of 2010 Performance Share Agreement. +8-K +000-07246 +10.1 +3/17/2011 +10.7* +Form of 2012 Performance Share Agreement. +8-K +000-07246 +10.1 +1/20/2012 +10.8* +Executive severance compensation plan. +8-K +000-07246 +10.2 +9/25/2012 +10.9* +Form of 2013 Performance Share Agreement. +X +10.10* +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +X +10.11* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.12* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.13* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.14* +Employment Agreement with James M. Trimble, President and Chief Executive Officer, dated as of November 1, 2011. +10-Q +000-07246 +10.2 +11/3/2011 +10.15* +Employment Agreement with Barton R. Brookman, Jr., Senior Vice President of Exploration and Production, dated as of April 19, 2010. +8-K +000-07246 +10.5 +4/23/2010 +10.16 +Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009. +8-K +000-07246 +2.1 +11/4/2009 +10.17 +Limited Liability Company Agreement of PDC Mountaineer, LLC, dated October 29, 2009. +8-K +000-07246 +10.1 +11/4/2009 +57 +Incorporated by Reference +Exhibit +SEC File +Filed +Number +Exhibit Description +Form +Number +Exhibit +Filing Date +Herewith +10.18 † +Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing, Inc. and the Company, dated May 18, 2009. +10-Q +000-53201 +10.1 +5/18/2009 +10.19 † +Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and the Company, dated as of June 1, 2006. +10/A No. 3 +000-53201 +10.7 +3/31/2009 +10.20 † +First Amendment to the Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas and the Company, dated as of June 1, 2011. +8-K +000-07246 +10.1 +8/2/2011 +10.21 † +Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and the Company, dated as of October 28, 1999. +10/A No. 3 +000-53201 +10.3 +3/31/2009 +10.22 +Second Amended and Restated Credit Agreement dated as of November 5, 2010, between the Company, as borrower and JPMorgan Chase Bank, N.A. and BNP Paribas, as agents. +8-K +000-07246 +10.1 +11/12/2010 +10.23.1 +First Amendment to Second Amended and Restated Credit Agreement, dated as of December 22, 2010. +10-K +000-07246 +10.29 +2/24/2011 +10.23.2 +Second Amendment to Second Amended and Restated Credit Agreement, dated as of October 12, 2011. +8-K +000-07246 +10.1 +10/18/2011 +10.23.3 +Third Amendment to the Second Amended and Restated Credit Agreement, dated as of May 4, 2012. +10-Q +000-07246 +10.1 +5/10/2012 +10.23.4 +Fourth Amendment to the Second Amended and Restated Credit Agreement, dated as of June 25, 2012. +8-K +000-07246 +99.1 +7/2/2012 +10.23.5 +Fifth Amendment to the Second Amended and Restated Credit Agreement, dated as of June 29, 2012. +8-K +000-07246 +10.1 +7/2/2012 +10.23.6 +Sixth Amendment to the Second Amended and Restated Credit Agreement, dated as of September 21, 2012. +8-K +000-07246 +10.1 +9/25/2012 +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +14.1 +Code of Business Conduct and Ethics. +10-Q +000-17246 +14.1 +8/10/2009 +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1** +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +101.INS** +XBRL Instance Document +101.SCH** +XBRL Taxonomy Extension Schema Document +101.CAL** +XBRL Taxonomy Extension Calculation Linkbase Document +101.DEF** +XBRL Taxonomy Extension Definition Linkbase Document +101.LAB** +XBRL Taxonomy Extension Label Linkbase Document +101.PRE** +XBRL Taxonomy Extension Presentation Linkbase Document +*Management contract or compensatory plan or arrangement. +** Furnished herewith. +58 +Incorporated by Reference +Exhibit +SEC File +Filed +Number +Exhibit Description +Form +Number +Exhibit +Filing Date +Herewith +† Confidential portions of this document have been omitted and are filed separately with the SEC pursuant to Exchange Act Rule 24b-2. +59 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By /s/ James M. Trimble +James M. Trimble +President and Chief Executive Officer +February 27, 2013 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ James M. Trimble +President, Chief Executive Officer and Director +February 27, 2013 +James M. Trimble +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +February 27, 2013 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +February 27, 2013 +R. Scott Meyers +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 27, 2013 +Jeffrey C. Swoveland +/s/ Joseph E. Casabona +Director +February 27, 2013 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +February 27, 2013 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 27, 2013 +Larry F. Mazza +/s/ David C. Parke +Director +February 27, 2013 +David C. Parke +/s/ Kimberly Luff Wakim +Director +February 27, 2013 +Kimberly Luff Wakim +60 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Bcfe – One billion cubic feet of natural gas equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +Mcfe – One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL). +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +MMcfe – One million cubic feet of natural gas equivalent. +Tcfe – One trillion cubic feet of natural gas equivalent. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Behind-pipe reserves - Natural gas and crude oil reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. Generally, these are reserves in reservoirs above currently producing zones. +CIG - Colorado Interstate Gas. +Completion - Refers to the work performed and the installation of permanent equipment for the production of natural gas and crude oil from a recently drilled well. +Delineation - A drilling technique carried out to gain a better understanding of the structure and extent of a deposit in order to decide whether or not to conduct further drilling activities. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Dry gas or dry natural gas - Natural gas is considered dry when its composition is over 90% pure methane. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exit rate - Rate of production as of the date specified. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +61 +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells well include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Natural gas and crude oil production that we own, less royalties and production due to others. References to net production include our proportionate share of PDCM's and our affiliated partnerships' net production. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +PEPL - Panhandle Eastern Pipeline. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10%) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10% is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - A well that is not a dry well or dry hole, as defined above, and includes wells that are mechanically capable of production. +Proved developed non-producing reserves or PDNPs - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term mean "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of natural gas, NGL, crude oil and condensate, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing natural gas and crude oil from a different producing formation. +62 +Refracture - A refracture is when we stimulate by fracturing a producing zone of a well to increase its production as well as its PDP reserves. +Reserves - Estimated remaining quantities of natural gas, NGLs crude oil and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering natural gas, NGLs and crude oil or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Spud - To begin drilling; the act of beginning a hole. Past tense: spudded . +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Unconventional resource(s) - Natural gas and crude oil that cannot be produced at economic flow rates in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other techniques to expose more of the resources to the wellbore. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and crude oil, regardless of whether such acreage contains proved reserves. +Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil. +Working interest - An interest in a natural gas and crude oil lease that gives the owner of the interest the right to drill and produce natural gas and crude oil on the leased acreage. It requires the owner to pay their entire share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production. +63 +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Management's Report on Internal Control Over Financial Reporting +F- 2 +Financial Statements: +Report of Independent Registered Public Accounting Firm +F- 3 +Consolidated Balance Sheets - December 31, 2012 and 201 1 +F- 4 +Consolidated Statements of Operations - Years Ended December 31, 2012, 2011 and 2010 +F- 5 +Consolidated Statements of Cash Flows - Years Ended December 31, 2012, 2011 and 2010 +F- 6 +Consolidated Statements of Equity - Years Ended December 31, 2012, 2011, and 2010 +F- 7 +Notes to Consolidated Financial Statements +F- 8 +Supplemental Information - Unaudited: +Natural Gas and Crude Oil Information +F- 38 +Quarterly Financial Information +F- 44 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts +F- 46 +F- 1 +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 , based upon the criteria established in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2012 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2012 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +PDC ENERGY, INC. +/s/ James M. Trimble +James M. Trimble +President and Chief Executive Officer +/s/ Gysle R. Shellum +Gysle R. Shellum +Chief Financial Officer +/s/ R. Scott Meyers +R. Scott Meyers +Chief Accounting Officer +F- 2 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc.: +In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, equity, and cash flows present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Pittsburgh, Pennsylvania +February 26, 2013 +F- 3 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2012 +2011 +Assets +Current assets: +Cash and cash equivalents +$ +2,457 +$ +8,238 +Restricted cash +3,942 +11,070 +Accounts receivable, net +64,880 +59,923 +Accounts receivable affiliates +4,842 +8,518 +Fair value of derivatives +52,042 +60,809 +Deferred income taxes +36,151 +16,127 +Prepaid expenses and other current assets +7,635 +8,365 +Total current assets +171,949 +173,050 +Properties and equipment, net +1,616,706 +1,301,716 +Assets held for sale +— +148,249 +Fair value of derivatives +6,883 +41,175 +Accounts receivable affiliates +— +2,836 +Other assets +31,310 +30,979 +Total Assets +$ +1,826,848 +$ +1,698,005 +Liabilities and Shareholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +82,716 +$ +76,027 +Accounts payable affiliates +5,296 +10,176 +Production tax liability +25,899 +18,949 +Fair value of derivatives +18,439 +27,974 +Funds held for distribution +34,228 +28,594 +Accrued interest payable +11,056 +11,243 +Other accrued expenses +25,715 +22,083 +Total current liabilities +203,349 +195,046 +Long-term debt +676,579 +532,157 +Deferred income taxes +148,427 +207,573 +Asset retirement obligation +61,563 +46,316 +Fair value of derivatives +10,137 +21,106 +Accounts payable affiliates +— +6,134 +Other liabilities +23,612 +25,561 +Total liabilities +1,123,667 +1,033,893 +Commitments and contingent liabilities +Shareholders' equity +Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued +— +— +Common shares - par value $0.01 per share, 100,000,000 authorized, 30,294,224 and 23,634,958 issued as of December 31, 2012 and 2011, respectively +303 +236 +Additional paid-in capital +387,494 +217,707 +Retained earnings +315,568 +446,280 +Treasury shares - at cost, 5,059 and 2,938 as of December 31, 2012 and 2011, respectively +(184 +) +(111 +) +Total shareholders' equity +703,181 +664,112 +Total Liabilities and Shareholders' Equity +$ +1,826,848 +$ +1,698,005 +See accompanying Notes to Consolidated Financial Statements +F- 4 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2012 +2011 +2010 +Revenues: +Natural gas, NGLs and crude oil sales +$ +270,327 +$ +276,605 +$ +205,029 +Sales from natural gas marketing +47,079 +66,419 +69,071 +Commodity price risk management gain, net +32,339 +46,090 +59,891 +Well operations, pipeline income and other +6,388 +6,846 +9,030 +Total revenues +356,133 +395,960 +343,021 +Costs, expenses and other: +Production costs +75,485 +67,352 +63,543 +Cost of natural gas marketing +46,552 +65,465 +68,015 +Exploration expense +22,605 +6,253 +13,675 +Impairment of natural gas and crude oil properties +168,149 +25,159 +6,481 +General and administrative expense +58,815 +61,454 +42,188 +Depreciation, depletion, and amortization +146,879 +128,907 +108,095 +Accretion of asset retirement obligations +4,060 +1,733 +1,329 +Gain on sale of properties and equipment +(4,353 +) +(196 +) +(174 +) +Total cost, expenses and other +518,192 +356,127 +303,152 +Income (loss) from operations +(162,059 +) +39,833 +39,869 +Loss on extinguishment of debt +(23,283 +) +— +— +Interest expense +(48,287 +) +(36,985 +) +(33,250 +) +Interest income +8 +47 +71 +Income (loss) from continuing operations before income taxes +(233,621 +) +2,895 +6,690 +Provision for income taxes +88,835 +183 +(652 +) +Income (loss) from continuing operations +(144,786 +) +3,078 +6,038 +Income (loss) from discontinued operations, net of tax +14,074 +10,359 +(104 +) +Net income (loss) +(130,712 +) +13,437 +5,934 +Net loss attributable to noncontrolling interests +— +— +280 +Net income (loss) attributable to shareholders +$ +(130,712 +) +$ +13,437 +$ +6,214 +Amounts attributable to PDC Energy, Inc. shareholders: +Income (loss) from continuing operations +$ +(144,786 +) +$ +3,078 +$ +6,318 +Income (loss) from discontinued operations, net of tax +14,074 +10,359 +(104 +) +Net income (loss) attributable to shareholders +$ +(130,712 +) +$ +13,437 +$ +6,214 +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(5.23 +) +$ +0.13 +$ +0.33 +Income (loss) from discontinued operations +0.51 +0.44 +(0.01 +) +Net income (loss) attributable to shareholders +$ +(4.72 +) +$ +0.57 +$ +0.32 +Diluted +Income (loss) from continuing operations +$ +(5.23 +) +$ +0.13 +$ +0.32 +Income (loss) from discontinued operations +0.51 +0.43 +(0.01 +) +Net income (loss) attributable to shareholders +$ +(4.72 +) +$ +0.56 +$ +0.31 +Weighted-average common shares outstanding: +Basic +27,677 +23,521 +19,674 +Diluted +27,677 +23,871 +19,821 +See accompanying Notes to Consolidated Financial Statements +F- 5 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2012 +2011 +2010 +Cash flows from operating activities: +Net income (loss) +$ +(130,712 +) +$ +13,437 +$ +5,934 +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Unrealized (gain) loss on derivatives, net +17,134 +(28,601 +) +(12,625 +) +Depreciation, depletion and amortization +146,879 +135,154 +111,062 +Impairment of natural gas and crude oil properties +168,149 +25,159 +11,147 +Prepaid well costs write-offs +3,916 +1,359 +668 +Loss on extinguishment of debt +23,283 +— +— +Exploratory dry hole costs +15,347 +177 +4,199 +Accretion of asset retirement obligation +4,060 +1,897 +1,423 +Stock-based compensation +8,495 +8,781 +5,314 +Excess tax benefits from stock-based compensation +— +(1,311 +) +(293 +) +(Gain) loss from sale of properties and equipment +(24,273 +) +(4,263 +) +299 +Amortization of debt discount and issuance costs +7,864 +6,265 +4,618 +Deferred income taxes +(80,379 +) +9,530 +1,179 +Inventory adjustment and other +4,123 +135 +307 +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +294,598 +154,282 +127,298 +Changes in assets and liabilities: +Accounts receivable +6,843 +(3,451 +) +2,122 +Other assets +(2,908 +) +(3,893 +) +22,616 +Restricted cash +8,859 +(8,603 +) +219 +Production tax liability +2,499 +5,436 +(6,818 +) +Accounts payable and accrued expenses +(5,050 +) +12,422 +1,172 +Other liabilities +592 +(2,796 +) +(730 +) +Total changes in assets and liabilities +10,835 +(885 +) +18,581 +Net cash from operating activities +174,721 +166,834 +151,813 +Cash flows from investing activities: +Capital expenditures +(347,729 +) +(334,496 +) +(162,723 +) +Acquisition of oil and gas properties, net of cash acquired +(312,223 +) +(145,894 +) +(158,051 +) +Proceeds from acquisition adjustments +14,469 +— +— +Proceeds from sale of properties and equipment +193,544 +23,140 +23,369 +Other +— +849 +(3,527 +) +Net cash from investing activities +(451,939 +) +(456,401 +) +(300,932 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +682,000 +417,194 +414,500 +Payment of revolving credit facility +(839,750 +) +(183,713 +) +(494,500 +) +Proceeds from senior notes offering +500,000 +— +115,000 +Redemption of senior notes +(221,840 +) +— +— +Payment of debt issuance costs +(11,969 +) +(680 +) +(8,541 +) +Proceeds from sale of common stock, net of issuance costs +164,496 +— +125,506 +Excess tax benefits from stock-based compensation +— +1,311 +293 +Contribution from noncontrolling interest +— +12,464 +20,077 +Purchase of treasury shares +(1,500 +) +(3,143 +) +(788 +) +Net cash from financing activities +271,437 +243,433 +171,547 +Net change in cash and cash equivalents +(5,781 +) +(46,134 +) +22,428 +Cash and cash equivalents, beginning of year +8,238 +54,372 +31,944 +Cash and cash equivalents, end of year +$ +2,457 +$ +8,238 +$ +54,372 +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +41,768 +$ +29,429 +$ +28,335 +Income taxes +1,845 +(1,498 +) +(27,322 +) +Non-cash investing activities: +Change in accounts payable related to purchases of properties and equipment +288 +23,837 +15,787 +Change in asset retirement obligation, with a corresponding change to natural gas and crude oil properties, net of disposals +11,967 +17,538 +3,624 +Non-cash financing activities: +Change in paid-in capital related to convertible debt, net of tax +— +— +12,850 +See Note 15, Acquisitions , for non-cash transactions related to our acquisitions +See accompanying Notes to Consolidated Financial Statements +F- 6 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2012 +2011 +2010 +Common shares, issued: +Shares beginning of year +23,634,958 +23,462,326 +19,242,219 +Shares issued pursuant to sale of equity +6,500,000 +— +4,140,000 +Exercise of stock options +— +2,814 +— +Issuance of stock awards, net of forfeitures +173,737 +242,334 +110,680 +Retirement of treasury shares +(14,471 +) +(72,516 +) +(30,573 +) +Shares end of year +30,294,224 +23,634,958 +23,462,326 +Treasury shares: +Shares beginning of year +2,938 +2,938 +8,273 +Purchase of treasury shares +44,576 +87,588 +30,573 +Issuance of treasury shares +(28,587 +) +(15,072 +) +— +Retirement of treasury shares +(14,471 +) +(72,516 +) +(30,573 +) +Non-employee directors' deferred compensation plan +603 +— +(5,335 +) +Shares end of year +5,059 +2,938 +2,938 +Common shares outstanding +30,289,165 +23,632,020 +23,459,388 +Equity: +Shareholders' equity +Preferred shares, par value $0.01 per share: +Balance beginning and end of year +$ +— +$ +— +$ +— +Common shares, par value $0.01 per share: +Balance beginning of year +236 +235 +192 +Shares issued pursuant to sale of equity +65 +— +41 +Issuance of stock awards, net of forfeitures +2 +1 +2 +Balance end of year +303 +236 +235 +Additional paid-in capital: +Balance beginning of year +217,707 +209,198 +64,406 +Proceeds from sale of equity, net of issuance costs +164,431 +— +125,465 +Convertible debt discount, net of issuance costs and tax +— +— +12,165 +Stock-based compensation expense +8,495 +8,781 +5,314 +Issuance of treasury shares +(955 +) +(472 +) +— +Retirement of treasury shares +(491 +) +(2,671 +) +(788 +) +Tax impact of stock-based compensation +(1,693 +) +785 +(166 +) +Contribution by investing partner in PDCM +— +12,464 +20,077 +Effect of PDCM deconsolidation/change in ownership interest +— +(10,378 +) +(17,275 +) +Balance end of year +387,494 +217,707 +209,198 +Retained earnings: +Balance beginning of year +446,280 +432,843 +426,629 +Net income (loss) attributable to shareholders +(130,712 +) +13,437 +6,214 +Balance end of year +315,568 +446,280 +432,843 +Treasury shares, at cost: +Balance beginning of year +(111 +) +(111 +) +(312 +) +Purchase of treasury shares +(1,500 +) +(3,143 +) +(788 +) +Issuance of treasury shares +955 +472 +— +Retirement of treasury shares +491 +2,671 +788 +Non-employee directors' deferred compensation plan +(19 +) +— +201 +Balance end of year +(184 +) +(111 +) +(111 +) +Total shareholders' equity +703,181 +664,112 +642,165 +Noncontrolling interests in subsidiary +Balance beginning of year +— +76 +47,678 +Noncontrolling interest in PDC Mountaineer, LLC +— +— +(47,322 +) +Net loss attributed to noncontrolling interest in subsidiary +— +(76 +) +(280 +) +Balance end of year +— +— +76 +Total noncontrolling interests in subsidiary +— +— +76 +Total Equity +$ +703,181 +$ +664,112 +$ +642,241 +See accompanying Notes to Consolidated Financial Statements +F- 7 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. ("PDC," "PDC Energy," "we," "us" or "the Company") is a domestic independent natural gas and crude oil company engaged in the exploration for and the acquisition, development, production and marketing of natural gas, NGLs and crude oil. As of December 31, 2012 , we owned an interest in approximately 7,200 gross wells located primarily in the Wattenberg Field, Utica Shale, Appalachian Basin, northeast Colorado and Piceance Basin. We are engaged in two business segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +The consolidated financial statements include the accounts of PDC, our wholly owned subsidiaries, an entity in which we have a controlling financial interest (2010 only) and our proportionate share of PDC Mountaineer, LLC ("PDCM") and our 21 affiliated partnerships. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of natural gas, NGLs and crude oil sales revenue, natural gas, NGLs and crude oil reserves, future cash flows from natural gas and crude oil properties, valuation of derivative instruments and valuation of deferred income tax assets. +Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. Accretion of asset retirement obligations have been reclassified out of the statement of operations line item production cost and into accretion of asset retirement obligations. Deferred income taxes have been reclassified out of the balance sheet line item prepaid expenses and other current assets and into deferred income taxes. We also reclassified prepaid well costs write-offs out of the statement of cash flows line item changes in other assets and into prepaid well costs write-offs. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash. Pursuant to an oral litigation settlement agreement, in July 2011, we funded an escrow account in the amount of $8.7 million . During 2012, approval and settlement occurred and the $8.7 million was released from the escrow account thereby reducing our restricted cash balance. In conjunction with our acquisition of certain Wattenberg assets in 2012, we funded an escrow account with $1.7 million . +We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2012 , we had collateral in the form of certificates of deposit and cash totaling $5.3 million which consisted of $3.9 million and $1.4 million included in restricted cash and other assets, respectively. As of December 31, 2011 , we had collateral in the form of certificates of deposit and cash totaling $3.8 million which consisted of $2.3 million and $1.5 million included in restricted cash and other assets, respectively. +Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our natural gas and crude oil operations. As of December 31, 2012 and 2011 , inventory of $1.2 million and $1.1 million , respectively, is included in prepaid expenses and other current assets on the balance sheets. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of natural gas and crude oil. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on our balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations, with the exception of changes in fair value related to those derivatives we designated to our affiliated partnerships. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. Changes in the fair value of the derivative instruments designated to our affiliated partnerships are recorded on the balance sheets in accounts payable affiliates and accounts receivable affiliates. As positions designated to our affiliated partnerships settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the partnerships and net realized losses are deducted from the partnerships’ cash distributions from production. The affiliated partnerships bear their designated share of counterparty risk. +The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Notes 3, Fair Value of Financial Instruments , and 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2012 and 2011 , respectively. +F- 8 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Natural Gas and Crude Oil Properties. We account for our natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment , for disclosure related to changes in our capitalized exploratory well costs. +Proved Property Impairment. We assess our producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the statement of operations line item impairment of natural gas and crude oil properties, with a corresponding impact on accumulated depreciation, depletion and amortization on the balance sheet. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved natural gas and crude oil properties with individually significant acquisition costs are periodically assessed for impairment. Unproved natural gas and crude oil properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved natural gas and crude oil properties are charged to the statement of operations line item impairment of natural gas and crude oil properties. +Other Property and Equipment. The following table presents the estimated useful lives of our other property and equipment: +Pipelines and related facilities +10 - 17 years +Transportation and other equipment +3 - 20 years +Buildings +30 - 40 years +Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. No impairment to other property and equipment was recognized in 2012 or 2011. Impairment recognized in 2010 was immaterial. +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $7.5 million , $6.7 million and $7.5 million in 2012 , 2011 and 2010 , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved natural gas and crude oil properties and major development projects, on which DD&A is not currently recorded and on which exploration or development +F- 9 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $1.2 million , $1.7 million and $0.3 million in 2012 , 2011 and 2010 , respectively. +Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair values that are ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. Depreciation, depletion, and amortization expense is not recorded on assets to be divested once they are classified as held for sale. Assets to be divested are classified in the consolidated financial statements as held for sale, and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities held for sale on the consolidated balance sheets and to discontinued operations on the consolidated statements of operations, respectively, for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. Management does not expect any continuing involvement with businesses classified as discontinued operations following their divestiture. Businesses classified as held for sale are expected to be disposed of within one year. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the balance sheet amounts are reclassified from their historical presentation to assets and liabilities held for sale for all periods presented. The results of operations continue to be reported in continuing operations. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce natural gas, NGLs and crude oil, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. The partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the balance sheets. The long-term portion of the production tax liability is included in other liabilities on the balance sheets and was $18.7 million and $19.4 million in December 31, 2012 and 2011 , respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and future credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2012 and 2011 , we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2012 and 2011 , included in other assets was $17.4 million and $12.3 million , respectively, related to debt issuance costs. The December 31, 2012 , amount included $1.9 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $10.9 million related to our 7.75% senior notes due 2022 and $4.6 million related to our revolving credit facility and the PDCM credit facility. The December 31, 2011, amount included $2.4 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $3.4 million related to our 12% senior notes due 2022 and $6.5 million related to our revolving credit facility and the PDCM credit facility. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value. The initial capitalized costs, net of salvage value, are depleted over the useful lives of the related assets through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9, Asset Retirement Obligations , for a reconciliation of the changes in our asset retirement obligation. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Natural gas, NGLs and crude oil sales. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for transportation and processing arrangements of our sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, we sell gas at the wellhead and collect a price and recognize revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by the purchasers and reflected in the wellhead price. The majority of our natural gas and NGLs in Colorado are sold on a long-term basis ranging +F- 10 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +from 15 years to the life of the lease. Sales of natural gas and NGLs in other regions, along with crude oil, are sold under contracts with terms ranging from one month to three years. Virtually all of our contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line and the quality of the natural gas. +Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the limited partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. +Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, Riley Natural Gas ("RNG"), our suppliers and our customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the realized and unrealized gains and losses of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of natural gas and crude oil properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved natural gas and crude oil properties and other non-natural gas and crude oil properties. To estimate the fair values of these properties, we prepare estimates of natural gas and crude oil reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in natural gas and crude oil exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the statement of operations. No amounts for stock-based compensation were capitalized in 2012 , 2011 and 2010 . +Recent Accounting Standards. +The following standards were recently adopted: +Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and were effective for public entities during interim and annual periods beginning after December 15, 2011. Early application was not permitted. With the exception of the disclosure requirements, adoption of these changes did not have a significant impact on our financial statements. +Presentation of Comprehensive Income. On June 16, 2011, the FASB issued changes related to the presentation of comprehensive income. These changes eliminate the current option to report other comprehensive income and its components in the statement of changes in equity. These changes are intended to enhance comparability between entities that report under U.S. GAAP and those that report under IFRS, and to provide a more consistent method of presenting non-owner transactions that affect an entity's equity. An entity may elect to present items of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements. Each component of net income and each component of other comprehensive income, together with totals +F- 11 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +for comprehensive income and its two parts, net income and other comprehensive income, need to be displayed under either alternative. The statement(s) need to be presented with equal prominence as the other primary financial statements. These changes were effective for our financial statements issued for annual reporting periods beginning after December 15, 2011. Adoption of this change did not have a material impact on our financial statements. +NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our natural gas and crude oil collars, natural gas calls and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +F- 12 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, +2012 +2011 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Assets: +Commodity-based derivative contracts +$ +42,788 +$ +15,734 +$ +58,522 +$ +76,104 +$ +25,837 +$ +101,941 +Basis protection derivative contracts +387 +16 +403 +5 +38 +43 +Total assets +43,175 +15,750 +58,925 +76,109 +25,875 +101,984 +Liabilities: +Commodity-based derivative contracts +9,839 +2,081 +11,920 +9,888 +3,768 +13,656 +Basis protection derivative contracts +16,656 +— +16,656 +35,424 +— +35,424 +Total liabilities +26,495 +2,081 +28,576 +45,312 +3,768 +49,080 +Net asset +$ +16,680 +$ +13,669 +$ +30,349 +$ +30,797 +$ +22,107 +$ +52,904 +The following table presents a reconciliation of our Level 3 assets measured at fair value: +2012 +2011 +2010 +(in thousands) +Fair value, net asset, beginning of year +$ +22,107 +$ +10,762 +$ +15,048 +Changes in fair value included in statement of operations line item: +Commodity price risk management gain, net +7,576 +13,487 +11,591 +Sales from natural gas marketing +63 +114 +580 +Cost of natural gas marketing +— +— +23 +Changes in fair value included in balance sheet line item (1): +Accounts receivable affiliates +— +49 +231 +Accounts payable affiliates +(319 +) +(454 +) +(1,737 +) +Settlements included in statement of operations line items: +Commodity price risk management loss, net +(15,644 +) +(1,712 +) +(14,467 +) +Sales from natural gas marketing +(114 +) +(139 +) +(484 +) +Cost of natural gas marketing +— +— +(23 +) +Fair value, net asset end of year +$ +13,669 +$ +22,107 +$ +10,762 +Changes in unrealized gains (losses) relating to assets (liabilities) still held +as of year-end, included in statement of operations line item: +Commodity price risk management gain, net +$ +3,665 +$ +11,669 +$ +9,594 +Sales from natural gas marketing +1 +(3 +) +54 +Total +$ +3,666 +$ +11,666 +$ +9,648 +__________ +(1) +Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. +Non-Derivative Financial Assets and Liabilities +The carrying values of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. +F- 13 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The portion of our long-term debt related to our revolving credit facility, as well as our proportionate share of PDCM's credit facility, approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our long-term debt related to our senior notes under the fair value option; however, as of December 31, 2012 , we estimate the fair value of the portion of our long-term debt related to the 3.25% convertible senior notes due 2016 to be $125.3 million , or 109% of par value, and the portion related to our 7.75% senior notes due 2022 to be $512.8 million , or 102.6% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. +See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Natural Gas and Crude Oil Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities. +NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for natural gas, NGLs and crude oil. To manage a portion of our exposure to price volatility from producing natural gas and crude oil, we utilize the following economic hedging strategies for each of our business segments. +• +For natural gas and crude oil sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and +• +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2012 , we had derivative instruments in place for a portion of our anticipated production through 2016 for a total of 68,853 BBtu of natural gas and 3,754 MBbls of crude oil. +As of December 31, 2012 , our derivative instruments were comprised of commodity floors, collars and swaps, basis protection swaps and physical sales and purchases. +• +Floor options (puts) are arrangements where, if the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed put strike price, then no payment is due from us to the counterparty; +• +Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which have negative differentials to NYMEX, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and +• +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +F- 14 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the location and fair value amounts of our derivative instruments on the balance sheets as of December 31, 2012 and 2011 : +Derivatives instruments: +Balance sheet line item +2012 +2011 +(in thousands) +Derivative assets: +Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +$ +47,016 +$ +51,220 +Related to affiliated partnerships (1) +Fair value of derivatives +4,707 +8,018 +Related to natural gas marketing +Fair value of derivatives +302 +1,528 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +17 +43 +52,042 +60,809 +Non Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +6,671 +34,938 +Related to affiliated partnerships (1) +Fair value of derivatives +— +6,134 +Related to natural gas marketing +Fair value of derivatives +203 +103 +Basis protection contracts +Related to natural gas marketing +Fair value of derivatives +9 +— +6,883 +41,175 +Total derivative assets +$ +58,925 +$ +101,984 +Derivative liabilities: +Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +$ +1,744 +$ +7,498 +Related to affiliated partnerships (2) +Fair value of derivatives +— +211 +Related to natural gas marketing +Fair value of derivatives +226 +1,384 +Basis protection contracts +Related to natural gas and crude oil sales +Fair value of derivatives +14,329 +15,762 +Related to affiliated partnerships (2) +Fair value of derivatives +2,140 +3,116 +Related to natural gas marketing +Fair value of derivatives +— +3 +18,439 +27,974 +Non Current +Commodity contracts +Related to natural gas and crude oil sales +Fair value of derivatives +9,969 +4,357 +Related to affiliated partnerships (2) +Fair value of derivatives +— +113 +Related to natural gas marketing +Fair value of derivatives +168 +93 +Basis protection contracts +Related to natural gas and crude oil sales +Fair value of derivatives +— +13,820 +Related to affiliated partnerships (2) +Fair value of derivatives +— +2,723 +10,137 +21,106 +Total derivative liabilities +$ +28,576 +$ +49,080 +__________ +(1) +Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding payable to our affiliated partnerships representing their proportionate share of the derivative assets. +(2) +Represents derivative positions designated to our affiliated partnerships. Accordingly, our accompanying balance sheets include a corresponding receivable from our affiliated partnerships representing their proportionate share of the derivative liabilities. +F- 15 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our statements of operations: +Year Ended December 31, +2012 +2011 +2010 +Statement of operations line item +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +Reclassification +of Realized +Gains (Losses) +Included in Prior Periods +Unrealized +Realized and Unrealized +Gains +(Losses) For +the +Current +Period +Total +(in thousands) +Commodity price risk management gain (loss), net +Realized gains +$ +28,819 +$ +20,597 +$ +49,416 +$ +10,329 +$ +6,914 +$ +17,243 +$ +20,148 +$ +26,947 +$ +47,095 +Unrealized gains (losses) +(28,819 +) +11,742 +(17,077 +) +(10,329 +) +39,176 +28,847 +(20,148 +) +32,944 +12,796 +Total commodity price risk management gain, net +$ +— +$ +32,339 +$ +32,339 +$ +— +$ +46,090 +$ +46,090 +$ +— +$ +59,891 +$ +59,891 +Sales from natural gas marketing +Realized gains +$ +1,571 +$ +599 +$ +2,170 +$ +1,827 +$ +1,143 +$ +2,970 +$ +2,390 +$ +3,991 +$ +6,381 +Unrealized gains (losses) +(1,571 +) +(87 +) +(1,658 +) +(1,827 +) +1,666 +(161 +) +(2,390 +) +1,745 +(645 +) +Total sales from natural gas marketing +$ +— +$ +512 +$ +512 +$ +— +$ +2,809 +$ +2,809 +$ +— +$ +5,736 +$ +5,736 +Cost of natural gas marketing +Realized losses +$ +(1,387 +) +$ +(642 +) +$ +(2,029 +) +$ +(1,441 +) +$ +(1,130 +) +$ +(2,571 +) +$ +(1,905 +) +$ +(3,996 +) +$ +(5,901 +) +Unrealized gains (losses) +1,387 +214 +1,601 +1,441 +(1,526 +) +(85 +) +1,905 +(1,431 +) +474 +Total cost of natural gas marketing +$ +— +$ +(428 +) +$ +(428 +) +$ +— +$ +(2,656 +) +$ +(2,656 +) +$ +— +$ +(5,427 +) +$ +(5,427 +) +NOTE 5 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2012 +2011 +(in thousands) +Natural gas, NGLs and crude oil sales +$ +39,837 +$ +42,388 +Natural gas marketing +8,209 +6,225 +Reimbursements for title defects +7,579 +— +Joint interest billings +6,896 +7,465 +Other +3,385 +4,766 +Allowance for doubtful accounts +(1,026 +) +(921 +) +Accounts receivable, net +$ +64,880 +$ +59,923 +Our accounts receivable primarily relates to sales of our natural gas, NGLs and crude oil production, derivative counterparties and other third parties that own working interests in the properties we operate. Inherent to our industry is the concentration of natural gas, NGLs and crude oil sales to a limited number of customers. This industry concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. Our estimate of uncollectible amounts changes periodically. For the each of the years in the three-year period ended December 31, 2012 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2012 , we had two customers representing 10% or greater of our accounts receivable balance: Suncor Energy Marketing and Merit Energy, representing 26.4% and 11.7% , respectively, of our accounts receivable balance. The $7.6 million of accounts receivable at December 31, 2012 due from Merit Energy related to reimbursements for title defects discovered subsequent to our acquisition of certain Wattenberg assets from affiliates of Merit Energy (the "Merit Acquisition"). The reimbursement for certain title defects was received in January 2013. +F- 16 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: +Year Ended December 31, +Customer +2012 +2011 +2010 +Suncor Energy Marketing, Inc. +29.8 +% +25.7 +% +19.6 +% +DCP Midstream, LP +12.2 +% +11.5 +% +9.6 +% +WPX Energy Rocky Mountain, LLC +5.6 +% +9.9 +% +12.5 +% +Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing natural gas and crude oil. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments was not significant. +The following table presents the counterparties that expose us to credit risk as of December 31, 2012 , with regard to our derivative assets: +Fair Value of +Derivative Assets +Counterparty Name +As of December 31, 2012 +(in thousands) +JPMorgan Chase Bank, N.A. (1) +$ +41,323 +Wells Fargo Bank, N.A. (1) +4,782 +Bank of Nova Scotia (1) +4,315 +Other lenders in our revolving credit facility +8,146 +Various (2) +359 +Total +$ +58,925 +____________ +(1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt. +(2) Represents a total of 28 counterparties. +NOTE 6 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization: +As of December 31, +2012 +2011 +(in thousands) +Properties and equipment, net: +Natural gas and crude oil properties +Proved +$ +2,075,924 +$ +1,694,694 +Unproved +319,327 +102,466 +Total natural gas and crude oil properties +2,395,251 +1,797,160 +Pipelines and related facilities +47,786 +40,721 +Transportation and other equipment +34,858 +32,475 +Land and buildings +14,935 +14,572 +Construction in progress +67,217 +69,633 +Gross properties and equipment +2,560,047 +1,954,561 +Accumulated depreciation, depletion and amortization +(943,341 +) +(652,845 +) +Properties and equipment, net +$ +1,616,706 +$ +1,301,716 +F- 17 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents impairment charges recorded for natural gas and crude oil properties: +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Continuing operations: +Impairment of proved properties +$ +161,185 +$ +22,460 +$ +— +Impairment of individually significant unproved properties +1,943 +1,108 +1,477 +Amortization of individually insignificant unproved properties +5,021 +1,591 +5,004 +Total continuing operations +168,149 +25,159 +6,481 +Discontinued operations: +Impairment of proved properties +— +— +4,666 +Total discontinued operations +— +— +4,666 +Total impairment of natural gas and crude oil properties +$ +168,149 +$ +25,159 +$ +11,147 +In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on estimated future cash flows from an unrelated third-party bid, a Level 3 input, as we changed our development plans in the basin and decided to sell the related assets. The impairment charge was included in the statement of operations line item impairment of natural gas and crude oil properties. See Note 19, Subsequent Events , for additional information regarding the planned sale of certain of our oil and natural gas properties. +In 2011, we recognized an impairment charge of $22.5 million to write-down our NECO assets to fair value. The fair value was based on unrelated third-party bids, a level 3 input. The impairment charge was included in the statement of operations' line item impairment of natural gas and crude oil properties. +In May 2010, pursuant to our entry into an agreement to sell our Michigan assets, we reclassified our Michigan assets as held for sale. We compared the transactional sales price, considered a Level 3 input, less costs to sell to the carrying value of our Michigan net assets. The net carrying value exceeded the net sales price and, therefore, during the second quarter of 2010, we recognized a pre-tax impairment charge of $4.7 million to reduce the carrying value of the net assets to reflect the net sales price. The impairment charge was included in discontinued operations on the statement of operations. See Note 14, Assets Held for Sale, Divestitures, and Discontinued Operations. +Suspended Well Costs +The following table presents the capitalized exploratory well costs pending determination of proved reserves, and included in properties and equipment on the balance sheets: +2012 +2011 +2010 +(in thousands, except for number of wells) +Balance beginning of year, January 1, +$ +4,432 +$ +2,297 +$ +1,174 +Additions to capitalized exploratory well costs pending the determination of proved reserves +30,482 +3,692 +4,353 +Reclassifications to wells, facilities and equipment based on the determination of proved reserves +— +(1,557 +) +(2,231 +) +Deconsolidation of PDCM and change in ownership interest +— +— +(462 +) +Capitalized exploratory well costs charged to expense +(15,347 +) +— +(537 +) +Balance end of year, December 31, +$ +19,567 +$ +4,432 +$ +2,297 +Number of wells pending determination at December 31, +2 +6 +3 +Additions to capitalized exploratory well costs pending determination of proved reserves increased in 2012 as compared to prior years as we increased our exploratory drilling activities in the liquid-rich emerging Utica Shale play. +In 2012, capitalized well costs related to two vertical stratigraphic test wells in eastern Ohio were expensed at a cost of $12.2 million. Additionally, three wells in south central Ohio and a well in southeast Colorado were determined to have noncommercial quantities of hydrocarbons and were expensed at a cost of $1.2 million and $0.9 million, respectively. +F- 18 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents an aging of capitalized exploratory well costs based on the date that drilling commenced and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the commencement of drilling: +As of December 31, +2012 +2011 +2010 +(in thousands) +Exploratory well costs capitalized for a period of one year or less +$ +19,567 +$ +3,587 +$ +2,297 +Exploratory well costs capitalized for a period greater than one year since commencement of drilling +— +845 +— +Balance end of year, December 31, +$ +19,567 +$ +4,432 +$ +2,297 +Number of projects with exploratory well costs that have been capitalized for a period greater than one year since commencement of drilling +— +2 +— +NOTE 7 - INCOME TAXES +The table below presents the components of our provision for income taxes from continuing operations for the years presented: +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Current: +Federal +$ +— +$ +3,172 +$ +1,616 +State +(199 +) +172 +(904 +) +Total current income taxes +(199 +) +3,344 +712 +Deferred: +Federal +78,425 +(2,868 +) +(3,990 +) +State +10,609 +(293 +) +2,626 +Total deferred income taxes +89,034 +(3,161 +) +(1,364 +) +Provision for income taxes from continuing operations +$ +88,835 +$ +183 +$ +(652 +) +We continue to utilize tax deferral strategies such as bonus and accelerated depreciation, IRC Section 1031 like-kind exchange strategies and intangible drilling cost expense elections to minimize our current taxes. As a result of these elections and deferral strategies, we have generated federal and state net operating losses (“NOLs”) in 2012, 2011 and 2010. Substantially, all the 2010 federal NOL was carried back to 2008, generating a refund of $4.6 million which was received in the fourth quarter of 2011. The remaining federal NOLs and substantially all the state NOLs are being carried forward to 2013 and/or future periods. We expect to utilize our federal NOL and a substantial portion of our state NOLs to offset the projected 2013 taxable gain on the planned sale of our non-core Colorado assets. See Note 19, Subsequent Events , for additional information regarding the planned sale. There can be no assurance we will be successful in closing such divestiture. +F- 19 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: +Year Ended December, 31, +2012 +2011 +2010 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +2.9 +(9.4 +) +1.3 +Percentage depletion +0.3 +(29.5 +) +(11.3 +) +Non-deductible compensation +(0.1 +) +— +4.4 +Non-deductible meals and entertainment +(0.1 +) +3.1 +1.2 +State deferred rate change +— +15.4 +(26.2 +) +Unrecognized tax benefits +— +(30.3 +) +2.4 +State tax credits +— +— +(3.3 +) +Federal return examination adjustments +— +4.2 +4.7 +Return to provision adjustments +— +3.7 +— +Other +— +1.5 +1.5 +Effective tax rate +38.0 +% +(6.3 +)% +9.7 +% +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2012 and 2011 are presented below: +As of December 31, +2012 +2011 +(in thousands) +Deferred tax assets: +Provision for underpayment of natural gas sales +$ +— +$ +3,334 +Deferred compensation +7,216 +4,319 +Asset retirement obligations +10,325 +9,438 +State NOL and tax credit carryforwards, net +6,117 +5,240 +Percentage depletion - carryforward +4,702 +3,733 +Alternative minimum tax - credit carryforward +2,351 +2,351 +Federal NOL carryforward +21,281 +12,210 +Other +2,276 +2,621 +Deferred tax assets +54,268 +43,246 +Deferred tax liabilities: +Properties and equipment +122,742 +184,657 +Investment in PDCM +31,445 +30,919 +Unrealized gains - derivatives +7,163 +12,612 +Convertible debt +5,194 +6,504 +Total gross deferred tax liabilities +166,544 +234,692 +Net deferred tax liability +$ +112,276 +$ +191,446 +Classification in the balance sheets: +Deferred income tax assets +$ +36,151 +$ +16,127 +Deferred income tax liability +148,427 +207,573 +Net deferred tax liability +$ +112,276 +$ +191,446 +Deferred tax liabilities for properties and equipment decreased in 2012 primarily as a result of our impairment of certain oil and gas properties, which is an expense not currently deductible from taxable income, partially offset by our continued use of statutory provisions for bonus and accelerated tax depreciation. In addition, a tax gain, previously deferred through the use of IRC Section 1031 LKE strategies, was recognized upon the sale of our Permian Basin assets. +As of December 31, 2012 , we have state NOL carryforwards of $142.4 million that begin to expire in 2029 , state credit carryforwards of $1.8 million that begin to expire in 2022 and federal NOL carryforwards of $60.8 million that will expire in 2030 . Approximately $0.9 million +F- 20 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +of excess tax benefits relating to stock-based compensation that are a component of our NOL carryforwards, when realized, will be credited to APIC. +The following table presents a reconciliation of the total amounts of unrecognized tax benefits: +2012 +2011 +2010 +(in thousands) +Balance beginning of year, January 1 +$ +179 +$ +1,093 +$ +566 +Additions for tax positions of prior years +— +— +253 +Additions for tax positions of current year +— +— +274 +Reductions due to settlements +— +(782 +) +— +Reductions due to lapse of statute of limitations +— +(132 +) +— +Balance end of year, December 31 +$ +179 +$ +179 +$ +1,093 +Interest and penalties related to uncertain tax positions are recognized in income tax expense. Accrued interest and penalties related to uncertain tax positions were immaterial for each of the years in the three-year period ended December 31, 2012 . The total amount of unrecognized tax benefits that would affect the effective tax rate, if recognized, was $0.2 million as of December 31, 2012 and December 31, 2011 , respectively. As of December 31, 2012 , we expect a decrease in the unrecognized tax benefit in the next twelve months due to statute of limitation expiration. During 2012, we did not reduce our liability for any uncertain tax benefits, of which the remaining balance is related to our state tax filings, as no prior tax positions were resolved, nor did we have any new uncertain tax benefits arise during the year. The statute of limitation for most of our state tax jurisdictions is open from 2008 forward. +In accordance with the Compliance Assurance Process ("CAP"), the IRS completed its “post filing review” of our 2010 tax return in January 2012 and completed their “post filing review” of our 2011 tax return in January 2013. We have been issued a “no change” letter for both of the reviewed tax years. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the IRS CAP program for the review of our 2012 tax year and we have been invited and have accepted continued participation in the program for our 2013 tax year. Participation in the IRS CAP program has enabled us to currently have no uncertain tax benefits associated with our federal tax return filings. During 2011, we were able to reduce our liability for uncertain tax benefits upon accelerated examination and settlement of our 2007-2009 tax years upon entering the IRS program. +F- 21 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2012 +2011 +(in thousands) +Senior notes +3.25% Convertible senior notes due 2016: +Principal amount +$ +115,000 +$ +115,000 +Unamortized discount +(13,671 +) +(17,079 +) +3.25% Convertible senior notes due 2016, net of discount +101,329 +97,921 +7.75% Senior notes due 2022: +Principal amount +500,000 +— +12% Senior notes due 2018: +Principal amount +— +203,000 +Unamortized discount +— +(1,764 +) +12% Senior notes due 2018, net of discount +— +201,236 +Total senior notes +601,329 +299,157 +Credit facilities +Corporate +49,000 +209,000 +PDCM +26,250 +24,000 +Total credit facilities +75,250 +233,000 +Total long-term debt +$ +676,579 +$ +532,157 +Senior Notes +3.25% Convertible Senior Notes Due 2016. In November 2010 , we issued $115 million of 3.25% convertible senior notes due 2016 (the "2016 Convertible Senior Notes") in a private placement to qualified institutional buyers. The convertible notes and the common stock issuable upon conversion of the convertible notes, if any, have not been registered under the Securities Act of 1933 ("Securities Act") or any state securities laws, nor are we required to register such convertible notes or common shares. The convertible notes are governed by an indenture dated November 23, 2010, between the Company and the Bank of New York Mellon, as trustee. The maturity for the payment of principal is May 15, 2016 . Interest at the rate of 3.25% per year is payable in cash semiannually in arrears on each May 15 and November 15 , commencing on May 15, 2011 . The convertible notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the convertible notes; equal in right of payment to our existing and future unsecured indebtedness that is not so subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our senior secured credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the convertible notes does not contain any restrictive financial covenants. +We may not redeem the convertible notes prior to the maturity date of the convertible notes. However, prior to November 15, 2015 , holders of the convertible notes may convert upon specified events and periods as defined in the governing indenture. The notes are convertible at any time thereafter at an initial conversion rate of 23.5849 per $1,000 principal amount of the convertible notes, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the convertible notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the $1,000 principal amount of the convertible notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. +We allocated the gross proceeds of the convertible notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued our convertible notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the convertible notes. As of December 31, 2012 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the convertible notes of 3.4 years using an effective interest rate of 7.4% . For 2012 , interest expense related to the indebtedness and the amortization of the discount were $3.7 million and $3.4 million , respectively, compared to $3.7 million and $3.2 million , respectively, in 2011 . As of December 31, 2012 and 2011 , notwithstanding the inability to convert, assuming conversion, the value of the convertible notes did not exceed the principal amount. +F- 22 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +7.75% Senior Notes Due 2022. On October 3, 2012 , we issued $500 million aggregate principal amount of 7.75% senior notes due October 15, 2022 (the “2022 Senior Notes”) in a private placement. The proceeds from the issuance of the notes, after the initial purchasers' commissions and estimated offering expenses, were used to fund the redemption of our 2018 Senior Notes, repay a portion of the amount outstanding under our revolving credit facility and for general corporate purposes. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 , commencing on April 15, 2013 . Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness (including our 2016 Convertible Senior Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility. +In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2022 Senior Notes for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2022 Senior Notes by holders. +At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. +At any time prior to October 15, 2015 , we may redeem up to 35% of the outstanding 2022 Senior Notes with proceeds from certain equity offerings at a redemption price of 107.75% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as: +• +at least 65% of the aggregate principal amount of the notes issued on October 3, 2012 remains outstanding after each such redemption; and +• +the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. +12% Senior Notes Due 2018. On October 3, 2012 , we issued a notice to redeem on November 2, 2012 the entire $203 million principal amount of the 12% senior notes due 2018 (the "2018 Senior Notes") for a total redemption price of approximately $222 million , including an $18.9 million make-whole premium. The make-whole provision was based upon terms set forth in the related indenture. On November 2, upon the redemption of the 2018 Senior Notes, the $18.9 million make-whole premium, remaining unamortized debt discount of $1.5 million and unamortized debt issuance costs of $2.9 million were recognized as a $23.3 million pre-tax loss on debt extinguishment in the consolidated statement of operations. The amount paid to bond holders for the make-whole premium has been included as a financing activity in our statement of cash flows. +Credit Facilities +Revolving Credit Facility. In November 2010 , we obtained a revolving credit facility pursuant to a Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The maximum facility amount is $600 million . As of December 31, 2012 , we had $49 million outstanding on our revolving credit facility, compared to $209 million as of December 31, 2011 . The borrowing base of the revolving credit facility will be the loan value assigned to the proved reserves attributable to our and our subsidiaries' natural gas and crude oil interests, excluding proved reserves attributable to PDCM and our 21 affiliated partnerships. Our revolving credit facility borrowing base is subject to a semiannual size redetermination based on quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of our and such subsidiaries' other assets. Neither PDCM nor the various limited partnerships that we have sponsored, and continue to serve as the managing general partner, are guarantors of the revolving credit facility. +On October 31, 2012, the semi-annual redetermination of our revolving credit facility's borrowing base was completed with our available borrowing base being reduced from $525 million to $450 million as a result of the 2022 Senior Notes issuance. On September 21, 2012 , we entered into a Sixth Amendment to the revolving credit facility. The Sixth Amendment increased the amount of senior note +F- 23 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +indebtedness and refinancing indebtedness permitted under the revolving credit agreement. On June 29, 2012, concurrent with the Merit Acquisition, we entered into a Fifth Amendment to our revolving credit facility. The Fifth Amendment increased our available borrowing base to $525 million from $425 million based on our natural gas and crude oil reserves as of December 31, 2011 and the estimated reserves as of April 1, 2012 for the acquired assets from the Merit Acquisition. On June 25, 2012, we entered into the Fourth Amendment to our revolving credit facility. The Fourth Amendment amended certain provisions of the revolving credit facility to allow us greater flexibility in entering into hedging transactions in connection with future potential asset acquisitions. On May 4, 2012, we entered into the Third Amendment to our revolving credit facility and, as a result of the semi-annual redetermination by our bank group, our borrowing base was increased by $25 million to $425 million . +Our outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015 , or in the event that the borrowing base would fall below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and maintaining certain financial ratios on a quarterly basis. The financial tests and ratios, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.00 to 1.00. +The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the 2016 Convertible Senior Notes. Among other things, the restriction on redemption of the 2016 Convertible Senior Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. +We have outstanding an $18.7 million irrevocable standby letter of credit in favor of a third-party transportation service provider to secure the construction of certain additions and/or replacements to its facilities to provide firm transportation of the natural gas produced by us and others for whom we market production in West Virginia and Southwestern Pennsylvania. The letter of credit reduces the amount of available funds under our revolving credit facility by an equal amount. We pay a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans ( 2.75% per annum as of December 31, 2012 ) for the period in which the letter of credit remains outstanding. The letter of credit expires on July 20, 2013. We expect to renew the letter of credit prior to its expiration. +We pay a fee of 0.5% per annum on the unutilized commitment on the available funds under our revolving credit facility. As of December 31, 2012 , the available funds under our revolving credit facility, including a reduction for the $18.7 million irrevocable standby letter of credit in effect, was $382.3 million . The weighted-average borrowing rate on our revolving credit facility, exclusive of the letter of credit, was 4.5% per annum as of December 31, 2012 compared to 3.8% as of December 31, 2011 . +PDCM Credit Facility. PDCM has a credit facility dated April 30, 2010 , as amended, with an aggregate revolving commitment or borrowing base of $80 million , of which our proportionate share is $40 million . The maximum allowable facility amount is $400 million . Based upon PDCM's discretion, interest accrues at either an alternative base rate ("ABR") or an adjusted LIBOR. The ABR is the greater of BNP Paribas' prime rate, the federal funds effective rate plus 0.5% or the adjusted LIBOR for a three month interest period plus 1%. ABR and adjusted LIBOR borrowings are assessed an additional margin based upon the outstanding balance as a percentage of the available balance. ABR borrowings are assessed an additional margin of 1.25% to 2.0%. Adjusted LIBOR borrowings are assessed an additional margin spread of 2.25% to 3.0%. No principal payments are required until the credit agreement expires on April 30, 2014 , or in the event that the borrowing base falls below the outstanding balance. The credit facility is subject to and secured by PDCM's properties, including our proportionate share of such properties. The credit facility borrowing base is subject to size redetermination semiannually based upon a valuation of PDCM's reserves at June 30 and December 31. Either PDCM or the lenders may request a redetermination upon the occurrence of certain events. Pursuant to the interests of the joint venture, the credit facility will be utilized by PDCM for the exploration and development of its Marcellus assets. +The credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests and financial ratios that must be met on a quarterly basis. The financial tests and ratios, as defined by the credit facility, include requirements to maintain a minimum current ratio of 1.0 to 1.0, not to exceed a debt to EBITDAX ratio of 5.0 to 1.0 (declining to 4.5 to 1.0 on March 31, 2013 and 4.0 to 1.0 on September 30, 2013) and to maintain a minimum interest coverage ratio of 2.5 to 1.0. As of December 31, 2012 , our proportionate share of PDCM's outstanding credit facility balance was $26.3 million compared to $24 million as of December 31, 2011 . PDCM is required to pay a commitment fee of 0.5% per annum on the unutilized portion of the activated credit facility. The weighted-average borrowing rate on PDCM's credit facility was 3.5% per annum in 2012 , compared to 5.0% in 2011 . +As of December 31, 2012 , we were in compliance with all credit facility covenants and expect to remain in compliance throughout the next twelve-month period. +F- 24 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 9 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in natural gas and crude oil properties: +2012 +2011 +(in thousands) +Balance beginning of year, January 1 +$ +46,566 +$ +28,047 +Obligations incurred with development activities and assumed with acquisitions +14,169 +9,625 +Accretion expense +4,060 +1,897 +Obligations discharged with disposal of properties and asset retirements +(2,232 +) +(990 +) +Deconsolidation of PDCM and change in ownership interest +— +(916 +) +Revisions in estimated cash flows +— +8,903 +Balance end of year, December 31 (1) +62,563 +46,566 +Less current portion +(1,000 +) +(250 +) +Long-term portion +$ +61,563 +$ +46,316 +__________ +(1) +Includes $2 million as of December 31, 2011 related to assets held for sale. +The revisions in estimated cash flows during 2011 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells in the two fields where we currently conduct the majority of our operations. These cost increases related mostly to the costs of cement and construction materials and third-party and internal support services on a per well basis. The revision in the asset retirement obligation did not have an immediate effect in the 2011 statement of operations as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells. +NOTE 10 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $3.4 million for 2012 and $2.6 million for 2011 and 2010 , respectively. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2012 , 2011 and 2010 . As of December 31, 2012 and 2011 , the liability related to this benefit was $2 million and $2.2 million , respectively, which was included in other liabilities on the balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2012 and 2011 . +We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2012 , 2011 and 2010 related to this plan were immaterial. As of December 31, 2012 and 2011 , the related liability of $0.7 million is included in other liabilities on the balance sheets. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the balance sheets, was immaterial as of December 31, 2012 and 2011 . +NOTE 11 - COMMITMENTS AND CONTINGENCIES +Firm Transportation Agreements. We enter into contracts that provide firm transportation, sales and processing charges on pipeline systems through which we transport or sell natural gas. Satisfaction of the volume requirements includes volumes produced by us, volumes purchased from third parties and volumes produced by PDCM, our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges whether the required volumes are delivered or not. With the exception of contracts entered into by PDCM, the costs of any volume shortfalls are borne by PDC. +F- 25 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information, including our proportionate share of PDCM, related to our long-term firm transportation, sales and processing agreements for pipeline capacity: +Year Ending December 31, +Area +2013 +2014 +2015 +2016 +2017 +Through +Expiration +Total +Expiration +Date +Volume (MMcf) +Piceance Basin +30,710 +36,168 +30,603 +26,053 +85,895 +209,429 +May 31, 2021 +Appalachian Basin +20,316 +24,353 +23,361 +24,862 +168,296 +261,188 +September 20, 2025 +NECO +2,190 +1,825 +1,825 +1,825 +— +7,665 +December 31, 2016 +Total +53,216 +62,346 +55,789 +52,740 +254,191 +478,282 +Dollar commitment +(in thousands) +$ +25,756 +$ +29,283 +$ +26,163 +$ +24,075 +$ +94,033 +$ +199,310 +Effective January 1, 2013, we entered into a new gas gathering and processing agreement with Williams Field Services Company related to our Piceance Basin production. The new agreement included additional terms and conditions which, among other things, reduced our Piceance Basin total committed volumes for gathering to 116,260 MMcf over the term of the agreement. In February 2013, we entered into a purchase and sale agreement pursuant to which our Piceance Basin and NECO firm gathering commitments will be assumed by the buyer of certain of our oil and natural gas properties upon the closing of the transaction. There can be no assurance that we will be successful in closing such divestiture. See Note 19, Subsequent Events , for additional information regarding the planned sale. +Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Alleged Class Action Filed Regarding 2010 and 2011 Partnership Purchases +On December 21, 2011 the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of certain former partnership unit holders, related to its partnership repurchases completed by mergers in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California, and is titled Schulein v. Petroleum Development Corp . The complaint primarily alleges a claim that the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. On February 10, 2012, the Company filed a motion to dismiss or in the alternative to stay. On June 15, 2012, the Court denied the motion. The Court has approved a litigation schedule including a jury trial in May 2014. We have not recorded a liability for claims pending because we believe we have good legal defenses to the asserted claims and because the plaintiffs have not specified damages and it is not possible for management to estimate what, if any, monetary damages could result from this claim. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2012 and December 31, 2011 , we had accrued environmental liabilities in the amount of $8.4 million and $2.5 million , respectively, included in other accrued expenses on the balance sheet. The increase in accrued liabilities at December 31, 2012 primarily relates to the assumption of environmental liabilities related to the Merit Acquisition. We are not aware of any environmental claims existing as of December 31, 2012 which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. +Partnership Repurchase Provision. Substantially all of our drilling programs contain a repurchase provision where investing partners may request that we purchase their partnership units at any time beginning with the third anniversary of the first cash distribution. The provision provides that we are obligated to purchase an aggregate of 10% of the initial subscriptions per calendar year (at a minimum price of four times the most recent 12 months' cash distributions from production), if repurchase is requested by investors, subject to our financial ability to do so. As of December 31, 2012 , the maximum annual repurchase obligation for 2013, based upon the minimum price described above, was approximately $2.9 million . We believe we have adequate liquidity to meet this potential obligation. During 2012 , 2011 and 2010 , we paid $0.5 million , $0.2 million and $0.6 million , respectively, under this provision for the repurchase of partnership units. +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. +F- 26 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2012 : +Year Ending December 31, +2013 +2014 +2015 +2016 +2017 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +2,607 +$ +2,386 +$ +1,929 +$ +461 +$ +255 +$ +887 +$ +8,525 +Operating lease expense for the years ended 2012 , 2011 and 2010 was $6.1 million , $5.9 million and $4.9 million , respectively. +Employment Agreements with Executive Officers . Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company. +See Note 17, Transactions With Affiliates , for a discussion related to the separation agreement entered into with our former chief executive officer in 2011. +NOTE 12 - COMMON STOCK +Sale of Equity Securities +In May 2012 , we completed a public offering of 6,500,000 shares of our common stock, par value $0.01 per share, at an offering price of $26.50 per share. Net proceeds of the offering were approximately $164.5 million , after deducting underwriting discounts and commissions and offering expenses, of which $65,000 is included in common shares-par value and $164.4 million is included in APIC on the balance sheet as of December 31, 2012 . We used the net proceeds from the offering to finance a portion of the Merit Acquisition and for general corporate purposes. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on January 23, 2012. +In November 2010 , we sold 4,140,000 shares of our common stock in an underwritten public offering at a price of $32.00 per share. The net proceeds of $125.5 million were used, together with other proceeds, to fund an acquisition of additional assets in the Wolfberry Trend in the Permian Basin of West Texas, which closed in November 2010 , our acquisition of the 2004 and 2005 partnerships and other acquisitions and for general corporate purposes. Pending such uses, we applied the net proceeds from this offering and other proceeds to temporarily repay the entire outstanding amount under our revolving credit facility, with the remaining balance being deposited in an interest bearing account and held as cash and cash equivalents until utilized as contemplated above. The offering was made pursuant to an effective shelf registration statement on Form S-3 filed with the SEC on November 26, 2008. +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan. In June 2010 , our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). In accordance with the 2010 Plan, up to 1,400,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event, may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2012 , 490,412 shares remain available for issuance pursuant to the 2010 Plan. +2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004 , we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We no longer issue awards pursuant to the 2004 Plan. All outstanding and non-vested awards pursuant to the 2004 Plan will continue to be outstanding and vest pursuant to their original terms on or before April 19, 2020. +F- 27 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2012 +2011 (1) +2010 +(in thousands) +Stock-based compensation expense +$ +8,495 +$ +8,781 +$ +5,314 +Income tax benefit +(3,245 +) +(3,344 +) +(2,019 +) +Net expense +$ +5,250 +$ +5,437 +$ +3,295 +__________ +(1) Includes a $2.5 million pre-tax charge related to a separation agreement with our former chief executive officer. See Note 17, Transactions with Affiliates, for additional information regarding the related separation agreement. +Stock Option Awards +We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period. We have not issued any new stock options awards since 2006. As of December 31, 2012 , all compensation cost related to stock options has been fully recognized in our statements of operations. +The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial: +Year Ended December 31, +2012 +2011 +2010 +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Weighted- Average +Remaining +Contractual +Term (in years) +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Outstanding beginning of year, January 1, +6,973 +$ +41.09 +— +10,306 +$ +41.90 +10,306 +$ +41.90 +Forfeited +— +— +— +(3,333 +) +43.60 +— +— +Outstanding end of year, December 31, +6,973 +41.09 +2.6 +6,973 +41.09 +10,306 +41.90 +Exercisable at December 31, +6,973 +41.09 +2.6 +6,973 +41.09 +10,306 +41.60 +SARs +The SARs vest ratably over a three-year period and may be exercised at any point after vesting through 10 years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +In January 2012, the Compensation Committee awarded 68,361 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2012 +2011 +2010 +Expected term of award +6 years +6 years +5 years +Risk-free interest rate +1.1 +% +2.5 +% +2.5 +% +Expected volatility +64.3 +% +60.2 +% +62.0 +% +Weighted-average grant date fair value per share +$ +17.61 +$ +25.22 +$ +13.26 +The expected life of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +F- 28 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in our SARs: +Year Ended December 31, +2012 +2011 +2010 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Outstanding beginning of year, January 1, +50,471 +$ +31.61 +8.6 +$ +341 +57,282 +$ +24.44 +$ +1,020 +— +$ +— +$ +— +Awarded +68,361 +30.19 +— +— +31,552 +43.95 +— +57,282 +24.44 +— +Exercised +— +— +— +— +(25,371 +) +24.44 +77 +— +— +— +Forfeited +— +— +— +— +(12,992 +) +43.95 +— +— +— +— +Outstanding end of year, December 31, +118,832 +30.80 +8.4 +486 +50,471 +31.61 +341 +57,282 +24.44 +1,020 +Exercisable at December 31, +27,458 +28.84 +7.5 +187 +10,636 +24.44 +114 +— +— +— +Total compensation cost related to SARs granted and not yet recognized in our statement of operations as of December 31, 2012 , was $1.0 million . The cost is expected to be recognized over a weighted-average period of 1.8 years. +Restricted Stock Awards +Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed. +In January 2012, the Compensation Committee awarded a total of 79,889 time-based restricted shares to our executive officers that vest ratably over three year period ending on January 16, 2015. +The following table presents the changes in non-vested time-based awards during 2012 : +Shares +Weighted-Average +Grant-Date +Fair Value +Non-vested at December 31, 2011 +527,801 +$ +29.29 +Granted +341,338 +26.59 +Vested +(186,205 +) +29.42 +Forfeited +(36,444 +) +28.20 +Non-vested at December 31, 2012 +646,490 +27.93 +As of/Year Ended December 31, +2012 +2011 +2010 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +5,950 +$ +9,030 +$ +3,219 +Total intrinsic value of time-based awards non-vested +21,470 +18,531 +22,211 +Market price per common share as of December 31, +33.21 +35.11 +42.25 +Weighted-average grant date fair value per share +26.59 +33.71 +25.04 +Total compensation cost related to non-vested time-based awards expected to vest and not yet recognized in our statements of operations as of December 31, 2012 was $11.5 million . This cost is expected to be recognized over a weighted-average period of 2.2 years. +Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. Generally, the market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +F- 29 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In January 2012, the Compensation Committee awarded a total of 30,541 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 14 peer companies. The shares are measured over a three-year period ending on December 31, 2014 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2012 +2011 +Expected term of award +3 years +3 years +Risk-free interest rate +0.3 +% +1.1 +% +Expected volatility +65.3 +% +74.2 +% +Weighted-average grant date fair value per share +$ +36.54 +$ +58.53 +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future +The following table presents the change in non-vested market-based awards during 2012 : +Shares +Weighted-Average +Grant-Date +Fair Value per Share +Non-vested at December 31, 2011 +43,081 +$ +42.05 +Granted +30,541 +36.54 +Forfeited +(32,926 +) +45.15 +Non-vested at December 31, 2012 +40,696 +39.22 +As of/Year Ended December 31, +2012 +2011 +2010 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +— +$ +366 +$ +— +Total intrinsic value of market-based awards non-vested +1,352 +1,513 +3,361 +Market price per common share as of December 31, +33.21 +35.11 +42.25 +Weighted-average grant date fair value per share +36.54 +58.53 +— +Total compensation cost related to non-vested market-based awards expected to vest and not yet recognized in our statement of operations as of December 31, 2012 was $0.9 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2004 Plan are retired, while those issued pursuant to the 2010 Plan are reissued to service awards. For shares that are retired, we first charge any excess of cost over the par value to additional paid-in-capital ("APIC") to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2012 , we acquired 44,576 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 14,471 shares were retired, 28,587 and 1,518 shares were reissued and are available for reissuance, respectively, pursuant to our 2010 Plan. +F- 30 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record on September 14, 2007 . A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire on September 11, 2017 . +Preferred stock +We are authorized, pursuant to shareholder approval in 2008 , to issue 50,000,000 shares of Company preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2012 , no preferred shares had been issued. +NOTE 13 - EARNINGS PER SHARE +Basic earnings per common share ("EPS") is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted EPS is similarly computed except that the denominator includes the effect, using the treasury stock method, of our unamortized portion of restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted-average diluted shares outstanding: +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Weighted-average common shares outstanding - basic +27,677 +23,521 +19,674 +Dilutive effect of share-based compensation: +Restricted stock +— +307 +119 +SARs +— +40 +21 +Non-employee director deferred compensation +— +3 +7 +Weighted-average common and common share equivalents outstanding - diluted +27,677 +23,871 +19,821 +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +694 +220 +204 +SARs +116 +22 +— +Stock options +7 +9 +10 +Non-employee director deferred compensation +3 +— +— +Total anti-dilutive common share equivalents +820 +251 +214 +For 2012, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive. +In November 2010, we issued 115,000 convertible senior notes, $1,000 principal amount per note, that give the holders the right to convert the aggregate principal amount into 2.7 million common shares at a conversion price of $42.40 per share. These convertible notes could have a dilutive impact on our earnings per share if the average market share price exceeds the $42.40 conversion price. The average market share price did not exceed the conversion price during 2012 , 2011 or 2010 . +F- 31 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS +Selected financial information . The tables below set forth selected financial information related to net assets divested, net assets related to discontinued operations and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold, net of liabilities, that were or are expected to be assumed by the purchaser. Net assets related to discontinued operations presents those assets that were or are expected to be sold, less liabilities that were or are expected to be assumed, by the purchaser, as well as all other related assets and liabilities, consisting of accounts receivable and production tax liability, which were not sold. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the statement of operations table presents the revenues and expenses that were reclassified from the specified statement of operations line items to discontinued operations. +The following table presents balance sheet data related to assets held for sale: +As of December 31, +2011 +Balance Sheet +Net Assets Held for Sale +Net Assets +Related to Discontinued Operations +(in thousands) +Assets +Current assets +Accounts receivable, net +$ +— +$ +3,198 +Oil inventory +— +89 +Total current assets +— +3,287 +Properties and equipment +168,218 +168,218 +Accumulated Depreciation, Depletion and Amortization +(19,969 +) +(19,969 +) +Total assets +$ +148,249 +$ +151,536 +Liabilities +Current liabilities +Accounts payable +— +1,907 +Production tax liability +— +262 +Total current liabilities +— +2,169 +Asset retirement obligation +2,022 +2,022 +Total liabilities +$ +2,022 +$ +4,191 +Net assets +$ +146,227 +$ +147,345 +F- 32 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents statement of operations data related to our discontinued operations: +Year Ended December 31, +Statements of Operations - Discontinued Operations +2012 +2011 +2010 +(in thousands) +Revenues +Natural gas, NGLs and crude oil sales +$ +4,456 +$ +27,552 +$ +11,130 +Sales from natural gas marketing +— +— +3,328 +Well operations, pipeline income and other +34 +128 +560 +Total revenues +4,490 +27,680 +15,018 +Costs, expenses and other +Production costs +1,668 +8,365 +4,215 +Cost of natural gas marketing +— +— +3,265 +Impairment of natural gas and crude oil properties +— +— +4,666 +Depreciation, depletion and amortization +— +6,247 +2,967 +Accretion of asset retirement obligations and other +— +200 +223 +Gain on sale of properties and equipment +(19,920 +) +(3,854 +) +— +Total costs, expenses and other +(18,252 +) +10,958 +15,336 +Income (loss) from discontinued operations +22,742 +16,722 +(318 +) +Provision for income taxes +(8,668 +) +(6,363 +) +214 +Income (loss) from discontinued operations, net of tax +$ +14,074 +$ +10,359 +$ +(104 +) +Permian Basin. During the fourth quarter of 2011, we completed the sale of our non-core Permian assets to unrelated third parties for a total of $13.2 million . Additionally, on December 20, 2011, we executed a purchase and sale agreement with COG Operating LLC (“COG”), a wholly owned subsidiary of Concho Resources Inc., an unrelated third-party, for the sale of our core Permian Basin assets for a sale price of $173.9 million , subject to customary terms and adjustments, including adjustments based on title and environmental due diligence to be conducted by COG. The effective date of the transaction was November 1, 2011. Following the sale to COG, we do not have significant continuing involvement in the operations of, or cash flows from, these assets; accordingly, the Permian assets were reclassified as held for sale as of December 31, 2011, and the results of operations related to those assets have been separately reported as discontinued operations in the consolidated statement of operations for all periods presented. On February 28, 2012, the divestiture closed. Upon final settlement, total proceeds received were $189.2 million after closing adjustments, resulting in a pre-tax gain on sale of $19.9 million . +North Dakota. In December 2010, we executed a letter of intent with an unrelated third-party for the sale of our North Dakota assets. In February 2011, we executed a purchase and sale agreement and subsequently closed with the same unrelated party. Proceeds from the sale were $9.5 million , net of our non-affiliated investor partners' share of $3.8 million , resulting in a pre-tax gain on sale of $3.9 million . Following the sale to the unrelated party, we do not have significant continuing involvement in the operations of, or cash flows from, these assets. Accordingly, the results of operations related to the North Dakota assets have been reported as discontinued operations in the consolidated statements of operations for 2011 and 2010. +Michigan . During the third quarter of 2010, we divested our Michigan asset group and related liabilities for net cash proceeds of $22 million and realized a loss on sale of $4.7 million in the form of an impairment charge recorded during 2010 (see Note 6, Properties and Equipment , regarding the impairment charge). We do not have significant continuing involvement in the operations of or cash flows from this asset group. Accordingly, the results of operations related to the Michigan assets have been reported as discontinued operations in the consolidated statement of operations for 2010. +See Note 19, Subsequent Events , for information regarding the planned sale of certain of our oil and natural gas properties. +F- 33 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 15 - ACQUISITIONS +The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of natural gas and crude oil properties during 2012 , 2011 and 2010 : +Year Ended December 31, +2012 +2011 +2010 +Merit (1) +Seneca-Upshur +2003/2002-D Partnerships +2005 Partnerships +Permian +2004 +Partnerships +(in thousands) +Total acquisition cost +$ +304,643 +$ +69,618 +$ +29,960 +$ +43,015 +$ +114,273 +$ +34,768 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Natural gas and crude oil properties - proved +$ +180,259 +$ +20,175 +$ +27,940 +$ +39,825 +$ +45,592 +$ +32,730 +Natural gas and crude oil properties - unproved +151,428 +49,100 +— +— +71,647 +— +Other assets +3,631 +10,196 +3,455 +3,848 +— +3,396 +Total assets acquired +335,318 +79,471 +31,395 +43,673 +117,239 +36,126 +Liabilities assumed: +Asset retirement obligation +13,870 +8,157 +497 +300 +2,351 +912 +Other accrued expenses +10,100 +— +— +— +615 +126 +Other liabilities +6,705 +1,696 +938 +358 +— +320 +Total liabilities assumed +30,675 +9,853 +1,435 +658 +2,966 +1,358 +Total identifiable net assets acquired +$ +304,643 +$ +69,618 +$ +29,960 +$ +43,015 +$ +114,273 +$ +34,768 +___________ +(1) Assets acquired and liabilities assumed in the Merit Acquisition are subject to post-closing adjustments as more detailed analyses are completed and additional information is obtained about the acquired natural gas and crude oil properties. +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are the most sensitive and subject to change. +2012 Acquisitions +Merit Acquisition. On June 29, 2012 , we completed the acquisition of certain Wattenberg Field oil and natural gas properties, leasehold mineral interests and related assets located in Weld, Adams and Boulder Counties, Colorado from affiliates of Merit Energy, an unrelated third-party. The aggregate purchase price of these properties was approximately $304.6 million , after post-closing adjustments. We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit facility. +This acquisition was accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. +Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 29, 2012 closing date, including approximately $11.4 million of total revenue and $9.5 million of income from operations. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 and December 31, 2011 , assuming the Merit Acquisition had been completed as of January 1, 2011, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results. +F- 34 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Year Ended December 31, +2012 +2011 +(in thousands, except per share amounts) +Total revenues +$ +370,488 +$ +438,204 +Total costs, expenses and other +521,178 +366,120 +Net income (loss) +$ +(119,343 +) +$ +45,688 +Earnings per share: +Basic +$ +(4.31 +) +$ +1.94 +Diluted +$ +(4.31 +) +$ +1.91 +2011 Acquisitions +Seneca-Upshur . In October 2011, PDCM acquired from an unrelated third-party 100% of the membership interests of Seneca-Upshur Petroleum, LLC ("Seneca-Upshur") for a purchase price of $139.2 million ( $69.6 million net to PDC), after post-closing adjustments, which was funded by capital contributions by PDCM's investing partners and a draw on PDCM's revolving credit facility. Substantially all of the acreage acquired is held by production, prospective for the Marcellus Shale and is in close proximity to PDCM's existing properties. Following the closing, several title defects were discovered that were not cured by the seller within the time specified by the purchase and sale agreement. Accordingly, PDCM received title defect payments during 2012 totaling $28.9 million , of which $14.5 million represents our share, the effect of which is reflected in the purchase price noted above. +2003/2002-D Partnerships . In October 2011, we acquired from non-affiliated investor partners the remaining working interest in five of our affiliated partnerships: PDC 2002-D Limited Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership and PDC 2003-C Limited Partnership and (the "2002/2003 Partnerships"). We purchased the 2002/2003 Partnerships for an aggregate amount of $30 million , which was funded from our revolving credit facility. These purchases included the non-affiliated investor partners' remaining working interests in wells located in the Wattenberg Field and Piceance Basin. +2005 Partnerships . In June 2011, we acquired from non-affiliated investor partners the remaining working interest in three of our affiliated partnerships: PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership (the "2005 Partnerships"). We purchased the 2005 Partnerships for an aggregate amount of $43 million , which was funded from our revolving credit facility. These purchases included the non-affiliated investor partners' remaining working interests wells located in the Wattenberg Field and Piceance Basin. +Pro Forma Information . The results of operations for the Seneca-Upshur, 2002/2003 Partnerships and 2005 Partnerships acquisitions have been included in our consolidated financial statements from the respective dates of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying statements of operations. +2010 Acquisitions +2004 Partnerships . In December 2010, we acquired the remaining working interest in four of our affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership (the “2004 Partnerships”). We purchased these partnerships for an aggregate amount of $36.5 million , which was funded from our revolving credit facility. These purchases included the remaining working interests in wells located in the Wattenberg Field and Piceance Basin. +Permian Basin . In July 2010, we acquired various producing assets located in the Wolfberry Trend in the Permian Basin in West Texas (the “Wolfberry Assets”). In conjunction with the divestiture of our Michigan asset group, we entered into a like-kind exchange agreement with a qualified intermediary. The Wolfberry Assets were identified as our replacement property in accordance with IRC Section 1031. Sales proceeds of $19.3 million from the Michigan divestiture were transferred directly to the qualified intermediary and, along with $55.7 million from our revolving credit facility, funded the purchase of the Wolfberry Assets. The sale of our Michigan assets resulted in a gain for income tax purposes of $19.2 million , which then resulted in a tax liability of $7.3 million . With the favorable deferral aspects of IRC Section 1031, we were able to defer $6.5 million of this tax liability. In November 2010, we acquired for $39.4 million in cash a second position in the Wolfberry oil trend, including 100% of the interest in producing assets and undeveloped acreage. +Pro Forma Information . The results of operations for the 2004 Partnerships and Wolfberry Assets acquisition have been included in our consolidated financial statements from the respective dates of acquisition. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the accompanying statements of operations. +F- 35 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 16 - NONCONTROLLING INTEREST IN SUBSIDIARY +In 2007, we contributed $0.8 million for a 50% interest in WWWV, LLC (the "LLC"), a limited liability company for which we served as the managing member. The LLC's only asset was an aircraft and was formed for the purpose of owning and operating the aircraft. We consolidated the entity based on a controlling financial interest. In 2011, we divested the asset and dissolved the entity with no material impact on our financial statements. +NOTE 17 - TRANSACTIONS WITH AFFILIATES +Former Executive Officer. In June 2011, Richard W. McCullough resigned from his positions as our Chief Executive Officer and the Chairman of the Board, effective immediately. In connection with his resignation, in July 2011, Mr. McCullough and the Company executed a separation agreement, whereby Mr. McCullough will receive those benefits to which he was entitled under Section 7(d) of his employment agreement, dated as of April 19, 2010, including without limitation, separation compensation in the amount of $4.1 million , less required withholdings, his annual non-qualified deferred supplemental retirement benefit equal to $30,000 for each of the years 2012 through 2021 (not accelerated), less required withholdings, continued coverage under the Company’s group health plans at the Company’s cost for a period equal to the lesser of 18 months or such period ending as of the date Mr. McCullough is eligible to participate in another employer’s group health plan, immediate vesting of any unvested Company stock options, SARs and restricted stock and issuance of shares representing the vested portion of his 2009 performance share awards. Related to this separation agreement, the statement of operations for 2011 reflects a charge to general and administrative expense of $6.7 million . +PDCM and Affiliated Partnerships. Our Gas Marketing segment markets the natural gas produced by PDCM and our affiliated partnerships in the Eastern Operating Region. +Amounts due from/to the affiliated partnerships are primarily related to derivative positions and, to a lesser extent, unbilled well lease operating expenses, and costs resulting from audit and tax preparation services. We have entered into derivative instruments on behalf of our affiliated partnerships for their estimated production. +The following table presents amounts included in our consolidated statement of operations related to the marketing of natural gas on behalf of PDCM and our affiliated partnerships and amounts included in our consolidated balance sheet related to the derivative instruments we entered into on behalf of our affiliated partnerships: +As of/Year Ended December 31, +2012 +2011 +2010 +(in thousands) +PDCM: +Sales from natural gas marketing +$ +11,105 +$ +9,735 +$ +4,298 +Cost of natural gas marketing +10,888 +9,544 +4,214 +Affiliated Partnerships: +Sales from natural gas marketing +535 +1,276 +651 +Cost of natural gas marketing +524 +1,251 +638 +Receivable from affiliates +2,140 +6,163 +14,616 +Payable to affiliates +4,707 +14,152 +20,342 +We provide certain well operating and administrative services for PDCM. Amounts billed to PDCM for these services were $12.1 million , $10.4 million and $11.1 million in 2012 , 2011 and 2010 , respectively. Our statements of operations include only our proportionate share of these billings. The following table presents the statement of operations line item in which our proportionate share is recorded and the amount for each of the periods presented. +Year Ended December 31, +Statement of Operations Line Item +2012 +2011 +2010 +(in thousands) +Production Costs +$ +3,945 +$ +3,441 +$ +3,862 +Exploration Expense +492 +430 +883 +General and Administrative Expense +1,630 +1,543 +1,899 +F- 36 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 18 - BUSINESS SEGMENTS +We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. +Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our natural gas and crude oil properties. The segment represents revenues and expenses from the production and sale of natural gas, NGLs and crude oil. Segment revenue includes natural gas, NGLs and crude oil sales, commodity price risk management, net and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of natural gas and crude oil properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $139.4 million , $122.2 million and $105.9 million in 2012 , 2011 and 2010 , respectively. +Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. +The following tables present our segment information: +2012 +2011 +2010 +(in thousands) +Year Ended December 31, +Revenues: +Oil and Gas Exploration and Production +$ +309,054 +$ +329,541 +$ +273,950 +Gas Marketing +47,079 +66,419 +69,071 +Total Revenues +$ +356,133 +$ +395,960 +$ +343,021 +Segment income (loss) from continuing operations before income taxes: +Oil and Gas Exploration and Production +$ +(96,293 +) +$ +106,832 +$ +84,387 +Gas Marketing +528 +954 +1,063 +Unallocated +(137,856 +) +(104,891 +) +(78,760 +) +Total +$ +(233,621 +) +$ +2,895 +$ +6,690 +Expenditures for segment long-lived assets: +Oil and Gas Exploration and Production +$ +656,443 +$ +479,027 +$ +319,268 +Unallocated +3,509 +1,363 +1,506 +Total +$ +659,952 +$ +480,390 +$ +320,774 +As of December 31, +Segment assets: +Oil and Gas Exploration and Production +$ +1,723,011 +$ +1,461,130 +Gas Marketing +11,090 +14,713 +Unallocated +92,747 +73,913 +Assets held for sale +— +148,249 +Total Assets +$ +1,826,848 +$ +1,698,005 +NOTE 19 - SUBSEQUENT EVENT +On February 4, 2013, we entered into a purchase and sale agreement with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which we have agreed to sell to Caerus our Piceance Basin, NECO and certain non-core Colorado oil and gas properties, leasehold mineral interests and related assets, including derivatives, for aggregate cash consideration of approximately $200 million , subject to post-closing adjustments. The assets being sold do not include any of our core Wattenberg Field acreage. The cash consideration is subject to customary adjustments, including adjustments based upon title and environmental due diligence, and by certain firm transportation obligations and natural gas hedging positions that will be assumed by Caerus. There can be no assurance we will be successful in closing such divestiture. +F- 37 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION - UNAUDITED +NATURAL GAS AND CRUDE OIL INFORMATION - UNAUDITED +Net Proved Reserves +All of our natural gas, NGLs and crude oil reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our natural gas, crude oil, condensate and NGL reserves. As of December 31, 2012 , 2011 and 2010, all of our reserve estimates were based on reserve reports prepared by Ryder Scott Company, L.P. ("Ryder Scott"). These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas, NGLs and crude oil expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. +The price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves +As of December 31, +Natural Gas +(per Mcf) +NGLs +(per Bbl) +Crude Oil +(per Bbl) +2012 +$ +2.35 +$ +28.02 +$ +87.51 +2011 +3.41 +39.59 +88.94 +2010 +3.54 +34.12 +71.95 +F- 38 +PDC ENERGY, INC. +The following tables present the changes in our estimated quantities of proved reserves: +Natural Gas +(MMcf) +NGLs +(MBbls) +Crude Oil, Condensate (MBbls) +Total +(MMcfe) +Proved Reserves: +Proved reserves, January 1, 2010 +608,925 +— +18,070 +717,345 +Revisions of previous estimates +6,504 +8,908 +(85 +) +59,442 +Extensions, discoveries and other additions +Western Operating Region +56,524 +811 +2,247 +74,872 +Eastern Operating Region +35,092 +— +— +35,092 +Purchases of reserves +Western Operating Region +20,920 +1,531 +4,367 +56,308 +Eastern Operating Region +220 +— +— +220 +Other +— +— +— +— +Dispositions +(43,690 +) +— +(55 +) +(44,020 +) +Production +(27,189 +) +(601 +) +(1,308 +) +(38,643 +) +Proved reserves, December 31, 2010 +657,306 +10,649 +23,236 +860,616 +Revisions of previous estimates +(161,654 +) +3,163 +(1,904 +) +(154,100 +) +Extensions, discoveries and other additions +Western Operating Region +125,374 +5,633 +17,092 +261,724 +Eastern Operating Region +51,315 +— +— +51,315 +Purchases of reserves +Western Operating Region +24,776 +1,052 +1,581 +40,574 +Eastern Operating Region +7,985 +— +24 +8,129 +Dispositions +(2,070 +) +(94 +) +(435 +) +(5,244 +) +Production +(30,887 +) +(815 +) +(1,958 +) +(47,525 +) +Proved reserves, December 31, 2011 (1) +672,145 +19,588 +37,636 +1,015,489 +Revisions of previous estimates +(289,436 +) +(3,671 +) +(6,729 +) +(351,836 +) +Extensions, discoveries and other additions +Western Operating Region +116,205 +11,637 +27,482 +350,919 +Eastern Operating Region +56,728 +— +— +56,728 +Purchases of reserves +Western Operating Region +87,189 +8,084 +10,801 +200,499 +Eastern Operating Region +23 +— +— +23 +Dispositions +(6,406 +) +(1,970 +) +(7,854 +) +(65,350 +) +Production +(32,410 +) +(841 +) +(2,026 +) +(49,612 +) +Proved reserves, December 31, 2012 (2) +604,038 +32,827 +59,310 +1,156,860 +Proved Developed Reserves, as of: +January 1, 2010 +258,375 +— +6,244 +295,839 +December 31, 2010 +227,341 +4,013 +8,287 +301,141 +December 31, 2011 (1) +299,369 +11,753 +16,910 +471,347 +December 31, 2012 (2) +281,925 +14,353 +20,412 +490,515 +Proved Undeveloped Reserves, as of: +January 1, 2010 +350,550 +— +11,826 +421,506 +December 31, 2010 +429,965 +6,636 +14,949 +559,475 +December 31, 2011 (1) +372,776 +7,835 +20,726 +544,142 +December 31, 2012 (2) +322,113 +18,474 +38,898 +666,345 +__________ +(1) +Includes estimated reserve data related to our Permian asset group, which was held for sale and under a purchase and sale agreement. The divestiture of our Permian assets closed on February 28, 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included in this report for additional details related to the divestiture of our Permian asset group. Total proved reserves included 6,242 MMcf of natural gas, 7,825 MBbls of crude oil and 1,970 MBbls of NGLs, for an aggregate of 65,018 MMcfe of natural gas equivalent, related to our Permian asset group. Total proved developed reserves related to those assets included 1,750 MMcf, 1,815 MBbls, 550 MBbls and 15,940 MMcfe, respectively, and proved undeveloped reserves included 4,492 MMcf, 6,010 MBbls, 1,420 MBbls and 49,078 MMcfe, respectively. +(2) +Includes estimated reserve data related to our Piceance and NECO assets, which are expected to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 19, Subsequent Events, to our consolidated financial statements included elsewhere in this report for additional details related to the planned divestiture of our Piceance and NECO assets. Total proved reserves +F- 39 +PDC ENERGY, INC. +include 83,656 MMcf of natural gas and 148 MBbls of crude oil, for an aggregate of 84,544 MMcfe of natural gas equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. +Developed +Undeveloped +Total +(MMcfe) +Beginning proved reserves, January 1, 2011 +301,141 +559,475 +860,616 +Undeveloped reserves converted to developed +43,597 +(43,597 +) +— +Revisions of previous estimates +73,643 +(227,743 +) +(154,100 +) +Extensions, discoveries and other additions +58,979 +254,060 +313,039 +Purchases of reserves +46,756 +1,947 +48,703 +Dispositions +(5,244 +) +— +(5,244 +) +Production +(47,525 +) +— +(47,525 +) +Ending proved reserves, December 31, 2011 +471,347 +544,142 +1,015,489 +Undeveloped reserves converted to developed +45,929 +(45,929 +) +— +Revisions of previous estimates +(109,909 +) +(241,927 +) +(351,836 +) +Extensions, discoveries and other additions +67,787 +339,860 +407,647 +Purchases of reserves +81,253 +119,269 +200,522 +Dispositions +(16,280 +) +(49,070 +) +(65,350 +) +Production +(49,612 +) +— +(49,612 +) +Ending proved reserves, December 31, 2012 +490,515 +666,345 +1,156,860 +2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 352 Bcfe. The revision was primarily due to a decrease of approximately 240 Bcfe due to lower gas pricing, mostly related to the Piceance Basin, approximately 6 Bcfe due to increased operating costs, approximately 46 Bcfe due to adjustments for geological reasons and approximately 77 Bcfe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 3 Bcfe due to non-acquisition interest adjustments and approximately 14 Bcfe due to asset performance. Discoveries and extensions of approximately 408 Bcfe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 57 Bcfe were added in the Eastern Operating Region related to the Marcellus Shale and approximately 351 Bcfe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 201 Bcfe of proved reserves, approximately 200 Bcfe due to an acquisition in the Wattenberg Field. We divested a total of 65 Bcfe in 2012, primarily our core Permian Basin assets. Based on the economic conditions on December 31, 2012, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Based on our decision to drill predominantly horizontal wells in 2012, our drilling program focused on locations that were not included in proved undeveloped reserves in the December 2011 reserve report. By focusing on non-PUD drilling locations in 2012, we were able to add considerable PUD reserves in the 2012 reserve report. In 2013, we anticipate the majority of our drilling to be focused on horizontal well locations that are included in our proved undeveloped reserves in the 2012 reserve report. Therefore, we expect to convert 15% to 20% of our PUDs to proved developed producing reserves in 2013. This level of capital spending is consistent with the most recent years. +2011 Activity. In 2011 , we recorded a downward revision of our previous estimate of proved reserves of approximately 154 Bcfe. The revision was primarily due to a decrease of approximately 4 Bcfe due to lower gas pricing and approximately 173 Bcfe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 6 Bcfe due to increased efficiencies in operating costs, approximately 5 Bcfe due to non-acquisition interest adjustments and approximately 12 Bcfe due to asset performance. In addition, the “Revisions of previous estimates” line item includes a deduction in the “Undeveloped” column and an increase in the “Developed” column of approximately 125 Bcfe. These reserves were transferred from proved undeveloped to proved developed as a result of the Company's determination that costs related to a refracture became less significant as compared to the costs associated with drilling a new well. Discoveries and extensions of approximately 313 Bcfe in 2011 are due to the drilling of 195 gross wells and the addition of new proved undeveloped reserves. Approximately 51 Bcfe were added in the Eastern Operating Region, approximately 262 Bcfe were added in the Western Operating Region ( 141 Bcfe in the Wattenberg Field, 80 Bcfe in the Piceance Basin and 41 Bcfe in the Permian Basin). We acquired approximately 49 Bcfe of proved reserves, approximately 8 Bcfe through acquisitions in the Eastern Operating Region, and approximately 41 Bcfe in the Western Operating Region ( 28 Bcfe were acquired in the Wattenberg Field and 13 Bcfe were acquired in the Piceance Basin) due to the repurchase of the 2003/2002-D and 2005 Partnerships as well as the purchase of interests in some of our other existing properties. We divested a total of approximately 5 Bcfe in 2011 . This included the sale of 100% of our North Dakota assets, or 2 Bcfe, to an unrelated third-party and our non-core Permian Basin assets, or 3 Bcfe, to unrelated third parties. +2010 Activity. In 2010, we revised our previous estimate of proved reserves upward by 59.4 Bcfe. The revision was primarily due to an increase of 55.6 Bcfe due to asset performance, 35.9 Bcfe due to higher commodity pricing, 28.1 Bcfe due to the impact of evaluating NGLs as a separate stream and 1.5 Bcfe due to interest adjustments. This was partially offset by a decrease of 58.7 Bcfe due to adjustments for geological reasons or reclassification of prior period proved undeveloped reserves to probable reserves due to aging and 3 Bcfe due to increased operating costs. Discoveries and extensions of 110 Bcfe in 2010 are due to drilling of 213 gross wells and the addition of new proved undeveloped reserves: +F- 40 +PDC ENERGY, INC. +35.1 Bcfe were added in the Eastern Operating Region and 74.9 Bcfe were added in the Western Operating Region ( 29.4 Bcfe in Wattenberg Field, 36.2 Bcfe in the Piceance Basin, 9.1 Bcfe in the NECO area and 0.2 Bcfe in North Dakota) and Permian Basin. We acquired 56.5 Bcfe of proved reserves, approximately 32.6 Bcfe through two acquisitions in the Permian Basin, and 23.9 Bcfe in both the Western and Eastern Operating Regions due to the repurchase of the 2004 Partnerships as well as the purchase of interests in some of our other existing properties. Of the 23.9 Bcfe, 12.8 Bcfe were acquired in the Wattenberg Field and 10.9 Bcfe were acquired in the Piceance Basin. Total dispositions of 44 Bcfe in 2010 included the deconsolidation of PDCM, or 28.9 Bcfe, and the sale of all of our Michigan assets, or 15.1 Bcfe, to an unaffiliated third-party. +Results of Operations for Natural Gas and Crude Oil Producing Activities +The results of operations for natural gas and crude oil producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Revenue: +Natural gas, NGLs and crude oil sales +$ +274,783 +$ +304,157 +$ +216,159 +Commodity price risk management gain, net +32,339 +46,090 +59,891 +307,122 +350,247 +276,050 +Expenses: +Production costs +77,537 +75,717 +60,121 +Exploration expense +22,605 +6,289 +20,291 +Impairment of proved natural gas and oil properties +162,287 +25,159 +4,666 +Depreciation, depletion, and amortization +146,879 +128,458 +103,303 +Accretion of asset retirement obligations +4,060 +1,897 +1,423 +Gain on sale of properties and equipment +(24,273 +) +(4,050 +) +(174 +) +389,095 +233,470 +189,630 +Results of operations for natural gas and crude oil producing +activities before provision for income taxes +(81,973 +) +116,777 +86,420 +Provision for income taxes +31,163 +(36,785 +) +(5,937 +) +Results of operations for natural gas and crude oil producing activities, excluding corporate overhead and interest costs +$ +(50,810 +) +$ +79,992 +$ +80,483 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +Costs Incurred in Natural Gas and Crude Oil Property Acquisition, Exploration and Development Activities +Costs incurred in natural gas and crude oil property acquisition, exploration and development are presented below. +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +105,303 +$ +79,554 +$ +87,241 +Unproved properties +276,225 +95,081 +84,636 +Development costs (2) +233,144 +301,008 +138,018 +Exploration costs: (3) +Exploratory drilling +18,803 +3,626 +21,223 +Geological and geophysical +1,925 +1,846 +2,367 +Total costs incurred +$ +635,400 +$ +481,115 +$ +333,485 +__________ +(1) +Property acquisition costs - represent costs incurred to purchase, lease or otherwise acquire a property. +F- 41 +PDC ENERGY, INC. +(2) +Development costs - represents costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store natural gas, NGLs and crude oil. Of these costs incurred for the years ended December 31, 2012 , 2011 and 2010 , $62.0 million , $80.6 million and $37.4 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing natural gas, NGLs and crude oil. +Capitalized Costs Related to Natural Gas and Crude Oil Producing Activities +Aggregate capitalized costs related to natural gas and crude oil exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2012 +2011 +(in thousands) +Proved natural gas and crude oil properties +$ +2,075,924 +$ +1,694,847 +Unproved natural gas and crude oil properties +319,327 +102,466 +Capitalized costs +2,395,251 +1,797,313 +Less accumulated DD&A +(905,458 +) +(621,074 +) +Capitalized costs, net +$ +1,489,793 +$ +1,176,239 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for natural gas, NGLs and crude oil, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +As of December 31, +2012 +2011 +2010 +(in thousands) +Future estimated cash flows +$ +7,529,292 +$ +6,415,255 +$ +4,361,095 +Future estimated production costs +(1,690,453 +) +(1,704,645 +) +(1,418,044 +) +Future estimated development costs +(1,852,177 +) +(1,474,137 +) +(1,119,604 +) +Future estimated income tax expense +(1,230,294 +) +(946,849 +) +(508,805 +) +Future net cash flows +2,756,368 +2,289,624 +1,314,642 +10% annual discount for estimated timing of cash flows +(1,587,871 +) +(1,348,415 +) +(826,224 +) +Standardized measure of discounted future estimated net cash flows +$ +1,168,497 +$ +941,209 +$ +488,418 +F- 42 +PDC ENERGY, INC. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2012 +2011 +2010 +(in thousands) +Sales of natural gas, NGLs and crude oil production, net of production costs +$ +(194,346 +) +$ +(226,227 +) +$ +(163,104 +) +Net changes in prices and production costs (1) +95,501 +383,293 +180,124 +Extensions, discoveries, and improved recovery, less related costs (2) +632,781 +467,347 +88,637 +Sales of reserves (3) +(86,902 +) +(4,224 +) +(24,174 +) +Purchases of reserves (4) +296,208 +64,761 +45,538 +Development costs incurred during the period +69,198 +94,941 +44,491 +Revisions of previous quantity estimates (5) +(452,775 +) +(112,468 +) +47,884 +Changes in estimated income taxes (6) +(131,256 +) +(204,377 +) +(105,557 +) +Net changes in future development costs +(3,979 +) +(29,827 +) +(41,595 +) +Accretion of discount +124,105 +65,284 +35,951 +Timing and other +(121,247 +) +(45,712 +) +32,587 +Total +$ +227,288 +$ +452,791 +$ +140,782 +__________ +(1) +Despite the decrease in price for each of our commodities for 2012 compared to 2011, our weighted-average price, net of production costs per Mcfe, in our 2012 reserve report increased to $3.45 from $3.19 resulting from our increase in liquids as a percentage of total proved reserves. Our weighted-average price, net of production costs per Mcfe, in our 2010 reserve report was $2.12 . +(2) +The 35% increase in 2012 as compared to 2011 reflects a continuation of our shifting focus from gas-rich projects to liquid-rich projects. At December 31, 2012, extensions, discoveries and other additions had increased to 407,647 MMcfe, a 30% increase, 52.2% of which was gas and 47.8% was liquids. Approximately 86% of the 35% increase was related to the additional volume of PUD reserves in the Wattenberg Field that were proved up by our 2012 drilling program. The changes in extensions, discoveries and improved recovery, less related costs, were 427% higher in 2011 as compared to 2010. At December 31, 2010, extensions, discoveries and other additions were 109,964 MMcfe, 83.3% of which was gas and 16.7% of which was liquids. At December 31, 2011, extensions, discoveries and other additions had increased to 313,039 MMcfe, a 185% increase, 56.4% of which was gas and 43.6% was liquids. This change was a result of our shifting of focus from gas-rich projects to liquid-rich projects. In 2011, we focused primarily on the liquids-rich Wattenberg Field in northern Colorado, where we drilled 17 horizontal Niobrara wells and 80 vertical wells, completed 190 zones and participated in 48 non-operated drilling projects. 2011 was the first year that horizontal Niobrara PUDs were included in our year-end reserves. All of these projects are liquid-rich and, with the exception of the vertical wells and refractures, these reserves were not recognized at December 31, 2010. As a result, approximately two-thirds of the 427% increase is related to additional volumes included in our reserve report in 2011 over those included in 2010 and one-third of the increase is related to the per Mcfe value increase of those additional volume of reserves. +(3) +The increase in sales of reserves in 2012 as compared to 2011 was due to the divestiture of our core Permian assets on February 28, 2012. +(4) +The increase in purchases of reserves in 2012 as compared to 2011 was due to the Merit Acquisition in the liquids-rich Wattenberg Field in northern Colorado. +(5) +The decrease in revisions of our previous quantity estimates in 2012 as compared to 2011 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments due to our drilling schedule. The decrease in 2011 as compared to 2010 was primarily due to lower natural gas pricing, a decrease in proved undeveloped reserves pursuant to the SEC five-year rule and adjustments for geological reasons, offset in part by improvements in asset performance. +(6) +The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38.2% , 38.1% and 38% for the year ended December 31, 2012, 2011 and 2010, respectively. In addition, the company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital,additional current year capital or future development capital. +It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +F- 43 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2012 and 2011 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share attributable to shareholders due to changes in the weighted-average shares outstanding throughout the year. +2012 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas, NGLs and crude oil sales +$ +75,310 +$ +56,879 +$ +59,915 +$ +78,223 +$ +270,327 +Sales from natural gas marketing +11,834 +8,917 +11,570 +14,758 +47,079 +Commodity price risk management gain (loss), net +11,501 +38,729 +(31,943 +) +14,052 +32,339 +Well operations, pipeline income and other +1,701 +1,520 +1,639 +1,528 +6,388 +Total revenues +100,346 +106,045 +41,181 +108,561 +356,133 +Costs, expenses and other: +Production costs +18,370 +18,055 +20,756 +18,304 +75,485 +Cost of natural gas marketing +11,492 +8,761 +11,598 +14,701 +46,552 +Exploration expense +2,063 +2,570 +1,969 +16,003 +22,605 +Impairment of natural gas and crude oil properties +653 +370 +395 +166,731 +168,149 +General and administrative expense +14,708 +14,378 +13,710 +16,019 +58,815 +Depreciation, depletion and amortization +39,814 +34,448 +32,483 +40,134 +146,879 +Accretion of asset retirement obligations +819 +825 +1,195 +1,221 +4,060 +Gain on sale of properties and equipment +(154 +) +(2,246 +) +(1,508 +) +(445 +) +(4,353 +) +Total costs, expenses and other +87,765 +77,161 +80,598 +272,668 +518,192 +Income (loss) from operations +12,581 +28,884 +(39,417 +) +(164,107 +) +(162,059 +) +Loss on extinguishment of debt +— +— +— +(23,283 +) +(23,283 +) +Interest expense +(10,444 +) +(10,053 +) +(11,360 +) +(16,430 +) +(48,287 +) +Interest income +2 +— +3 +3 +8 +Income (loss) from continuing operations before income taxes +2,139 +18,831 +(50,774 +) +(203,817 +) +(233,621 +) +Provision for income taxes +(759 +) +(6,179 +) +18,131 +77,642 +88,835 +Income (loss) from continuing operations +1,380 +12,652 +(32,643 +) +(126,175 +) +(144,786 +) +Income (loss) from discontinued operations, net of tax +14,455 +(381 +) +— +— +14,074 +Net income (loss) +$ +15,835 +$ +12,271 +$ +(32,643 +) +$ +(126,175 +) +$ +(130,712 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +0.06 +$ +0.48 +$ +(1.08 +) +$ +(4.17 +) +$ +(5.23 +) +Income (loss) from discontinued operations +0.61 +(0.02 +) +— +— +0.51 +Net income (loss) +$ +0.67 +$ +0.46 +$ +(1.08 +) +$ +(4.17 +) +$ +(4.72 +) +Diluted +Income (loss) from continuing operations +$ +0.06 +$ +0.47 +$ +(1.08 +) +$ +(4.17 +) +$ +(5.23 +) +Income (loss) from discontinued operations +0.60 +(0.01 +) +— +— +0.51 +Net income (loss) +$ +0.66 +$ +0.46 +$ +(1.08 +) +$ +(4.17 +) +$ +(4.72 +) +Weighted-average common shares outstanding +Basic +23,609 +26,597 +30,214 +30,233 +27,677 +Diluted +23,889 +26,728 +30,214 +30,233 +27,677 +F- 44 +PDC ENERGY, INC. +2011 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Natural gas, NGLs and crude oil sales +$ +58,810 +$ +65,762 +$ +72,044 +$ +79,989 +$ +276,605 +Sales from natural gas marketing +15,202 +18,897 +17,209 +15,111 +66,419 +Commodity price risk management gain (loss), net +(23,882 +) +20,537 +46,706 +2,729 +46,090 +Well operations, pipeline income and other +1,843 +1,755 +1,670 +1,578 +6,846 +Total revenues +51,973 +106,951 +137,629 +99,407 +395,960 +Costs, expenses and other: +Production costs +18,117 +16,537 +13,644 +19,054 +67,352 +Cost of natural gas marketing +14,993 +18,207 +17,227 +15,038 +65,465 +Exploration expense +1,669 +1,215 +1,135 +2,234 +6,253 +Impairment of natural gas and crude oil properties +453 +499 +531 +23,676 +25,159 +General and administrative expense +13,873 +19,509 +13,683 +14,389 +61,454 +Depreciation, depletion and amortization +30,985 +30,592 +31,523 +35,807 +128,907 +Accretion of asset retirement obligations +355 +358 +372 +648 +1,733 +Gain on sale of properties and equipment +— +— +(32 +) +(164 +) +(196 +) +Total costs, expenses and other +80,445 +86,917 +78,083 +110,682 +356,127 +Income (loss) from operations +(28,472 +) +20,034 +59,546 +(11,275 +) +39,833 +Interest expense +(9,062 +) +(9,067 +) +(9,496 +) +(9,360 +) +(36,985 +) +Interest income +9 +2 +36 +— +47 +Income (loss) from continuing operations before income taxes +(37,525 +) +10,969 +50,086 +(20,635 +) +2,895 +Provision for income taxes +14,278 +(2,804 +) +(19,218 +) +7,927 +183 +Income (loss) from continuing operations +(23,247 +) +8,165 +30,868 +(12,708 +) +3,078 +Income from discontinued operations, net of tax +3,323 +1,000 +1,692 +4,344 +10,359 +Net income (loss) +(19,924 +) +9,165 +32,560 +(8,364 +) +13,437 +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(0.99 +) +$ +0.35 +$ +1.31 +$ +(0.54 +) +$ +0.13 +Income from discontinued operations +0.14 +0.04 +0.07 +0.19 +0.44 +Net income (loss) attributable to shareholders +$ +(0.85 +) +$ +0.39 +$ +1.38 +$ +(0.35 +) +$ +0.57 +Diluted +Income (loss) from continuing operations +$ +(0.99 +) +$ +0.34 +$ +1.30 +$ +(0.54 +) +$ +0.13 +Income from discontinued operations +0.14 +0.04 +0.07 +0.19 +0.43 +Net income (loss) attributable to shareholders +$ +(0.85 +) +$ +0.38 +$ +1.37 +$ +(0.35 +) +$ +0.56 +Weighted-average common shares outstanding +Basic +23,428 +23,491 +23,569 +23,592 +23,521 +Diluted +23,428 +23,723 +23,783 +23,592 +23,871 +F- 45 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Deconsolidation/Purchase Price Adjustment for PDCM +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2012: +Allowance for doubtful accounts +$ +921 +$ +— +$ +258 +$ +153 +$ +1,026 +Valuation allowance for unproved natural gas and crude oil properties +12,204 +— +4,207 +8,375 +8,036 +2011: +Allowance for doubtful accounts +686 +121 +135 +21 +921 +Valuation allowance for unproved natural gas and crude oil properties +16,996 +260 +2,611 +7,143 +12,204 +2010: +Allowance for doubtful accounts +548 +135 +307 +34 +686 +Valuation allowance for state tax benefits +747 +— +— +747 +— +Valuation allowance for unproved natural gas and crude oil properties +15,001 +19 +6,120 +4,106 +16,996 +___ ____________ +(1) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved natural gas and crude oil properties, deductions represent accumulated amortization of expired or abandoned unproved natural gas and crude oil properties. For valuation allowance for state tax benefits, deductions represent expired or unutilized state tax benefits. +F- 46 \ No newline at end of file diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/filing_metadata.csv b/raw/filings/0000077877/2012/0000077877-13-000017/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..af4c4010fd09e2d6b7fcd58633dea9d7b5c129d5 --- /dev/null +++ b/raw/filings/0000077877/2012/0000077877-13-000017/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2013-02-27,2012-12-31,2013-02-27T13:47:47.000Z,0000077877-13-000017,pdce-10kxfy12.htm,10-K,27980980,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787713000017/pdce-10kxfy12.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787713000017/,2012,2012,1 diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/item1.txt b/raw/filings/0000077877/2012/0000077877-13-000017/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/item13.txt b/raw/filings/0000077877/2012/0000077877-13-000017/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3488777980c4ea86d10d15a8c04503764ca3a8e5 --- /dev/null +++ b/raw/filings/0000077877/2012/0000077877-13-000017/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/item9a.txt b/raw/filings/0000077877/2012/0000077877-13-000017/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..3081c0721bb8e962313ac0a5513080d2e2d57a82 --- /dev/null +++ b/raw/filings/0000077877/2012/0000077877-13-000017/item9a.txt @@ -0,0 +1,5 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2012 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2012 . +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2012 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/rp_note.txt b/raw/filings/0000077877/2012/0000077877-13-000017/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2012/0000077877-13-000017/rpt_disclosure.txt b/raw/filings/0000077877/2012/0000077877-13-000017/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e3403060b655118179e7b76971157049fd91bf64 --- /dev/null +++ b/raw/filings/0000077877/2012/0000077877-13-000017/rpt_disclosure.txt @@ -0,0 +1,18 @@ +TRANSACTIONS WITH RELATED PERSONS +Related Transactions +From January 1, 2013 to the +present, there was no transaction or series of transactions, nor is there any currently proposed transaction involving an amount exceeding $120,000 in which the Company is a participant and/or in which any Director, executive officer, known holder +of more than five percent of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest for which disclosure is required under SEC Rule S-K 404. +Policies and Procedures With Respect to Transactions with Related Persons +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related +parties and potential conflicts of interest. The related party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent +of the Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial +financial interest. +24 +Table of Contents +Under our related-party transaction policy, a related person transaction is +a transaction or arrangement involving a related person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the +Audit Committee any potential related person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions will be reviewed by the Audit Committee. In determining whether to +approve or ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of +the transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis and the impact of the transaction on +the Company’s business and operations. \ No newline at end of file diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/filing.txt b/raw/filings/0000874499/2001/0001060830-02-000041/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..96fb29d369c352d6cb2660c54dea671307588eb5 --- /dev/null +++ b/raw/filings/0000874499/2001/0001060830-02-000041/filing.txt @@ -0,0 +1,2413 @@ +10-K +1 +gulfportenergy10k2001.txt +UNITED STATES SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. +FORM 10-K +FOR ANNUAL AND TRANSITION REPORTS +PURSUANT TO SECTIONS 13 OR 15(d) OF THE +SECURITIES AND EXCHANGE ACT OF 1934 +[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE +ACT OF 1934 +OR +[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE +ACT OF 1934 +FOR THE YEAR ENDED DECEMBER 31, 2001 +Commission File Number 1-10192 +Gulfport Energy Corporation +----------------------------------------------------- +(Exact name of registrant as specified in its charter) +Delaware 73-1521290 +----------------------------------- --------------------- +(State or other jurisdiction of (IRS Employer +Incorporation or organization) Identification Number) +6307 Waterford Blvd., Suite 100 +Oklahoma City, Oklahoma 73118 +(405) 848-8807 +------------------------------------------------------------- +(Address, including zip code, and telephone number, including +area code, of registrant's principal executive office) +Securities registered pursuant to Section 12(b) of the Act: +Not Applicable +Securities registered pursuant to Section 12(g) of the Act: +NAME OF EACH EXCHANGE ON WHICH +TITLE OF EACH CLASS REGISTERED +Preferred Stock, $0.01 par value None +Common Stock, $0.01 par value None +Indicate by a check mark whether the registrant (1) has filed all +reports required to be filed by Section 13 or 15(d) of the Securities Exchange +Act of 1934 during the preceding 12 months (or for such shorter period that the +registrant was required to file such reports), and (2) has been subject to such +filing requirements for the past 90 days. Yes [X] No [ ]. +1 +Indicate by a check mark if disclosure of delinquent filers pursuant to +Item 405 of Regulation S-K is not contained herein and will not be contained, to +the best of registrant's knowledge, in definitive proxy or information +statements incorporated by reference in Part III of this Form 10-K or any +amendment to this Form 10-K. [ ] +All shares of common and preferred stock outstanding prior to the +Effective Date of the Plan of Reorganization (July 11, 1997) were canceled on +the Effective Date. The number of shares of the registrant's Common Stock, $0.01 +par value, outstanding at March 31, 2002 was 10,146,566. The aggregate market +value of the voting stock held by non-affiliates of Gulfport using an average +trading price in December 31, 2001 was $12,233,000. +APPLICABLE ONLY TO REGISTRANTS INVOLVED IN +BANKRUPTCY PROCEEDINGS DURING THE +PRECEDING FIVE YEARS +Indicate by check mark whether the registrant has filed all documents +and reports required to be filed by Section 12, 13 or 15(d) of the Securities +Exchange Act of 1934 subsequent to the distribution of securities under a plan +confirmed by a court. +Yes X No +----- ----- +APPLICABLE ONLY TO CORPORATE REGISTRANTS +Common Stock Issued Outstanding December 31, 2001: 10,146,566 +Common Stock Issued Outstanding February 1, 2002: 10,146,566 +2 +TABLE OF CONTENTS +Page +---- +Disclosure Regarding Forward-Looking Statements 4 +Part I +Item 1. Business 4 +Item 2. Properties 13 +Item 3. Legal Proceedings 15 +Item 4. Submission of Matters to a Vote of Security Holders 15 +PART II +Item 5. Market for the Registrant's Common Stock and Related +Shareholder Matters 16 +Item 6. Selected Financial Data 16 +Item 7. Management's Discussion and Analysis of Financial +Condition and Results of Operations 17 +Item 8. Financial Statements and Supplementary Data 24 +Item 9. Changes in and Disagreements with Accountants on Accounting +and Financial Disclosure 24 +PART III +Item 10. Directors, Executive Officers, Promoters and Control Persons; +Compliance with Section 16(a) of the Exchange Act 24 +Item 11. Executive Compensation 26 +Item 12. Security Ownership of Certain Beneficial Owners and Management 26 +Item 13. Certain Relationships and Related Transactions 26 +PART IV +Item 14. Exhibits, Financial Statement Schedules and +Reports on Form 8K 27 +Signatures 28 +3 +DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS +This Form 10-K includes "forward-looking statements" within the meaning +of Section 27A of the Securities Exchange Act of 1934, as amended (the "Exchange +Act"). All statements other than statements of historical facts, included in +this Form 10-K that address activities, events or developments that Gulfport +Energy Corporation ("Gulfport" or the "Company"), a Delaware corporation, +formerly known as WRT Energy Corporation ("WRT"), expects or anticipates will or +may occur in the future, including such things as estimated future net revenues +from oil and gas reserves and the present value thereof, future capital +expenditures (including the amount and nature thereof), business strategy and +measures to implement strategy, competitive strength, goals, expansion and +growth of Gulfport's business and operations, plans, references to future +success, reference to intentions as to future matters and other such matters are +forward-looking statements. These statements are based on certain assumptions +and analyses made by Gulfport in light of its experience and its perception of +historical trends, current conditions and expected future developments as well +as other factors it believes are appropriate in the circumstances. However, +whether actual results and developments will conform with Gulfport's +expectations and predictions is subject to a number of risks and uncertainties, +general economic, market, or business conditions; the opportunities (or lack +thereof) that may be presented to and pursued by Gulfport; competitive actions +by other oil and gas companies; changes in laws or regulations; and other +factors, many of which are beyond the control of Gulfport. Consequently, all of +the forward-looking statements made in the Form 10-K are qualified by these +cautionary statements and there can be no assurances that the actual results or +developments anticipated by Gulfport will be realized, or even if realized, that +they will have the expected consequences to or effects on Gulfport, its business +or operations. +Item 1. Business +Description of Business +Gulfport is an independent oil and gas exploration and production +company with properties located in the Louisiana Gulf Coast. Gulfport has a +market enterprise value of approximately $50.9 million dollars and generated +EBITDA of $9.6 million dollars for the twelve months ended December 31, 2001. As +of December 31, 2001, the Company had 29 MMBOE proved reserves with a present +value (10%) of estimated future net reserves of $130 million dollars. +Gulfport is actively pursuing further development of its properties in +order to fully exploit its reserves. The Company has a substantial portfolio of +low risk developmental projects for the next several years providing the +opportunity to increase production and cash flow. Gulfport's developmental +program is designed to reach the Company's high impact, higher potential rate of +return prospects through the penetration of several producing horizons. +Additionally, Gulfport owns 3-D seismic data, which along with the +Company's technical expertise, will be used to identify exploratory prospects +and test undrilled fault blocks in existing fields. +Background +Gulfport is the successor of WRT Energy Corporation ("WRT"). WRT filed for +bankruptcy in February 1996. Gulfport emerged as the reorganized company in July +1997. +4 +Principal Oil and Gas Properties +Gulfport owns interests in a number of producing oil and gas properties +located along the Louisiana Gulf Coast. The following is a map showing the +locations of Gulfport's principal oil and gas properties. +(MAP OMITTED) +Gulfport serves as the operator of substantially all of the properties in +which it holds a working interest with the exception of the Texaco ("Texaco" or +"ChevronTexaco") well and deep rights at West Cote Blanche Bay. During 2001 +Chevron acquired Texaco. The following table presents certain information as of +January 1, 2002 reflecting Gulfport's net interest in its producing oil and gas +properties. +Net Proved Reserves +Shut-in As of 1/1/02 +------------------- +Field NRI/WI Active Wells wells(1) Acreage(2) Gas Oil Total +-------------- ------------ ----------- +Percentages Gross Net Gross Net Gross Net MBOE MBOE MBOE +--------------------------------------------------------------------------------------------------------- +E Hackberry 78.7/100 17 17 73 73 3,147 3,147 590 3,392 3,982 +W Hackberry 87.5/100 2 2 25 25 592 592 47 248 295 +West Cote +Blanche Bay (3) 78.7/100 48 47 296 296 4,590 4,590 3,384 20,906 24,290 +Overrides/Royalty Various 12 1 6 1 403 403 100 277 377 +------------------------------------------------------------------------ +TOTAL 79 67 400 395 8,732 8,732 4,121 24,823 28,944 +======================================================================== +(1) The following wells produce on an intermittent basis: East Hackberry - +4; West Hackberry - 1; and West Cote Blanche Bay - 6.All of Gulfport's +acreage is Developed Acreage. +(2) Includes 1 producing well and 3 shut-in wells attributable to depths +below the Rob "C" Marker ("Deep Rights"). Gulfport has a 7.45% +non-operated working interest (5.84% NRI) in the Deep Rights. The Deep +Rights are operated by ChevronTexaco Corporation. +(3) In the future, Gulfport will have to plug and abandon almost 400 +wellbores. Gulfport's strategy to meet this obligation is to plug at +least twenty wells a year at WCBB, three at Hackberry and to invest in +plugging escrow accounts. The Company continually deposits money in +the West Cote Blanche Bay Escrow Account, which currently has a +balance of approximately $2.3 million dollars. Additionally, Gulfport +has a $200,000 letter of credit dedicated to the plugging operations +at East Hackberry. +All of the oil and gas leases in which Gulfport owns an interest have been +perpetuated by production. The operator may surrender the leases at any time by +notice to the lessors, or by the cessation of production. +East Hackberry Field +(Map Omitted) +Location and Land +The East Hackberry Field is located along the western shore of Lake +Calcasieu in Cameron Parish, Louisiana approximately 80 miles west of Lafayette +5 +and 15 miles inland from the Gulf of Mexico. In February 1994, Gulfport +purchased a 100% working interest (approximately 79% average NRI) in certain +producing oil and gas properties situated in the East Hackberry Field. The +purchase included two separate lease blocks, the Erwin Heirs Block which is +located on land originally developed by Gulf Oil Company (now ChevronTexaco +Corporation), and the adjacent State Lease 50 Block which is located primarily +in the shallow waters of Lake Calcasieu, originally developed by Texaco. The two +lease blocks together contain 3,147 acres. +In September 1994, Gulfport sold an overriding royalty interest equal to a +50% working interest in certain producing oil and gas wells situated in the East +Hackberry Field to Milam Royalty Corporation a subsidiary of J. P. Morgan and +Company. In April 1999, Gulfport purchased the overriding royalty interest back +from the then current owner, Queen Sand Resources, Inc. giving Gulfport a 100% +working interest in the field. +Geology +The Hackberry Field is a major salt intrusive feature, elliptical in shape +as opposed to a classic "dome," divided into East and West field entities by a +saddle. Structurally, Gulfport's East Hackberry acreage is located on the +eastern end of the Hackberry salt ridge. There are over 30 pay zones at this +field. The salt intrusion trapped Oligocene through Lower Miocene rocks in a +series of complex, steeply dipping fault blocks. The Camerina sand series is a +prolific producer with 1-2 MMBL per well of oil potential. Gulfport's wells +currently produce from perforations found between 5,100' and 12,200'. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company (now +ChevronTexaco Corporation) by a gravitational anomaly survey. The massive +shallow salt stock presented an easily recognizable gravity anomaly indicating a +productive field. Initial production began in 1927 and has continued to the +present. The estimated cumulative oil and condensate production through 2002 +was 111 million barrels of oil with casinghead gas production being 60 billion +cubic feet of gas. There have been a total of 170 wells drilled on Gulfport's +portion of the field with 17 having current daily production; three produce +intermittently; 73 wells are shut-in and 4 wells have been converted to salt +water disposal wells. The remaining 73 wells have been plugged and abandoned. +During 2001, daily net production averaged 305 barrels of oil with a limited +amount of net gas production. +Facilities +Gulfport has land-based production and processing facilities located at +the East Hackberry Field. The facility is comprised of two dehydrating units and +four disposal pumps. Gulfport also has a field office that serves both the East +and West Hackberry fields. Due to the high cost of gas, Gulfport converted the +Erwin Heirs Block from gas lift to other lifting methods in 2000 and returned +the rental compressors. Gulfport reactivated three pumping units from inventory +and purchased an additional surface unit and two electric submersible pumps. +2001 Activity +Gulfport began a program to periodically test shut-in wells on the State +Lease 50 portion of the East Hackberry Field. Additionally, Gulfport +reactivated a satellite tank battery at the State Lease 50 portion of East +Hackberry. The Company also conducted several remedial operations that included +6 +repairing holes in tubing and casing, replaced parted tubing and cleaned out +salt water disposal wells. +West Hackberry Field +Location and Land +The West Hackberry Field is located on land and is five miles West of Lake +Calcasieu in Cameron Parish, Louisiana approximately 85 miles west of Lafayette +and 15 miles inland from the Gulf of Mexico. In November 1992, Gulfport +purchased a 100% working interest (approximately 80% average NRI, subsequently +increased to approximately 87.5% NRI) in 592 acres within the West Hackberry +Field. +Gulfport's leases at West Hackberry are located within two miles of one of +the United States' Department of Energy's Strategic Petroleum Reserves. The +West Hackberry storage facility occupies 525 acres and has capacity to store 222 +million barrels of oil in underground salt caverns. +Geology +Structurally, Gulfport's West Hackberry acreage is located on the western +end of the Hackberry salt ridge. (See graphic above.) There are over 30 pay +zones at this field. West Hackberry consists of a series of fault-bounded traps +in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt +Ridge. Recoveries from these thick, porous, water-drive reservoirs have +resulted in per well cumulatives of almost 700 BOE. +Area History and Production +The first discovery well at West Hackberry was drilled in 1938 and was +developed by Superior Oil Company (now Exxon-Mobil Corporation) between 1938 and +1988. The estimated cumulative oil and condensate production through 2001 was +170 million barrels of oil with casinghead gas production of 120 billion cubic +feet of gas. There have been 36 wells drilled to date on Gulfport's portion of +West Hackberry and currently 2 are producing, 25 are shut-in and 1 well has been +converted to a saltwater disposal well. The remaining 8 wells have been plugged +and abandoned. During 2001, daily net production averaged 40 barrels of oil and +a limited amount of gas. +Facilities +Gulfport has land-based production and processing facilities located at +the West Hackberry field. Gulfport has two dehydrating units and one disposal +pump. During 2000, due to the high cost of gas, Gulfport converted the West +Hackberry field from gas lift to other lifting methods. The Company reactivated +two pumping units from inventory and sold a company owned compressor. Gulfport +maintains a field office that serves both the East and West Hackberry fields. +2001 Activity +Gulfport conducted several remedial operations that included repairing +holes in tubing and casing and replacing parted tubing. +West Cote Blanche Bay Field +(Map Omitted) (Type Log Omitted) +7 +Location and Land +The West Cote Blanche Bay (WCBB) Field lies approximately five miles off +the coast of Louisiana primarily in St. Mary Parish in a shallow bay, with water +depths averaging eight to ten feet. Gulfport originally acquired from Texaco a +6.25% working interest in all zones in the WCBB field in July 1988. In April +1995, Gulfport completed the purchase of an additional 43.75% working interest +in the WCBB field from an affiliate of Benton Oil and Gas Company and two +affiliates of Tenneco, Inc. as to those rights lying above the base of the Rob +"C" marker, located at approximately 10,500'. The sellers retained their +interests in all depths below the base of the Rob "C" marker. In July, 1997 +Gulfport acquired the remaining 50% working interest in the WCBB field in depths +above the Rob "C" marker from Texaco and became the operator of the shallow +rights in the field. In 1999 Gulfport exercised a preferential right to +purchase an additional 1.00% working interest in the rights below the Rob "C" +marker. Currently Gulfport owns a 100% working interest (78.66% NRI) and is +the operator in the depths above the Rob "C" marker and owns a 7.45% +non-operated working interest (5.84% NRI) in depths below the Rob "C" marker. +Texaco is the operator below the base of the Rob "C" marker. Gulfport's +leasehold at WCBB covers a portion of Louisiana State Lease 340 and contains +4,590 acres. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. +The field is characterized by a piercement salt dome, which created traps from +the Pleistocene through the Miocene. The relative movements affected deposition +and created a complex system of fault traps. The compensating fault sets +generally trend NW-SE and are intersected by sets having a major radial +component. Later-stage movement caused extension over the dome and a large +graben system was formed. +There are over 100 distinct sandstone reservoirs recognized throughout +most of the field and nearly 200 major and minor discrete intervals have been +tested. Within the over 800 wellbores that have been drilled to date in the +field, over 4,000 potential zones have been penetrated. These sands are highly +porous and permeable reservoirs primarily with a strong water drive. +Area History and Production +Texaco drilled the discovery well in 1940 based on a seismic and +gravitational anomaly. WCBB was subsequently developed on an even 160-acre +pattern for much of the remainder of the decade. Developmental drilling +continued and reached its peek in the 1970's when over 300 of the over 800 total +wells were drilled in the field. Of the over 800 wells drilled, only 80 were dry +holes and many of these were capable of hydrocarbon production. As a result, the +field has an historic success rate of over 90% for all wells drilled. The +cumulative gross production for the average producer in the field was 237 MBO, +with over 100 of those wells (14% of total wells) producing in excess of 500 +MBO. As of January 1, 2002, field cumulative gross production was 191 MMBO and +232.5 BCF of gas. +There have been 871 wells drilled in WCBB. Of these, 48 are currently +producing, 303 are shut-in and five have been converted to salt water disposal +wells. The balance of the wells (or 515) have been plugged and abandoned. +During 2001, Gulfport's net current daily production averaged 1,280 barrels of +oil, 399 MCF of gas and 11,881 barrels of water at WCBB. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 +shot points per mile that processed out 100 fold. In 1993, an undershoot survey +around the crest and production facilities was added. Gulfport owns the rights +8 +to the seismic data. In December of 1999 Gulfport completed the reprocessing +of the seismic data and its technical staff developed prospects from the data. +The reprocessed data will enable Gulfport to identify prospects in areas of the +field that would otherwise remain obscure. +Facilities +Gulfport owns and operates a production facility at WCBB. The platform +for the production facility stretches over a mile and is equipped with a 30 MMCF +capacity dehydrating system and three 225 horsepower triplex saltwater disposal +pumps. The Company has an ongoing program to modernize and service the +production facilities at WCBB. During 2001, Gulfport installed two new gas +compressors totaling 3,000 horsepower into full time service at the field +replacing three outdated inefficient compressors. The new compressors increased +efficiency and, together with a new header valve the Company installed at one of +the tank batteries, reduced gas usage in the field by 50%. Other work performed +on the facility during 2001 included repairing or replacing flow lines and gas +lift lines. Gulfport also back flowed and cleaned sand from the five saltwater +disposal wells at West Cote Blanche Bay, which allows the wells to handle a +higher volume of water. The Company generates cash flow by handling other +companies' gas and oil and disposing of their saltwater through the facility for +a fee. In 2001, Gulfport earned an average of $33,524 a month from third party +facility charges. +2001 Activity +During April 2001, Gulfport finished the seven well drilling program it +had commenced in January of 2001. The Company successfully drilled, completed +and is currently producing six intermediate depth wells, with total depths +averaging approximately 9,000' and one shallow well, with a total depth of +2,500'. These wells found significant oil and gas deposits in multiple targets +ranging from relatively low risk proven undeveloped objectives to higher +potential exploratory targets. Gulfport feels that by taking most future wells +to a depth of 9,000' there will be an increased chance of converting reserves +currently classified as possible and probable to proved. +Gulfport continued to meet its plugging obligation and plugged 26 wells at +WCBB during 2001 at an average cost of $18,400 per well. The Company has plugged +90 wells at WCBB since it began its plugging program in 1997. +2002 Field Activity +West Cote Blanche Bay +In 2002, Gulfport continues to use the reprocessed 3-D seismic data to +identify and confirm intermediate and shallow prospects at WCBB. The Company +plans to begin a ten well drilling program in the second quarter of 2002. The +ten well program will consist of eight developmental intermediate depth wells, +one developmental shallow horizontal well and one exploratory shallow well. The +Company anticipates that these wells will access significant oil and gas +deposits with most of the wells having multiple targets ranging from relatively +low risk proven undeveloped objectives to higher potential exploratory targets. +Gulfport also anticipates several recompletions and workovers and will continue +to fulfill its plugging obligations during 2002. +East & West Hackberry +Gulfport will continue testing shut-in wells and putting them on permanent +or intermittent production as results warrant. The Company also plans several +recompletion projects for the Erwin and State Lease 50 portion of East +9 +Hackberry. Gulfport is in the process of generating projects in the West +Hackberry field. +Texaco Operated Well +In June of 1999, Gulfport executed a sublease in favor of Texaco of an +approximate 72 acre block below the base of the 8 Sand, located at approximately +9,060 feet, at WCBB and reserved a 25% back-in working interest after the +proceeds of the well totaled $1,000,000. The well paid out in December 1999. +Overriding Royalty Interests +Gulfport also owns overriding royalty interests in an additional 14 +producing oil and gas wells lying in four fields. +When Gulfport sold its interest in the Bayou Penchant Field to Castex +Energy 1996 Limited Partnership effective April 1, 1998, Gulfport retained a 10% +overriding royalty interest in this field. The Bayou Penchant field is located +in Terrebonne Parish, Louisiana and the 2001 average daily gross production from +five producing wells was 1,250 gross MCF of gas. +Gulfport also owns a 2.5% overriding royalty interest in three producing +wells at the Napoleonville Field retained when Gulfport sold its interest to +Plymouth Operating Company in 1998. The Napoleonville field is located in +Assumption Parish, Louisiana and averaged 150 gross barrels of oil per day in +2001. +Additionally, Gulfport owns a net profits interest in one producing well +and all the leasehold rights in the South Atchafalaya Bay Field located in St. +Mary Parish, Louisiana. This well was placed on production in late 1999. This +interest provided over $21,000 in net revenue to Gulfport in 2001. +The land occupied by a warehouse owned by Gulfport in Lafayette, LA covers +approximately one acre. The mineral rights underlying the building were +included in a unit drilled by Newfield Exploration Company. In April 2000, +effective June 1999, Gulfport backed into a working interest in the Gladys +Garber #1 well. During 2001, the well generated over $62,000 net to Gulfport's +interest. +Fee Minerals and Surface Interest +Gulfport owns 230 net acres of fee minerals and surface interest adjacent +to its West Hackberry Field in Cameron Parish, Louisiana. This property +currently contains six producing wells. +Castex Energy 1996 Limited Partnership +Castex Back-In +Gulfport sold its interest in the Bayou Penchant, Bayou Pigeon, Deer Island +and Golden Meadow fields to Castex Energy 1996 Limited Partnership effective +April 1, 1998 subject to a 25% reversionary interest in the partnership after +Castex had received 100% of the initial investment. Castex informed Gulfport +that the investment had paid out effective September 1, 2001. In lieu of a 25% +interest in the partnership, Gulfport elected to take a proportionately reduced +25% working interest in the properties. The Company now owns the following +working interest in the subject fields: +10 +Field Parish Working Interest +Bayou Penchant Terrebonne 3.125% +Bayou Pigeon Iberia 6.250% +Deer Island Terrebonne 6.250% +Golden Meadow Lafourche 3.125% +In addition to the producing wells and associated leasehold rights, +Gulfport has prepaid the drilling and completion costs of three new wells. +Other Interests +Litigation Trust +Gulfport owns a 12% interest in the Trust (the "Litigation Trust") that was +established in WRT's bankruptcy to pursue litigation connected with WRT. +The Litigation Trust filed approximately 400 preference actions and +several substantive actions alleging fraud, malpractice and other wrongdoings. +At this time, Gulfport cannot estimate what the potential future recovery from +the litigation will be. +Oil and Gas Marketing +Gulfport sells its oil and gas at the wellhead and does not refine +petroleum products. Other than normal production facilities, Gulfport does not +own an interest in any bulk storage facilities or pipelines. As is customary in +the industry, Gulfport sells its production in any one area to relatively few +purchasers, including transmission companies that have pipelines near Gulfport's +producing wells. Gas purchase contracts are generally on a short-term "spot +market" basis and usually contain provisions by which the prices and delivery +quantities for future deliveries will be determined. The majority of Gulfport's +crude oil production in 2001 was sold on contracts based on the average closing +price on NYMEX for each trading day during the month of delivery. +During 2001, oil sales to Gulfmark Energy Inc. accounted for 86% of +Gulfport's oil sales. Gulfport had no other purchasers that accounted for +greater than 10% of it's oil sales. Gulfport had no gas purchasers that +accounted for more than 10% of it's total sales. +Competition and Markets +Availability of Markets. The availability of a ready market for any oil +and/or gas produced by Gulfport depends on numerous factors beyond the control +of management, including but not limited to, the extent of domestic production +and imports of oil, the proximity and capacity of gas pipelines, the +availability of skilled labor, materials and equipment, the effect of state and +federal regulation of oil and gas production and federal regulation of gas sold +in interstate commerce. Oil and gas produced by Gulfport in Louisiana is sold to +various purchasers who service the areas where Gulfport's wells are located. +Gulfport's wells are not subject to any agreements that would prevent Gulfport +from either selling its production on the spot market or committing such gas to +a long-term contract; however, there can be no assurance that Gulfport will +continue to have ready access to suitable markets for its future oil and gas +production. +Impact of Energy Price Changes. Oil and gas prices can be extremely +volatile and are subject to substantial seasonal, political and other +fluctuations. The prices at which oil and gas produced by Gulfport may be sold +11 +is uncertain and it is possible that under some market conditions the production +and sale of oil and gas from some or all of its properties may not be +economical. The availability of a ready market for oil and gas and the prices +obtained for such oil and gas, depend upon numerous factors beyond the control +of Gulfport, including competition from other oil and gas suppliers and national +and international economic and political developments. Because of all of the +factors influencing the price of oil and gas, it is impossible to accurately +predict future prices. +Environmental Regulation +Operations of Gulfport are subject to numerous federal, state and local +laws and regulations governing environmental protection. Over the last several +years, state and federal environmental laws and regulations have become more +stringent and may continue to become more stringent in the future. These laws +and regulations may affect Gulfport's operations and costs as a result of their +affect on oil and gas development, exploration, and production operations. It is +not anticipated that Gulfport will be required in the near future to expend +amounts that are material in relation to its total capital expenditures program +by reason of environmental laws and regulations, but inasmuch as such laws and +regulations are frequently changed, Gulfport is unable to predict the ultimate +cost of compliance. +Operational Hazards and Insurance +Gulfport's operations are subject to all of the risks normally incident to +the production of oil and gas, including blowouts, cratering, pipe failure, +casing collapse, oil spills and fires, each of which could result in severe +damage to or destruction of oil and gas wells, production facilities or other +property, or injury to persons. The energy business is also subject to +environmental hazards, such as oil spills, gas leaks, and ruptures and discharge +of toxic substances or gases that could expose Gulfport to substantial liability +due to pollution and other environmental damage. Although Gulfport maintains +insurance coverage considered to be customary in the industry for a company its +size, it is not fully insured against certain of these risks, either because +such insurance is not available or because of high premium costs. The occurrence +of a significant event that is not fully insured against could have a material +adverse effect on Gulfport's financial position. +Headquarters and Other Facilities +Gulfport leases office space in Oklahoma City, Oklahoma under a lease +covering approximately 7,000 square feet. The monthly rent is approximately +$13,000. +In 1996, Gulfport purchased a building in Lafayette, Louisiana to be used +as Gulfport's Louisiana headquarters. The 16 year-old building contains 12,480 +total square feet with 8,180 square feet of finished office area and 6,300 +square feet of clear span warehouse area. The mortgage balance was +approximately $163,000 as of January 1, 2002 with an estimated fair market value +of $350,000. This building allows Gulfport to provide office space for +Louisiana personnel, have access to meeting space close to the fields and to +maintain a corporate presence in Louisiana. +Employees +At December 31, 2001 Gulfport had 13 employees. A Louisiana well +servicing company serves as contract operator of the fields and provides all +necessary field personnel. +12 +Item 2. Properties +Oil & Gas Reserves +The oil and gas reserve information set forth below represents estimates +as prepared by the independent engineering firm of Netherland, Sewell & +Associates, Inc. Reserve engineering is a subjective process of estimating +volumes of economically recoverable oil and gas that cannot be measured in an +exact manner. The accuracy of any reserve estimate is a function of the quality +of available data and of engineering and geological interpretation. As a +result, the estimates of different engineers often vary. In addition, the +results of drilling, testing, and production may justify revisions of such +estimates. Accordingly, reserve estimates often differ from the quantities of +oil and gas that are ultimately recovered. Estimates of economically recoverable +oil and gas and of future net revenues are based on a number of variables and +assumptions, all of which may vary from actual results, including geologic +interpretation, prices, and future production rates and costs. +The following table sets forth estimates of the proved oil and gas reserves of +Gulfport at December 31, 2001, as estimated by Netherland, Sewell & Associates, +an independent engineering firm. +January 1, 2002 +------------------------------------------ +Proved Reserves Developed Underdeveloped Total +----------- -------------- ------------ +Oil (MBBLS) 3,745 21,078 24,823 +Gas (MMCF) 3,499 21,226 24,725 +MBOE 4,328 24,616 28,944 +Year-end present value 10% of +estimated future net revenue $22,027,000 $108,370,200 $130,397,200 +Total proved reserves increased to 28,944 MBOE at January 1, 2002 from +25,129 at January 1, 2001. This increase in reserves is mainly attributable to +the Company's drilling activity during 2001 as well as the mapping of additional +proved undeveloped locations. +The estimated future net revenues set forth above were determined by using +reserve quantities of proved reserves and the periods in which they are expected +to be developed and produced based on economic conditions prevailing at December +31, 2001. The estimated future production is priced at December 31, 2001 +without escalation using $16.75 per BBL and $2.65 per MCF, adjusted by lease for +transportation fees and regional price differentials. +In compliance with federal law, Gulfport files annual reports with the +Energy Information Agency of the U.S. Department of Energy with respect to its +production of oil and gas during each calendar year and its estimated oil and +gas reserves at the end of each year. +Production, Prices, and Production Costs +The following is a table and graph of Gulfport's net production in 2001. +13 +Year Ended December 31, +2001 2000 1999 +---- ---- ---- +Production Volumes: +Oil (MBBLS) 595 530 576 +Gas (MMCF) 71 83 107 +Oil Equivalents (MBOE) 607 544 594 +Average Prices +Oil (per BBL) $25.25 $29.76 $16.86 +Gas (per MCF) $ 6.02 $ 4.04 $ 2.83 +Oil Equivalents (per MBOE) $25.48 $29.62 $16.86 +Average Production Costs (per BOE) $ 7.85 $ 9.35 $ 6.18 +Average Production Taxes (per BOE) $ 2.88 $ 3.02 $ 1.64 +(Graph Omitted) +Drilling and Recompletion Activities +The following table contains data with respect to certain of Gulfport's +field operations during the years ended December 31, 2001, 2000 and 1999. +2001 2000 1999 +Gross Net Gross Net Gross Net +------------ ------------ ------------ +Recompletions, Sidetracks +and Deepenings: +Oil 6 6 4 4 15 15 +Gas 0 0 0 0 0 0 +Non-Productive 0 0 1 1 12 12 +------------ ------------ ------------ +TOTAL: 6 6 5 5 27 27 +============ ============ ============ +Development Wells: +Oil 6 6 2 2 5 5 +Gas 0 0 1 1 0 0 +Non-Productive 0 0 1 1 1 1 +------------ ------------ ------------ +TOTAL: 6 6 4 4 6 6 +============ ============ ============ +Exploratory Wells: +Oil 1 1 0 0 0 0 +Gas 0 0 0 0 0 0 +Non-Productive 0 0 0 0 0 0 +------------ ------------ ------------ +TOTAL: 1 1 0 0 0 0 +============ ============ ============ +Title to Oil and Gas Properties +It is customary in the oil and gas industry to make only a cursory review +of title to undeveloped oil and gas leases at the time they are acquired and to +obtain more extensive title examinations when acquiring producing properties. In +future acquisitions, Gulfport will conduct title examinations on material +portions of such properties in a manner generally consistent with industry +practice. Certain of Gulfport's oil and gas properties may be subject to title +defects, encumbrances, easements, servitudes or other restrictions, none of +which, in management's opinion, will in the aggregate materially restrict +Gulfport's operations. +14 +Item 3. Legal Proceedings +Gulfport has been named as a defendant in various lawsuits. The +ultimate resolution of these matters is not expected to have a material adverse +affect on the Company's financial condition or results of operations for the +periods presented in the financial statements. +Item 4. Submission of Matters to a Vote of Security Holders +On November 28, 2001 the Board of Directors nominated five persons to serve +on the Board of Gulfport. On December 30, 2001 the holders of a majority of the +outstanding shares of Gulfport's common stock executed a written consent +electing the five nominated persons as directors of Gulfport. Each director +will serve until the next annual meeting or until he is succeeded by another +qualified director who has been elected. +The annual shareholder meeting for Gulfport for the year ended December +31, 2001 has been scheduled for April 15, 2002. +Item 4a. Executive Officers of the Registrant. +The officers of Gulfport are as follows: +Name Age Position +---- --- -------- +Mike Liddell 48 Chairman of the Board, Chief +Executive Officer, President and +Director +Michael G. Moore 45 Vice President and Chief +Financial Officer +Lisa Holbrook 31 Vice President, General Counsel +and Secretary +Mike Liddell has served as a director of Gulfport since July 11, 1997, as +Chief Executive Officer since April 28, 1998 and as Chairman of the Board since +July 28, 1998. Mr. Liddell has served as President of Gulfport since July 2000. +In addition, Mr. Liddell served as Chief Executive Officer of DLB from October +1994 to April 28, 1998, and as a director of DLB from 1991 through April 1998. +From 1991 to 1994, Mr. Liddell was President of DLB. From 1979 to 1991, he was +President and Chief Executive Officer of DLB Energy. He received a B.S. degree +in education from Oklahoma State University. He is the brother of Mickey +Liddell. +Michael G. Moore has served as Vice President and Chief Financial Officer +since July 2000. From May 1998 through July 2000, Mr. Moore served as Vice +President and Chief Financial Officer of Indian Oil Company. From September 1995 +through May 1998, Mr. Moore served as Controller of DLB Oil & Gas, Inc. Prior +to that, Mr. Moore served as Controller of LEDCO, Inc., a Houston based gas +marketing company. Mr. Moore received both his B.B.A degree in finance and his +M.B.A. from the University of Central Oklahoma. +Lisa Holbrook has served as Vice President and Secretary of Gulfport since +November 5, 1999, and as General Counsel since April 28, 1998. In addition, Ms. +Holbrook served as Assistant General Counsel of DLB until April 1998. In 1996, +Ms. Holbrook received her J.D. from Oklahoma City University Law School where +she graduated with highest distinction. +15 +PART II +Item 5. Market for Registrant's Common Equity and Related Stockholder Matters +Gulfport's Common Stock is traded on the NASD OTC Bulletin Board under the +symbol GPOR. The following table sets forth the high and low sales prices for +the Common Stock in each quarter: +YEAR ENDED DECEMBER 31, 2001 LOW HIGH +-------------------------------- ----- ----- +First Quarter $3.875 $4.500 +Second Quarter $4.000 $6.250 +Third Quarter $4.000 $4.600 +Fourth Quarter $4.250 $4.600 +Holders of Record +At the close of business on February 1, 2002 there were 10,146,566 shares +of Common Stock outstanding held by 363 shareholders of record. +Dividend Policy +Gulfport has never paid dividends on the Common Stock. Gulfport currently +intends to retain all earnings to fund its operations. Therefore, Gulfport does +not intend to pay any cash dividends on the Common Stock in the foreseeable +future. +Item 6. Selected Financial Data +As a result of the Reorganization Case and Plan, which was consummated +and became effective on July 11, 1997, Gulfport was required to present its +financial statements pursuant to fresh start reporting standards. Accordingly, +the financial statements of Gulfport are not comparable to the financial +statements of WRT. However, in the case of the statement of operations, the +Company believes that comments comparing calendar years are appropriate in order +to provide a more meaningful understanding of Gulfport's operations. +The following selected financial data as of and for the years ended +December 31, 2001, 2000, 1999, 1998 and as of and for the five months 21 days +ended December 31, 1997, for Gulfport and for the six months and 10 days ended +July 10, 1997, for the Predecessor Company are derived from the financial +statements of Gulfport included elsewhere in the Annual Report. The financial +data set forth below should be read in conjunction with "Management's Discussion +and Analysis of Financial Condition and Results of Operations" and the financial +statements of Gulfport and the notes thereto included elsewhere in this Annual +Report. +16 +Reorganized Company Predecessor Company +July 11, Six Months +Year ended 1997 to 10 Days +December 31, December 31, July 10, +2001 2000 1999 1998 1997 1997 +------- ------- ------- -------- -------- -------- +Statement of Operation Data (in thousands, except per share amounts) +Oil and gas sales $15,458 $16,118 $10,018 $ 8,298 $ 9,456 $ 10,138 +------- ------- ------- -------- -------- -------- +Operating expenses 11,929 11,635 9,978 66,415 11,478 11,002 +------- ------- ------- -------- -------- -------- +Net income (loss) from operations 3,529 4,483 40 (58,117) (2,022) (864) +------- ------- ------- -------- -------- -------- +Interest expense 381 596 934 1,534 727 1,106 +Proceeds for litigation trust - - 1,342 - - - +Reorganized cost - - - - - (7,771) +Net income (loss) before +dividends on preferred stock +an extraordinary item 5,417 4,459 641 (59,109) (1,713) (9,615) +Extraordinary item - - - - - 88,723 +Miscellaneous Income 1,921 - - - - - +Net income (loss) before dividends +on preferred stock 5,417 4,459 641 (59,109) (1,713) 79,108 +Dividends on preferred stock - - - - - (1,510) +Net income (loss) available to +common stock 5,417 4,459 641 (59,109) (1,713) 77,59 +Earnings (loss) per common and +common share equivalent 0.53 0.44 0.13 (72.35) (3.88) N/A +Average common and common +equivalent shares outstanding 10,147 10,145 5,120 817 442 9,539 +Capital expenditures $12,761 $ 6,658 $ 7,147 $ 991 $ 5,644 $ 2,562 +Reorganized Company +2001 2000 1999 1998 1997 +------- ------- ------- -------- -------- +Balance Sheet Data +Working capital (deficit) $(4,171) $ 132 $(1,352) $ (3,204) $ (719) +Property, plant and equipment, net 35,723 26,692 23,469 19,990 81,507 +Total assets 40,892 36,178 33,484 27,568 92,346 +Long term debt 143 301 179 381 13,528 +Shareholders' equity (deficit) $33,992 $28,573 $24,114 $ 18,503 $ 70,280 +(1) Operating expenses for 1998 include non-cash charges of $50,131,000 +for impairment of oil and gas properties, $271,000 for abandonment of +long-lived assets and a $244,000 provision for doubtful accounts. See +"Management's Discussion and Analysis of Financial Condition and +Results of Operations." +Item 7. Management's Discussion and Analysis of Financial Condition and Results +of Operations +The following discussion and analysis of the Company's financial condition +and results of operations is based in part on the financial statements and the +notes thereto included elsewhere in this Annual Report and should be read in +conjunction therewith. +Credit Facilities +On July 11, 1997 Gulfport entered into a $15,000,000 credit facility with +ING (U.S.) Capital Corporation. During 1998 and 1999, there were two amendments +to the facility and the maturity date was reset to June 30, 2000. On June 28, +2000, the Company repaid in full its credit facility at ING and established a +new credit facility at Bank of Oklahoma ("BOK"). Gulfport was advanced $1.6 +million on this new facility, which called for interest payments to be made +17 +monthly in addition to twelve monthly principal payments of $100,000, with the +remaining unpaid balance due on August 31, 2001. On March 22, 2001, Gulfport +executed a new note with BOK increasing the availability to $1,760,000, +increasing the monthly payments slightly to $110,000 beginning July 1, 2001 and +extending the maturity date to October 1, 2002. This new note replaces the +original BOK note dated June 28, 2000. +On May 22, 2001, the Company entered in to a revolving line of credit +agreement with Gulfport Funding, LLC, ("Gulfport Funding") which has ownership +in common with the Company. Under the terms of the agreement, the Company may +borrow up to $3,000,000, with borrowed amounts bearing interest at Bank of +America Prime Rate plus 4%. All outstanding principal amounts along with accrued +interest are due on February 22, 2002. The Company paid a facility commitment +fee of $60,000 in connection with this line of credit. This fee will be +amortized over the life of the agreement. As of December 31, 2001, the Company +borrowed $3,000,000 available under this line. +In accordance with the revolving credit agreement, the Company issued +108,625 warrants to CD Holdings, LLC. The exercise price of these warrants was +established as the average closing price of the Company's common stock for the +five days following the issuance of the warrants. The warrant agreement provides +for pro-rata adjustments to the number of warrants granted if the Company at any +time increases the number of outstanding shares or otherwise adjusts its +capitalization. +Accounting Change +Before July 11, 1997, Gulfport used the successful efforts method for +reporting oil and gas operations. On July 11, 1997, Gulfport converted to the +full cost pool method of accounting for its oil and gas operations. +Due to the restating of property values to comply with fresh start +accounting and the conversion from the successful efforts method to the full +cost pool method for reporting oil and gas operations as of July 1997, +comparison of depreciation, depletion, and amortization expense for the years +ended December 31, 2001, 2000, 1999 and 1998, with prior years will not be +meaningful. +Results of Operations +The markets for oil and gas have historically been, and will continue to +be, volatile. Prices for oil and gas may fluctuate in response to relatively +minor changes in supply and demand, market uncertainty and a variety of factors +beyond the control of Gulfport. Set forth in the table below are the average +prices received by the Company and production volumes during the periods +indicated. +Year Ended December 31, +2001 2000 1999 +---- ---- ---- +Production Volumes: +Oil (MBBLS) 595 530 576 +Gas (MMCF) 71 83 107 +Oil Equivalents (MBOE) 607 544 594 +Average Prices: +Oil (per BBL) $25.50 $29.76 $16.86 +Gas (per MCF) $ 4.20 $ 4.04 $ 2.83 +Oil Equivalents (per MBOE) $25.48 $29.62 $16.86 +Average Production Costs (per BOE) $ 7.85 $ 9.35 $ 6.18 +Average Production Taxes (per BOE) $ 2.88 $ 3.02 $ 1.64 +Comparison of Years Ended December 31, 2001 and 2000 +Gulfport reported net income attributable to common stock of $5,417,000 for +the year ended December 31, 2001, as compared with $4,459,000 for the year ended +December 31, 2000. The increase in earnings attributable to common stock of +$958,000 was due to gains recorded during 2001 on the settlement of disputed +amounts. +Oil and Gas Revenues. For the year ended December 31, 2001 Gulfport +reported oil and gas revenues of $15,458,000, a 4% decrease from revenues of +$16,118,000 in 2000. This $660,000 decrease in revenues is attributable to a 14% +decease in prices per BOE to $25.50 for the year ended December 31, 2001 as +compared to $29.76 for the same period in 2000. This decrease in revenues due to +18 +prices was primarily offset by an increase in total BOE's produced and sold +resulting from the successful completion of the Company's 2001 drilling program +initiated in January 2001. +Operating Expenses Including Production Taxes. Total lease operating +expenses decreased $215,000 to $6,517,000 for the year ended December 31, 2001 +as compared to $6,732,000 for the same period in 2000. This decrease was +primarily attributable to a reduction in gas lift costs for 2001 as compared to +the same period in 2000. +General and Administrative Expenses. Net General and administrative +expenses increased only slightly by $82,000 or 5% to $1,634,000 for the year +ended December 31, 2001 from $1,552,000 for the same period 2000. This increase +was due primarily to fees associated with consultations with the Company's +financial advisors. In addition, due to an increased number of employees, +Gulfport recognized increased levels of salaries and benefits expense for the +year ended December 31, 2001 as compared to the same period in 2000. These +increases were completely offset however by administrative reimbursements from +related party's companies. +Interest Expense. Interest expense decreased by $215,000 or 36% to +$381,000 for the year ended December 31, 2001 from $596,000 for the same period +in 2000. This decrease was due to the settlement of disputed amounts with a +third party. Prior to the settlement, Gulfport was accruing approximately +$25,000 per month in interest expense. +Litigation Trust. No revenues were received from the Litigation Trust for +the comparable periods in 2001 or 2000. +Other changes in income for the year ended December 31, 2001 as compared +to the year ended December 31, 2000 were attributable to the following factors: +Depreciation, Depletion and Amortization. Depreciation, depletion and +amortization expense was $3,778,000 for the year ended December 31, 2001, +consisting of $3,512,000 in depletion on oil and gas properties, $218,000 in +depreciation of other property and equipment and $48,000 in amortization +expense. This is a 13% increase when compared to the 2000 depreciation, +depletion and amortization expense of $3,351,000. This increase is due primarily +to an increase in production for the year ended December 31, 2001 to 607 MBOE as +compared to 544 MBOE for the same period in 2000. +19 +Income Taxes. As of December 31, 2001, the Company had a net operating loss +carryforward of approximately $83 million, in addition to numerous timing +differences which gave rise to a deferred tax asset of approximately $47 +million, which was fully reserved by a valuation allowance at that date. +Utilization of net operating loss carryforwards and other timing differences +will be recognized as a reduction in income tax expense in the year utilized. A +current tax provision of $2.17 million was provided for the year ended 2001, +which was fully offset by an equal income tax benefit due to operating loss +carryforwards and other deferred tax assets. +Gain on Settlement of Disputed Amounts. Other changes in income for the +period ended December 31, 2001 included $1.9 million of non-recurring income +related to the settlement of disputed amounts. During the second quarter of +2001, the Company reached a settlement with Texaco Exploration and Production, +Inc. ("Texaco") regarding previously disputed amounts, some of which date back +to periods which were prior to the Company's reorganization. The Company's net +gain resulting from this settlement was $754,000. Also included on "Gain on +Settlement of Disputed Amounts" for the year ended December 31, 2001, were items +previously recorded as accounts payable totaling $1,167,000 which were also +settled or had expired by December 31, 2001. Included in this total were certain +tax claims of $372,000 as discussed in Note 6 to the Financial Statements, as +well as $795,000 in funds which the Company had previously classified as +accounts payable at December 31, 2000 because it believed these funds exceeded +its share of revenues on properties which it owns. +Comparison of Years Ended December 31, 2000 and 1999 +Gulfport reported net income attributable to common stock of $4,459,000 +for the year ended December 31, 2000, as compared with $641,000 for the year +ended December 31, 1999. The increase in earnings attributable to common stock +of $3,818,000 was due primarily to a significant increase in average oil and gas +prices in 2000. +Oil and Gas Revenues. For the year ended December 31, 2000, Gulfport +reported oil and gas revenues of $16,118,000, a 61% increase from revenues of +$10,018,000 in 1999. This $6,100,000 increase in revenues is attributable to a +76% increase in prices per BOE to $29.76 for the year ended December 31, 2000 as +compared to $16.86 for the same period in 1999. This increase in revenues was +partially offset by a slight reduction in total BOE's produced and sold due to +natural production declines during the year. +Operating Expenses Including Production Taxes. Total lease operating +expenses increased $2,092,000 to $6,732,000 for the year ended December 31, 2000 +as compared to $4,640,000 for the same period in 1999. This increase was +partially attributable to a $1,028,000 increase in gas lift costs to $1,555,000 +for the year ended 2000 from $528,000 for the same period in 1999. This +increase in gas lift costs is attributable to the increased gas prices for 2000 +as compared to 1999 as well as increase in gas usage related to an increased +number of producing wells brought online in 2000. In addition, the increase in +operating expenses was also due in part to an approximately $763,000 increase in +production taxes for year ended 2000 as a result of increased revenues from +higher oil and gas prices. +General and Administrative Expenses. General and administrative expenses +decreased by $171,000 or 10% to $1,552,000 for the year ended December 31, 2000 +from $1,723,000 for the same period 1999. This decrease was due primarily to +Gulfport's continuing efforts to reduce overall general and administrative +costs. +20 +Interest Expense. Interest expense decreased by $338,000 or 36% to +$596,000 for the year ended December 31, 2000 from $934,000 for the same period +in 1999. This decrease was due to a reduction in Gulfport's interest bearing +debt of $1.9 million. +Litigation Trust. In 1999, the Company received proceeds of $1,342,000 from +the Trust. Since the Company had no basis in the Litigation Trust, the Company +recognized the entire proceeds of $1,342,000 as income in the month in which it +was received. No revenues were received from the Litigation Trust for the +comparable period in 2000. +Other changes in income for the year ended December 31, 2000 as compared +to the year ended December 31, 1999 were attributable to the following factors: +Depreciation, Depletion and Amortization. Depreciation, depletion and +amortization expense was $3,351,000 for the year ended December 31, 2000, +consisting of $3,126,000 in depletion on oil and gas properties, $209,000 in +depreciation of other property and equipment and $16,000 in amortization +expense. This is a 7% decrease when compared to the 1999 depreciation, depletion +and amortization expense of $3,615,000. This decrease is due primarily to a +reduction in total BOE's produced for the year ended December 31, 2000 as +compared to the same period in 1999. +Income Taxes. As of December 31, 2000, the Company had a net operating loss +carryforward of approximately $69 million, in addition to numerous timing +differences which gave rise to a deferred tax asset of approximately $41 +million, which was fully reserved by a valuation allowance at that date. +Utilization of net operating loss carryforwards and other timing differences +will be recognized as a reduction in income tax expense in the year utilized. A +current tax provision of $1.78 million was provided for the year ended December +31, 2000, which was fully offset by an equal income tax benefit due to operating +loss carryforwards and other deferred tax assets. +Capital Expenditures, Capital Resources and Liquidity +Net cash flow provided by operating activities for the year ended December +31, 2001 was $7.6 million, as compared to net cash flow provided by operating +activities of $6.3 million for the comparable period in 2000. +Net cash provided by financing activities for 2001 was $3.1 million as +compared to net cash used of $1.9 million during 2000. Net cash provided by +financing activities in 2001 included $3.0 million of proceeds from the new +Gulfport Funding, LLC credit facility while net cash used in 2000 included $3.5 +million of principle repayments. Net cash used in financing activities for 2000 +was $1.9 million as compared to net cash provided of $2.9 million during 1999. +Net cash used in financing activities in 2000 included $3.5 million of principle +payments to pay off the ING note and make principle payments on the new BOK +facility and the proceeds of $1.6 million from the new BOK facility. The 1999 +net cash flows provided by financing activities occurred as a result of the $3.2 +million from the Stockholder Credit Facility and the net proceeds from the 1999 +Regulation D Offering. The 1999 Regulation D Offering after expenses yielded +$4.97 million to Gulfport. Affiliated Stockholders subscribed for 4,040,011 +shares in the 1999 Regulation D Offering through the forgiveness of $3.0 +million in debt, thus netting $2.0 million to Gulfport for the net cash proceeds +from the 1999 Regulation D Offering. +Capital Expenditures. In 2001, Gulfport invested $12.8 million in oil and +gas properties and other property and equipment as compared to $6.7 million +during the comparable period in 2000. Of the $2.8 million the Company spent +during 2001, $6.8 million was spent on drilling and completion activity on new +wells and $6.0 million was spent on work over activity on existing wells. During +2001, Gulfport financed its capital expenditures with cash flow provided by +operations and borrowings under the Company's two credit facilities. +21 +Gulfport's strategy is to continue to increase cash flows generated by its +properties by undertaking new drilling, workover, sidetrack and recompletion +projects in the fields to exploit its extensive reserves. The Company has +upgraded its infrastructure by enhancing its existing facilities to increase +operating efficiencies, increase volume capacities and lower lease operating +expenses. Additionally, Gulfport has undertaken the reprocessing of its 3D +seismic data in its principal property, West Cote Blanche Bay. The reprocessed +data will enable the Company's geophysicists to generate new prospects and +enhance existing prospects in the intermediate zones in the field thus creating +a portfolio of new drilling opportunities in the most prolific depths of the +field. +Capital Resources. On July 11, 1997 Gulfport entered into a $15,000,000 +credit facility with ING (U.S.) Capital Corporation ("ING"). During 1998 and +1999, there were two amendments to the facility and the maturity date was reset +to June 30, 2000. On June 28, 2000, the Company repaid in full its credit +facility at ING and established a new credit facility at Bank of Oklahoma +("BOK"). Gulfport was advanced $1.6 million on this new facility, which called +for interest payments to be made monthly in addition to twelve monthly principal +payments of $100,000, with the remaining unpaid balance due on August 31, 2001. +On March 22, 2001, Gulfport executed a new note with BOK increasing the +availability to $1,760,000, increasing the monthly payments slightly to $110,000 +beginning July 1, 2001 and extending the maturity date to October 1, 2002. This +new note replaces the original BOK note dated June 28, 2000. +On May 22, 2001, the Company entered in to a revolving line of credit +agreement with Gulfport Funding, LLC, ("Gulfport Funding") which has ownership +in common with the Company. Under the terms of the agreement, the Company may +borrow up to $3,000,000, with borrowed amounts bearing interest at Bank of +America Prime Rate plus 4%. All outstanding principal amounts along with accrued +interest are due on February 22, 2002. The Company paid a facility commitment +fee of $60,000 in connection with this line of credit. This fee will be +amortized over the life of the agreement. As of December 31, 2001, the Company +borrowed $3,000,000 available under this line. +In March 2002, the Company commenced a Private Placement Offering of $10.0 +million dollars consisting of 10,000 Units. Each Unit consists of (i) one (1) +share of Cumulative Preferred Stock, Series A, of the Company (Preferred) and +(ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per +share. Dividends shall accrue on the Preferred Stock prior to the Mandatory +Redemption Date (as defined below) at the rate of 12% per annum payable +quarterly in cash or, at the option of the Company for a period not to exceed +two (2) years from the Closing Date, payable in whole or in part in additional +shares of the Preferred based on the Liquidation Preference (as defined below) +of the Preferred at the rate of 15% per annum. No other dividends shall be +declared or shall accrue on the Preferred. To the extent funds are legally +available, the Company is obligated to declare and pay the dividends on the +Preferred. The Warrants have a term of ten (10) years and an exercise price of +$4.00. The Company is required to redeem the Preferred on the fifth anniversary +of the first issuance and the Company may at its sole option, choose to redeem +the Preferred at any time before the expiration of the five years. +Two-thirds of the Preferred Stockholders can affect any Company action +which would effect their preference position. The Preferred cannot be sold or +transferred by its holders and the Company must use its best efforts to register +with the Securities and Exchange Commission ("SEC") the common stock issued in +connection with the exercise of the Warrants or, if possible, piggyback the +issued common stock if the Company participates in a public offering with the +SEC. +The Offering was made available to stockholders and affiliates of the +Company as of December 31, 2001 who were known to be accredited investors by the +Company. Purchasers were able to participate up to their pro-rata share of +ownership in the Company as of December 31, 2001. The Offering's initial closing +will begin March 29, 2002 and will continue until April 15, 2002. Mike +Liddell, the Company's Chief Executive Officer, shall have until September 30, +2002 to subscribe for his proportionate share of the Offering. +On March 29, 2002, Gulfport Funding, LLC, participated in the Offering +through a conversion of its $3.0 million dollar loan along with the accumulated +interest due from the Company for 3,262.98 Units. Additionally on March 29, +2002, entities controlled by the majority shareholder initially funded a share +of the Preferred Offering in the amount of $2,738,000. +As a result of the completion of the NSA engineering report for the year +ended January 1, 2002, the Company intends to initiate discussions with it's +banking institutions and attempt to put in a place a larger and longer-term +revolving credit facility. The Company cannot be sure however that they will be +successful. +The Company is also currently consulting with several financial advisors to +determine how to take advantage of the current market whether through internal +value creation or a capital markets transaction. +22 +Liquidity. The primary capital commitments faced by the Company are the +capital requirements needed to continue developing the Company's proved reserves +and to continue meeting the required principal payments on its term Credit +Facilities. +In Gulfport's January 1, 2002 reserve report, 85% of Gulfport's net +reserves were categorized as proved undeveloped. The proved reserves of +Gulfport will generally decline as reserves are depleted, except to the extent +that Gulfport conducts successful exploration or development activities or +acquires properties containing proved developed reserves, or both. +To realize reserves and increase production, the Company must continue its +exploratory drilling, undertake other replacement activities or utilize third +parties to accomplish those activities. The Company plans to begin a ten well +drilling program in the second quarter of 2002. The ten well program will +consist of eight developmental intermediate depth wells, one developmental +shallow horizontal well and one exploratory shallow well. The Company +anticipates that these wells will access significant oil and gas deposits with +most of the wells having multiple targets ranging from relatively low risk +proven undeveloped objectives to higher potential exploratory targets. Gulfport +also anticipates several recompletions and workovers in the field during 2002. +It is anticipated that these reserve development projects will be funded either +through the use of cash flow from operations when available, interim bank +financing, a long-term credit facility or by accessing the capital markets. The +cash flow generated from these new projects will be reinvested in the field to +complete more capital projects. +Commitments and Contingencies +Plugging and Abandonment Funds +In connection with the acquisition of the remaining 50% interest in the +WCBB properties, the Company assumed the obligation to contribute approximately +$18,000 per month through March, 2004, to a plugging and abandonment trust and +the obligation to plug a minimum of 20 wells per year for 20 years commencing +March 11, 1997. ChevronTexaco retained a security interest in production from +these properties until abandonment obligations to ChevronTexaco have been +fulfilled. Once the plugging and abandonment trust is fully funded, the Company +can access it for use in plugging and abandonment charges associated with the +property. As of December 31, 2001, the plugging and abandonment trust totaled +$2,272,000, including interest received during 2001 of approximately $55,000. +During October 2001, Gulfport completed the yearly program to meet its +plugging liability for the twelve-month period ending March 2001. The Company +plugged 26 non-producing wells at West Cote Blanche Bay. During March 2002, +Gulfport began to fulfill its yearly plugging commitment of 20 wells at WCBB for +the twelve-month period ending, March 2002. +In addition, the Company has letters of credit totaling $200,000 secured +by certificates of deposit being held for plugging costs in the East Hackberry +field. Once specific wells are plugged and abandoned the $200,000 will be +returned to the Company. +Texaco Global Settlement +Pursuant to the terms of a global settlement between ChevronTexaco and the +State of Louisiana which includes the State Lease No. 50 portion of Gulfport's +East Hackberry Field, Gulfport was obligated to commence drilling a well or +other qualifying development operation on certain non-producing acreage in the +field prior to March 1998. Because of prevailing market conditions during 1998, +23 +the Company believed it was commercially impractical to shoot seismic or +commence drilling operations on the subject property. As a result, Gulfport has +agreed to surrender approximately 440 non-producing acres in this field to the +State of Louisiana. At December 31, 2001, Gulfport was in the process of +releasing these properties to the State of Louisiana. +Year 2000 Compliance +Gulfport made all necessary investments in software systems and +applications to ensure it was Year 2000 compliant. Gulfport did not experience +any difficulties related to the Year 2000 rollover. Any cost associated with +the process of becoming Year 2000 compliant was not material. +Subsequent Events +In March 2002, the Company commenced a Private Placement Offering of $10.0 +million dollars consisting of 10,000 Units. Each Unit consists of (i) one (1) +share of Cumulative Preferred Stock, Series A, of the Company (Preferred) and +(ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per +share. Dividends shall accrue on the Preferred Stock prior to the Mandatory +Redemption Date (as defined below) at the rate of 12% per annum payable +quarterly in cash or, at the option of the Company for a period not to exceed +two (2) years from the Closing Date, payable in whole or in part in additional +shares of the Preferred based on the Liquidation Preference (as defined below) +of the Preferred at the rate of 15% per annum. No other dividends shall be +declared or shall accrue on the Preferred. To the extent funds are legally +available, the Company is obligated to declare and pay the dividends on the +Preferred. The Warrants have a term of ten (10) years and an exercise price of +$4.00. The Company is required to redeem the Preferred on the fifth anniversary +of the first issuance and the Company may at its sole option, choose to redeem +the Preferred at any time before the expiration of the five years. +Two-thirds of the Preferred Stockholders can affect any Company action +which would effect their preference position. The Preferred cannot be sold or +transferred by its holders and the Company must use its best efforts to register +with the Securities and Exchange Commission ("SEC") the common stock issued in +connection with the exercise of the Warrants or, if possible, piggyback the +issued common stock if the Company participates in a public offering with the +SEC. +The Offering was made available to stockholders and affiliates of the +Company as of December 31, 2001 who were known to be accredited investors by the +Company. Purchasers were able to participate up to their pro-rata share of +ownership in the Company as of December 31, 2001. The Offering's initial closing +will begin March 29, 2002 and will continue until April 15, 2002. Mike +Liddell, the Company's Chief Executive Officer, shall have until September 30, +2002 to subscribe for his proportionate share of the Offering. +On March 29, 2002, Gulfport Funding, LLC, participated in the Offering +through a conversion of its $3.0 million dollar loan along with the accumulated +interest due from the Company for 3,262.98 Units. Additionally on March 29, +2002, entities controlled by the majority shareholder initially funded a share +of the Preferred Offering in the amount of $2,738,000. +Item 8. Financial Statements and Supplementary Data +The information required by this item appears on pages F-1 through F-22 +following the signature pages of this Report. +Item 9. Changes in and Disagreements with Accountants on Accounting and +Financial Disclosure. +None +PART III +Item 10. Directors and Executive Officers of the Registrant. +The officers and directors of Gulfport are as follows: +Name Age Position +---- --- ------- +Mike Liddell 48 Chairman of the Board, Chief Executive +Officer, President and Director +Michael G. Moore 45 Vice President and +Chief Financial Officer +Lisa Holbrook 31 Vice President, General Counsel and +Secretary +Robert E. Brooks 55 Director +*David L. Houston 49 Director +*Mickey Liddell 40 Director +*Dan Noles 54 Director +*Members of Gulfport's Audit Committee. +24 +Mike Liddell has served as a director of Gulfport since July 11, 1997, as +Chief Executive Officer since April 28, 1998 and as Chairman of the Board since +July 28, 1998. Mr. Liddell has served as President of Gulfport since July 2000. +In addition, Mr. Liddell served as Chief Executive Officer of DLB from October +1994 to April 28, 1998, and as a director of DLB from 1991 through April 1998. +From 1991 to 1994, Mr. Liddell was President of DLB. From 1979 to 1991, he was +President and Chief Executive Officer of DLB Energy. He received a B.S. degree +in education from Oklahoma State University. He is the brother of Mickey +Liddell and brother in law of Dan Noles. +Michael G. Moore has served as Vice President and Chief Financial Officer +since July 2000. From May 1998 through July 2000, Mr. Moore served as Vice +President and Chief Financial Officer of Indian Oil Company. From September 1995 +through May 1998, Mr. Moore served as Controller of DLB Oil & Gas, Inc. Prior to +that, Mr. Moore served as Controller of LEDCO, Inc., a Houston based gas +marketing company. Mr. Moore received his B.B.A degree in finance from the +University of Central Oklahoma in 1982 and in 1987 also completed his M.B.A. +from the University of Central Oklahoma. +Lisa Holbrook has served as Vice President and Secretary of Gulfport since +November 5, 1999, and as General Counsel since April 28, 1998. In addition, Ms. +Holbrook served as Assistant General Counsel of DLB until April 1998. In 1996, +Ms. Holbrook received her J.D. from Oklahoma City University Law School where +she graduated with highest distinction. +Robert E. Brooks has served as a director of Gulfport since July 11, 1997. +Mr. Brooks is currently a partner with Brooks Greenblatt, a commercial finance +company located in Baton Rouge, Louisiana that was formed by Mr. Brooks in July +1997. Mr. Brooks is a Certified Public Accountant and was Senior Vice President +in charge of Asset Finance and Managed Assets for Bank One, Louisiana between +1993 and July 1997. He received his B.S. degree from Purdue University in +mechanical engineering in 1969. He obtained graduate degrees in finance and +accounting from the Graduate School of Business at the University of Chicago in +1974. +David Houston has served as a director of Gulfport since July 1998. Since +1991, Mr. Houston has been the principal of Houston & Associates, a firm that +offers life and disability insurance, compensation and benefits plans and estate +planning. Prior to 1991, he was President and Chief Executive Officer of Equity +Bank for Savings, F.A., a $600 million, Oklahoma-based savings bank. He +currently serves on the board of directors and executive committee of Deaconess +Hospital, Oklahoma City, Oklahoma, and is the former chair of the Oklahoma State +Ethics Commission and the Oklahoma League of Savings Institutions. He received a +Bachelor of Science degree in business from Oklahoma State University and a +graduate degree in banking from Louisiana State University. +Mickey Liddell has served as a director of Gulfport since January 1999. Mr. +Liddell is currently the President of Banner Entertainment, Inc., a motion +picture production company in Los Angeles, California. Prior to 1994, Mr. +Liddell owned and managed wholesale nutrition product stores in Los Angeles. +Mr. Liddell received a Bachelor of Arts from the University of Oklahoma in +Communications in 1984 and a graduate degree from Parson School of Design in New +York, New York in 1987. He is the brother of Mike Liddell and the brother in +law of Dan Noles. +Dan Noles was appointed to the Board of Directors in January of 2000. Mr. +Noles has served as the president of Atoka Management Company, an oilfield +equipment company, since 1993. Mr. Noles received his Bachelor degree in +25 +Finance from the University of Oklahoma in 1970. Mr. Noles is the +brother-in-law to Mike Liddell and Mickey Liddell. +Items 11 & 12. +For information concerning Item 11 - Executive Compensation and Item 12 - +Security Ownership of Certain Beneficial owners and Management, see the +definitive Proxy Statement of Gulfport Energy Corporation for the Annual Meeting +of Shareholders to be held on April 15, 2002, which will be filed with the +Securities and Exchange Commission within 120 days after the close of the +Registrant's year and is incorporated herein by this reference (with the +exception of portions noted therein that are not incorporated by reference). +See also Part I - Item 4A - Executive Officers of the Registrant. +Item 13. Certain Relationships and Related Transactions +In March 2001, a company that shares common ownership with Gulfport +acquired a majority of the oil and natural gas properties of a mid-continent +exploration and production company. Subsequent to the acquisition, Gulfport +began providing administrative services to effectively manage the day-to-day +operations of this acquisition and in turn receives an administrative service +fee for such services. +26 +PART IV +Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. +(a) 1. Financial Statements. The following Financial Statements +of the Company, the Notes thereto, and the reports thereon are +filed under Item 8 of this Report. +Independent Auditors Report F-2 +Balance Sheets, December 31, 2001 and 2000 F-3 +Statements of Income, Years Ended December 31, 2001, 2000 and 1999 F-4 +Statements of Stockholders' Equity, Years Ended December 31, 2001, +2000 and 1999. F-5 +Statements of Cash Flows, Years Ended December 31, 2001, 2000 +and 1999 F-6 +Notes to Financial Statements F-7 +2. Financial Statement Schedules. All financial statement schedules +have been omitted, as the required information is inapplicable or is +not present in amounts sufficient to require submission of the +schedule or the information is presented in the Financial Statements +or related notes. +3. Exhibits. +10.1 Credit Agreement Dated June 28, 2000 between Registrant and +Bank of Oklahoma Filed March 30, 2001 +10.2 Stock Option Plan Filed March 30, 2001 +10.3 Credit Agreement dated February 1, 2001 between Registrant +and Bank of Oklahoma +(b). Reports on Form 8-K +June 30, 2000 - Disclosure of bank debt reduction and hiring of +new CFO +27 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities and +Exchange Act of 1934 as amended, the Registrant has duly caused this report to +be signed on its behalf by the undersigned thereunto duly authorized. +Date: March 30, 2001. +GULFPORT ENERGY CORPORATION +By:/s/Mike Liddell +------------------------------------- +Mike Liddell, Chief Executive Officer +Pursuant to the requirements of the Securities and Exchange Act of 1934 as +amended, this report has been signed below by the following persons on behalf of +the Registrant and in the capacity and on the date indicated. +Date: March 30, 2002 By:/s/Mike Liddell +------------------------------------ +Mike Liddell, Chief Executive +Officer And Director +Date: March 30, 2002 By:/s/Robert Brooks +------------------------------------- +Robert Brooks, Director +Date: March 30, 2002 By:/s/David L. Houston +------------------------------------- +David L. Houston, Director +Date: March 30, 2002 By:/s/Mickey Liddell +------------------------------------- +Mickey Liddell, Director +Date: March 30, 2002 By:/s/Dan Noles +------------------------------------- +Dan Noles, Director +Date: March 30, 2002 By:/s/Michael G. Moore +------------------------------------- +Michael G. Moore, Vice President and +Chief Financial Officer +28 +EXHIBIT INDEX +10.7 Credit Agreement Dated June 28, 2000 between Registrant and +Bank of Oklahoma Filed March 30, 2001 +10.8 Stock Option Plan Filed March 30, 2001 +10.9 Credit Agreement dated February 1, 2001 between Registrant +and Bank of Oklahoma +29 +Item 8. Financial Statements and Supplementary Data +INDEX TO FINANCIAL STATEMENTS +Page +---- +Independent Auditors' Report F-2 +Balance Sheets, December 31, 2001 and 2000 F-3 +Statements of Income, Years Ended December 31, 2001, +2000 and 1999 F-4 +Statements of Shareholders' Equity, Years Ended December +31, 2001, 2000 and 1999 F-5 +Statements of Cash Flows, Years Ended December 31, 2001, 2000 +and 1999 F-6 +Notes to Financial Statements F-7 +All financial statement schedules are omitted, as the required information is +inapplicable or the information is presented in the financial statements or +related notes. +F-1 +INDEPENDENT AUDITORS' REPORT +The Board of Directors and +Stockholders of Gulfport Energy Corporation: +We have audited the accompanying balance sheets of Gulfport Energy +Corporation (a Delaware corporation) as of December 31, 2001 and 2000, and the +related statements of income, stockholders' equity, and cash flows for the years +ended December 31, 2001, 2000 and 1999. These financial statements are the +responsibility of Gulfport's management. Our responsibility is to express an +opinion on these financial statements based on our audits. +We conducted our audits in accordance with auditing standards generally +accepted in the United States of America. Those standards require that we plan +and perform the audits to obtain reasonable assurance about whether the +financial statements are free of material misstatement. An audit includes +examining, on a test basis, evidence supporting the amounts and disclosures in +the financial statements. An audit also includes assessing the accounting +principles used and significant estimates made by management, as well as +evaluating the overall financial statement presentation. We believe that our +audits provide a reasonable basis for our opinion. +In our opinion, the financial statements referred to above present fairly, +in all material respects, the financial position of Gulfport Energy Corporation +as of December 31, 2001 and 2000, and the results of its operations and its cash +flows for the years ended December 31, 2001, 2000 and 1999, in conformity with +accounting principles generally accepted in the United States of America. +HOGAN & SLOVACEK +Oklahoma City, OK +March 29, 2002 +F-2 +GULFPORT ENERGY CORPORATION +BALANCE SHEETS +December 31, +-------------------------- +2001 2000 +------------ ------------ +Assets +Current assets: +Cash and cash equivalents $ 1,077,000 $ 3,657,000 +Accounts receivable, net of allowance for +doubtful accounts of $239,000 and $244,000 +at December 31, 2001 and 2000, respectively 1,096,000 3,608,000 +Accounts receivable - related party 160,000 - +Prepaid expenses and other current assets 253,000 171,000 +------------ ------------ +Total current assets 2,586,000 7,436,000 +------------ ------------ +Property and equipment: +Oil and natural gas properties 103,344,000 90,640,000 +Other property and equipment 1,976,000 1,919,000 +Accumulated depletion, depreciation, +amortization and impairment reserve (69,597,000) (65,867,000) +------------ ------------ +Property and equipment, net 35,723,000 26,692,000 +------------ ------------ +Other assets 2,583,000 2,050,000 +------------ ------------ +$ 40,892,000 $ 36,178,000 +=========== ============ +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable and accrued liabilities $ 2,637,000 $ 6,426,000 +Note payable - related party 3,000,000 - +Current maturities of long-term debt 1,120,000 878,000 +------------ ------------ +Total current liabilities 6,757,000 7,304,000 +------------ ------------ +Long-term debt 143,000 301,000 +------------ ------------ +Total liabilities 6,900,000 7,605,000 +------------ ------------ +Commitments and contingencies - - +Stockholders' equity: +Preferred stock - $.01 par value, 1,000,000 +authorized, none issued - - +Common stock - $.01 par value, 15,000,000 +authorized, 10,146,566 and 10,145,400 issued +and outstanding at December 31, 2001 and 2000, +respectively 101,000 101,000 +Paid-in capital 84,192,000 84,190,000 +Accumulated deficit (50,301,000) (55,718,000) +------------ ------------ +Total stockholders' equity 33,992,000 28,573,000 +------------ ------------ +Total liabilities and stockholders' +equity $ 40,892,000 $ 36,178,000 +============ ============ +See accompanying notes to financial statements. +F-3 +GULFPORT ENERGY CORPORATION +STATEMENTS OF INCOME +Year ended December 31, +---------------------------------------- +2001 2000 1999 +------------ ----------- ----------- +Revenues: +Gas sales $ 298,000 $ 337,000 $ 303,000 +Oil and condensate sales 15,160,000 15,781,000 9,715,000 +Other income 215,000 252,000 - +------------ ----------- ----------- +15,673,000 16,370,000 10,018,000 +------------ ----------- ----------- +Costs and expenses: +Operating expenses 4,767,000 5,098,000 3,472,000 +Production taxes 1,750,000 1,634,000 1,168,000 +Depreciation, depletion, and +amortization 3,778,000 3,351,000 3,615,000 +General and administrative 1,634,000 1,552,000 1,667,000 +Provision for doubtful accounts - - 56,000 +------------ ----------- ----------- +11,929,000 11,635,000 9,978,000 +------------ ----------- ----------- +INCOME FROM OPERATIONS 3,744,000 4,735,000 40,000 +------------ ----------- ----------- +OTHER (INCOME) EXPENSE: +Gain on settlement of disputed +amounts (1,921,000) - - +Interest expense 381,000 596,000 934,000 +Interest income (133,000) (320,000) (193,000) +Proceeds from Litigation Trust - - (1,342,000) +------------ ----------- ----------- +(1,673,000) 276,000 (601,000) +------------ ----------- ----------- +INCOME BEFORE INCOME TAXES 5,417,000 4,459,000 641,000 +INCOME TAX EXPENSE (BENEFIT): +Current 2,167,000 1,784,000 255,000 +Deferred (2,167,000) (1,784,000) (255,000) +------------ ----------- ----------- +- - - +------------ ----------- ----------- +NET INCOME $ 5,417,000 $ 4,459,000 $ 641,000 +============ =========== =========== +NET INCOME PER COMMON SHARE: +Basic $ 0.53 $ 0.44 $ 0.13 +============ =========== =========== +Diluted $ 0.52 $ 0.43 $ 0.13 +============ =========== =========== +See accompanying notes to financial statements. +F-4 +GULFPORT ENERGY CORPORATION +Statements of Stockholders' Equity +Additional +Preferred Common Stock Paid-in Accumulated +Stock Shares Amount Capital Deficit +--------- --------- ---------- ----------- ------------ +Balance at December 31, 1998 $ - 3,445,400 $1,723,000 $77,598,000 (60,818,000) +Change in par value of +common stock - - (1,689,000) 1,689,000 - +------ ---------- ---------- ----------- ----------- +Balance as restated, +December 31, 1998 - 3,445,400 34,000 79,287,000 (60,818,000) +Regulation D offering - 6,700,000 67,000 4,903,000 - +Net income - - - - 641,000 +------ ---------- ---------- ----------- ----------- +Balance at December 31, 1999 - 10,145,400 101,000 84,190,000 (60,177,000) +Net income - - - - 4,459,000 +------ ---------- ---------- ----------- ----------- +Balance at December 31, 2000 - 10,145,400 101,000 84,190,000 (55,718,000) +Common shares issued - 1,166 - 2,000 - +Net income - - - - 5,417,000 +------ ---------- ---------- ----------- ----------- +Balance at December 31, 2001 $ - 10,146,566 $ 101,000 $84,192,000 $(50,301,000) +====== ========== ========== =========== =========== +See accompanying notes to financial statements. +F-5 +GULFPORT ENERGY CORPORATION +Statements of Cash Flows +Year ended December 31, +---------------------------------------- +2001 2000 1999 +------------ ----------- ----------- +Cash flows from operating activities: +Net income $ 5,417,000 $ 4,459,000 $ 641,000 +Adjustments to reconcile net income +to net cash provided by operating +activities: +Depletion, depreciation and +amortization 3,730,000 3,335,000 3,615,000 +Provision for doubtful accounts +receivable - - 56,000 +Amortization of debt issuance costs 44,000 16,000 108,000 +Changes in operating assets and +liabilities: +(Increase) decrease in accounts +receivable - related (160,000) - - +(Increase) decrease in accounts +receivable 2,512,000 (1,553,000) (455,000) +(Increase) decrease in prepaid +expenses (126,000) (51,000) (10,000) +(Decrease) increase in accounts +payable and accrued liabilities (3,789,000) 130,000 2,406,000 +------------ ----------- ----------- +Net cash provided by operating +activities 7,628,000 6,336,000 6,361,000 +------------ ----------- ----------- +Cash flows from investing activities: +Additions to cash held in escrow (533,000) (55,000) (92,000) +Redemption of Certificates of +Deposit - 200,000 - +Capital expenditures (12,761,000) (6,658,000) (7,147,000) +Proceeds from sale of oil and +gas properties - 100,000 47,000 +Proceeds from sale of equipment - - 5,000 +Increase (decrease) in other assets - (19,000) (94,000) +------------ ----------- ----------- +Net cash used in investing activities (13,294,000) (6,432,000) (7,281,000) +------------ ----------- ----------- +Cash flows from financing activities: +Proceeds from sales of common stock 2,000 - 4,971,000 +Proceeds from borrowings - +related party 3,000,000 - - +Proceeds from borrowings 960,000 1,600,000 3,210,000 +Principle payments on borrowings (876,000) (3,495,000) (5,311,000) +Payment of loan origination fees - (16,000) - +------------ ----------- ----------- +Net cash provided by (used in) +financing activities 3,086,000 (1,911,000) 2,870,000 +------------ ----------- ----------- +Net (decrease) increase in cash and +cash equivalents (2,580,000) (2,007,000) 1,950,000 +Cash and cash equivalents at beginning +of period 3,657,000 5,664,000 3,714,000 +------------ ----------- ----------- +Cash and cash equivalents at end +of period $ 1,077,000 $ 3,657,000 $ 5,664,000 +============ =========== =========== +Supplemental disclosure of cash flow +information: +Interest payments $ 114,000 $ 240,000 $ 476,000 +============ =========== =========== +See accompanying notes to financial statements. +F-6 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport is a domestic independent oil and gas exploration, development and +production company with properties located in the Louisiana Gulf Coast. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original +maturity of three months or less to be cash equivalents for purposes of the +statement of cash flows. +Oil and Gas Properties +The Company uses the Full Cost method of accounting for oil and gas +operations. Accordingly, all costs, including nonproductive costs and certain +general and administrative costs associated with acquisition, exploration and +development of oil and gas properties, are capitalized. Net capitalized costs +are limited to the estimated future net revenues, after income taxes, discounted +at 10% per year, from proven oil and gas reserves and the cost of the properties +not subject to amortization. Such capitalized costs, including the estimated +future development costs and site remediation costs, if any, are depleted by an +equivalent units-of-production method, converting gas to barrels at the ratio of +six MCF of gas to one barrel of oil. No gain or loss is recognized upon the +disposal of oil and gas properties, unless such dispositions significantly alter +the relationship between capitalized costs and proven oil and gas reserves. Oil +and gas properties not subject to amortization consist of the cost of +undeveloped leaseholds. These costs are reviewed periodically by management for +impairment, with the impairment provision included in the cost of oil and gas +properties subject to amortization. Factors considered by management in its +impairment assessment include drilling results by Gulfport and other operators, +the terms of oil and gas leases not held by production, and available funds for +exploration and development. +Other Property and Equipment +Depreciation of other property and equipment is provided on a straight- +line basis over estimated useful lives of the related assets, which range from +seven to 30 years. +Reclassifications +Certain reclassifications have been made to the 2000 and 1999 financial +statements presentations in order to conform to the 2001 financial statements +presentation. +Net Income per Common Share +Basic net income per common share is computed by dividing income +attributable to common stock by the weighted average number of common shares +outstanding for the period. Diluted net income per common share reflects the +potential dilution that could occur if options or other contracts to issue +F-7 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +common stock were exercised or converted into common stock. Calculations of +basic and diluted net income per common share are illustrated in Note 12. +Income Taxes +Gulfport uses the asset and liability method of accounting for income +taxes, under which, deferred tax assets and liabilities are recognized for the +future tax consequences of (1) temporary differences between the financial +statement carrying amounts and the tax bases of existing assets and liabilities +and (2) operating loss and tax credit carryforwards. Deferred income tax assets +and liabilities are based on enacted tax rates applicable to the future period +when those temporary differences are expected to be recovered or settled. The +effect of a change in tax rates on deferred tax assets and liabilities is +recognized in income during the period the rate change is enacted. Deferred tax +assets are recognized as income in the year in which realization becomes +determinable. +Revenue Recognition +Gas revenues are recorded in the month produced using the entitlement +method, whereby any production volumes received in excess of the Company's +ownership percentage in the property are recorded as a liability. If less than +Gulfport's entitlement is received, the underproduction is recorded as a +receivable. There is no such liability or asset recorded at December 31, 2001 +or December 31, 2000. Oil revenues are recognized in the month produced. +Use of Estimates +The preparation of financial statements in conformity with generally +accepted accounting principles requires management to make estimates, judgments +and assumptions that affect the reported amounts of assets and liabilities as of +the date of the financial statements and revenues and expenses during the +reporting period. Actual results could differ materially from those estimates. +Significant estimates with regard to these financial statements include the +estimate of proved oil and gas reserve quantities and the related present value +of estimated future net cash flows there from and future net operating loss +carryforwards available as reductions of income tax expense. +Commitments and Contingencies +Liabilities for loss contingencies arising from claims, assessments, +litigation or other sources are recorded when it is probable that a liability +has been incurred and the amount can be reasonably estimated. +Segment Information +The Company's only revenue generating activity is the production and sale +of oil and gas. Therefore, no reporting of business segments has been included +in these financial statements or the notes thereto. +2. ACCOUNTS RECEIVABLE - RELATED PARTY +Included in the accompanying December 31, 2001 balance sheet are amounts +receivable from entities that have similar controlling interests as those +F-8 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +controlling the Company. These receivables represent amounts billed by the +Company for general and administrative functions performed by Gulfport's +personnel on behalf of the related party companies during 2001. Gulfport has +reduced its corresponding expenses by $325,000 billed to the companies for +performance of these services. +3. PROVISION FOR ALLOWANCE FOR DOUBTFUL ACCOUNTS +A summary of the activity in the allowance for doubtful accounts for the +years ended December 31, 2001 and 2000 is as follows: +2001 2000 +------------- ------------- +Balance, beginning of the year $ 244,000 $ 244,000 +Provision for bad debts - - +Bad debts written off (5,000) - +------------- ------------- +$ 239,000 $ 244,000 +============= ============= +No charges to bad debt expense were made during the years ended December 31, +2001 and 2000. During the year ended December 31, 1999, the Company charged +$56,000 to bad debt expense. The 1999 bad debt expense related to receivables +on properties no longer owned by Gulfport. +4. PROPERTY AND EQUIPMENT +The major categories of property and equipment and related accumulated +depreciation, depletion and amortization as of December 31 are as follows: +2001 2000 +------------- ------------- +Oil and gas properties $ 103,344,000 $ 90,640,000 +Office furniture and fixtures 1,499,000 1,442,000 +Building 217,000 217,000 +Land 260,000 260,000 +------------- ------------- +Total property and equipment $ 105,320,000 $ 92,559,000 +------------- ------------- +Accumulated depreciation, depletion, +amortization and impairment reserve (69,597,000) (65,867,000) +------------- ------------- +Property and equipment, net $ 35,723,000 $ 26,692,000 +============= ============= +Included in oil and gas properties at December 31, 2001 and 2000, are +$1,217,000 and $801,000, respectively, in general and administrative costs +incurred and capitalized to the full cost pool. General and administrative costs +capitalized to the full cost pool are those incurred directly related to +exploration and development activities such as geological costs and other +administrative costs associated with overseeing the exploration and development +activities. All general and administrative costs not directly associated with +exploration and development activities were charged to expense as they were +incurred. During 1999, $413,000 in general and administrative costs were +capitalized to the full cost pool. +F-9 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +During 2000, the Company sold equipment related to oil and gas properties +totaling $100,000. The sale of these properties was treated as a reduction to +the full cost pool. +5. OTHER ASSETS +Other assets as of December 31 consist of the following: +2001 2000 +------------- ------------- +Plugging and abandonment escrow account +on the WCBB properties $ 2,272,000 $ 1,739,000 +CDs securing letter of credit 200,000 200,000 +Deposits 111,000 111,000 +------------- ------------ +$ 2,583,000 $ 2,050,000 +============= ============ +6. SETTLEMENT OF CLAIMS +In accordance with a reorganization that took place during 1997, Gulfport +accrued certain tax claims totaling $372,000, which are included in the +accompanying balance sheet at December 31, 2000 as current liabilities. At +December 31, 2001 management determined these claims would not be asserted and +they were written off. The resulting income has been included in "Gain on +Settlement of Disputed Amounts" in the accompanying statement of income for the +year ended December 31, 2001. +7. LONG-TERM DEBT +Long-term debt as of December 31 is as follows: +2001 2000 +------------- ------------- +Note payable to bank, payable in +monthly payments of $110,000, including +interest at the Chase Manhattan Prime +rate plus 1% (5.75% at December 31, 2001), +with final payment of outstanding +principal and accrued interest amounts due +October 2002. $ 1,100,000 $ - +Note payable to bank, payable in +monthly payments of $100,000, including +interest at the Chase Manhattan +Prime rate plus 1%, with final payment +of outstanding principal and accrued +interest amounts due August 2001. +The outstanding balance at December 1, +2000, was refinanced effective February 1, +2001. - 1,000,000 +Note payable to bank, payable in +monthly payments of $2,900, including +interest at 9.5%, concluding May, 2004, +collaterized by land and building. 163,000 179,000 +------------ ------------ +Total 1,263,000 1,179,000 +Less - current maturities of long-term debt (1,120,000) (878,000) +------------ ------------ +Debt reflected as long-term $ 143,000 $ 301,000 +============ ============ +Following are the maturities of long-term debt for each of the next three +years: +2002 $1,120,000 +2003 21,000 +2004 122,000 +---------- +$1,263,000 +========== +Note Payable Refinancing +On February 1, 2001, Gulfport refinanced its $1,000,000 note payable which +was outstanding at December 31, 2000. Additional borrowings of $960,000 were +also made during April 2001, bringing the total amount borrowed to $1,760,000, +which is the total available under this line. Under the terms of the new +agreement, monthly principal payments of $110,000 were to be made beginning July +1, 2001, with the remaining outstanding principal due October 1, 2002. The +refinanced note bears interest at Chase Manhattan Prime rate plus 1%. +F-11 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +Building Loan +In 1996, the Company purchased a building in Lafayette, Louisiana to be +used as Gulfport's Louisiana headquarters. The building is 12,480 square feet +with approximately 6,180 square feet of finished office area and 6,300 square +feet of warehouse space. This building allows Gulfport to provide office space +for Louisiana personnel, have access to meeting space close to the fields and to +maintain a corporate presence in Louisiana. +8. NOTE PAYABLE - RELATED PARTY +On May 22, 2001, the Company entered in to a revolving line of credit +agreement with Gulfport Funding, LLC, ("Gulfport Funding") which has ownership +in common with the Company. Under the terms of the agreement, the Company may +borrow up to $3,000,000, with borrowed amounts bearing interest at Bank of +America Prime Rate plus 4%. The Company paid a facility commitment fee of +$60,000 in connection with this line of credit. This fee will be amortized over +the life of the agreement. As of December 31, 2001, the Company had borrowed the +$3,000,000 available under this line. All outstanding principal amounts along +with accrued interest were due on February 22, 2002. +In accordance with the revolving credit agreement, the Company issued +108,625 warrants to CD Holdings, LLC. The exercise price of these warrants was +established as the average closing price of the Company's common stock for the +five days following the issuance of the warrants. The warrant agreement provides +for pro-rata adjustments to the number of warrants granted if the Company at any +time increases the number of outstanding shares or otherwise adjusts its +capitalization. +On March 29, 2002, the outstanding balance on this note, along with +accumulated interest due on the note, were retired through Gulfport Funding's +participation in the Company's Private Placement Offering as described in Note +17. +9. COMMON STOCK OPTIONS, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company granted its Chief Financial Officer 10,000 stock options with +an exercise price of $2.00 per share and an effective date of July 15, 2000. +The options vest 35% in July 2001, and 35% in July 2002 with the remaining +shares vesting in 2003. The option agreement provides for pro-rata adjustments +F-12 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +to the options granted if the Company at any time increases the number of +outstanding shares or otherwise alters its capitalization. +During January, 2000, the Company's Chief Executive Officer, employees, and +non-employee directors were granted a total of 313,635 stock options with an +exercise price of $2.00 per share. The options vest 35% in January 2001, and 35% +in January 2002, with the remaining options vesting in January 2003. The option +agreements provide for pro-rata adjustments to options granted if the Company at +any time increases the number of outstanding shares or otherwise alters its +capitalization. +On June 1, 1999, Gulfport's Chief Executive Officer and President were each +granted stock options for the purchase of 2.5% of the outstanding shares of +Common Stock at an exercise price of $2.00 per share. The options vest 35% on +June 1, 2000, and 35% on June 1, 2001, with the remaining options vesting on +June 1, 2002. The option agreements provide for pro-rata adjustments to options +granted if Gulfport at any time increases the number of outstanding shares or +otherwise alters its capitalization. Stock options previously granted to the +President were surrendered to Gulfport upon his death in December 1999. +On September 15, 1999, all non-employee board members were each granted +10,000 options with an exercise price of $2.00. The options vest 33% on October +1, 1999, and 33% on October 1, 2000, with the remaining options vesting on +October 1, 2001. These options granted to non-employee board members will be +adjusted on a pro-rata basis to reflect any change in the capitalization of the +Company. +Options outstanding at December 31, 2001 totaled 607,355. Of this total, +319,080 options were exercisable at December 31, 2001, with the remaining +options vesting in future periods. +Warrants +In accordance with the revolving credit agreement discussed in Note 8, the +Company issued 108,625 warrants to CD Holdings, LLC. The exercise price of these +warrants was estimated as the average closing price of the Company's common +stock for the five days following the issuance of the warrants. The warrant +agreement provides for pro-rata adjustments to the number of warrants granted it +the Company at any time increases the number of outstanding shares or otherwise +adjusts its capitalization. +Also, at December 31, 2001, 1,163,195 warrants, each for the purchase of +one share of Gulfport's common stock, were outstanding. All of these warrants +were issued pursuant to a 1997 warrant agreement, stemming from a reorganization +which occurred that year. The warrants will expire on July 11, 2002 and are +exercisable at $10 per warrant. +The related agreement contains several anti-dilutive provisions that +provide for adjustments to the terms of the warrants in the event of any +recapitalization by Gulfport. As a result of Gulfport's capitalization changes +as described below, which occurred subsequent to the issuance of these warrants, +each warrant outstanding at December 31, 2001 can purchase .234 shares of common +stock. +F-13 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +Reverse Stock Split +On March 5, 1999, the Board of Directors authorized a 50-to-1 reverse stock +split, thereby decreasing the number of issued and outstanding shares to +3,445,400, and increasing the par value of each share to $.50. Subsequent to +this reverse stock split, the par value was reduced to $.01. +Regulation D Private Placement Offering +During September 1999, Gulfport conducted a private placement of stock (the +"Regulation D Offering"). In accordance with the provisions of certain +exemptions, the Regulation D Offering was made only to Accredited Investors as +defined in Regulation D. +Gulfport offered 6,700,000 shares of common stock at an exercise price of +$.75 per share. Each shareholder exercising his basic subscription privilege in +full was entitled to oversubscribe for additional shares. A total of 6,700,000 +shares were subscribed, yielding $5,016,000, net of offering costs. As of the +date of the Regulation D Offering, affiliated Shareholders were owed $3,238,000 +by the Company. In the Regulation D Offering, the Affiliated Shareholders +acquired 4,040,011 common shares through the forgiveness of $3,030,000 of this +debt, with the remaining balance of $208,000 paid in cash during 1999. +10. SETTLEMENT OF DISPUTED AMOUNTS +During the second quarter of 2001, the Company reached a settlement with +Texaco Exploration and Production, Inc. ("Texaco") regarding previously disputed +amounts, some of which date back to periods which were prior to the Company's +reorganization. The Company's net gain resulting from this settlement is +included in the accompanying statement of income for the year ended December 31, +2001, as "Gain on Settlement of Disputed Amounts" in the amount of $754,000. +Also included on "Gain on Settlement of Disputed Amounts" for the year +ended December 31, 2001, were items previously recorded as accounts payable +totaling $1,167,000 which were also settled or had expired by December 31, 2001. +Included in this total were certain tax claims of $372,000 as discussed in Note +6, as well as $795,000 in funds which the Company had previously classified as +accounts payable at December 31, 2000 because it believed these funds exceeded +its share of revenues on properties which it owns. +11. INCOME TAXES +A reconciliation of the statutory federal income tax amount to the recorded +expense follows: +F-14 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +2001 2000 1999 +----------- ----------- ---------- +Income before federal income taxes $ 5,417,000 $ 4,459,000 $ 641,000 +----------- ----------- ---------- +Expected income tax at statutory rate 2,167,000 1,784,000 255,000 +Net operating loss carryforward +utilized (2,167,000) (341,000) - +Other deferred tax assets utilized - (1,443,000) (255,000) +----------- ----------- ---------- +Income tax expense recorded $ - $ - $ - +=========== =========== ========== +The tax effects of temporary differences and net operating loss +carryforwards, which give rise to deferred tax assets at December 31 are +estimated as follows: +2001 2000 +------------ ----------- +Net operating loss carryforward $ 32,403,000 $ 18,231,000 +Oil and gas property basis difference 14,181,000 23,089,000 +------------ ------------ +Total deferred tax asset 46,584,000 41,320,000 +Valuation allowance (46,584,000) (41,320,000) +------------ ------------ +Net deferred tax asset (liability) $ - $ - +============ ============ +The Company has an available tax net operating loss carry forward estimated +at approximately $83,085,000 as of December 31, 2001. This carryforward will +begin to expire in the year 2013. +12. NET INCOME PER COMMON SHARE +A reconciliation of the components of basic and diluted net income per +common share is presented in the table below: +2001 2000 1999 +------------------------------- ------------------------------- ---------------------------- +Per Per Per +Income Shares Share Income Shares Share Income Shares Share +---------- ---------- ----- ---------- ---------- ----- -------- --------- ----- +Basic: +Income attributable +to common stock $5,417,000 10,146,112 $0.53 $4,459,000 10,145,400 $0.44 $641,000 5,120,255 $0.13 +===== ===== ===== +Effective of dilutive +securities: +Stock options - 342,261 - 259,567 - - +---------- ---------- ---------- ---------- -------- --------- +Diluted: +Income attributable +to common stock, +after assumed +dilutions $5,417,000 10,488,373 $0.52 $4,459,000 10,404,967 $0.43 $641,000 5,120,255 $0.13 +========== ========== ===== ========== ========== ===== ======== ========= ===== +Common stock equivalents not included in the above calculations of diluted +income are 1,163,195 warrants issued in 1997. Also not included in the +calculation of 2001 diluted earnings per share are 108,625 warrants issued in +connection with the Company's line of credit with Gulfport Funding, as discussed +in Note 8. Also, not included in the calculation of the 1999 diluted income per +F-15 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +share are 253,635 stock options issued to an officer of Gulfport in June 1999 +and 30,000 stock options issued to certain directors in September 1999. These +potential common shares were not considered in the calculations due to their +anti-dilutive effect during the periods presented. +13. RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business +activities with a substantial number of its shareholders. +DLB Oil & Gas, Inc. ("DLB") and Wexford Management LLC ("Wexford") were, +along with Gulfport, co-proponents in a 1997 plan of reorganization. During +April of 1998, DLB distributed all of its shares in the Company to its +shareholders prior to DLB's acquisition by Chesapeake Energy Corporation. As a +result of this distribution, Charles Davidson, Mike Liddell and Mark Liddell +collectively received 37.5% of the Company's stock. As of December 31, 2001, +Wexford and its affiliates owned approximately 17.7% of Gulfport's issued +outstanding stock. Charles Davidson, Mike Liddell and the Estate of Mark Liddell +own collectively 55.8% of the Company's outstanding stock as of December 31, +2001. +Administrative Service Agreement +Pursuant to the terms and conditions of an Administrative Services +Agreement, DLB agreed to make available to the Company personnel, services, +facilities, supplies, and equipment as needed, including executive and +managerial, accounting, auditing and tax, engineering, geological and +geophysical, legal, land and administrative and clerical services. The initial +term was one year beginning on the date of the Administrative Services +Agreement. The Administrative Services Agreement was to continue for successive +one-year periods unless terminated by either party. On April 28, 1998, in +connection with the acquisition of DLB, Inc. by Chesapeake Energy Corporation, +the obligations of DLB under the Administrative Services Agreement were assigned +to DLB Equities, L.L.C. +Gulfport paid fees under this agreement totaling $21,000 in 1999 and +believes that such fees are comparable to those that would have been charged by +an independent third party. Effective June of 1999, this Administrative Service +Agreement was terminated. +Stockholder Credit Facility +On August 18, 1998, Gulfport entered into a $3,000,000 revolving credit +facility with Liddell Investments, L.L.C., Liddell Holdings, L.L.C., CD +Holdings, L.L.C. and Wexford Entities (collectively "Affiliated Stockholders"). +Borrowing under the Stockholder Credit Facility was due on August 17, 1999 and +bore interest at LIBOR plus 3%. Pursuant to the facility agreement, Gulfport +paid the eligible Affiliated Stockholders an aggregate commitment fee equal to +$60,000. Gulfport repaid $2,000,000 of principal under the Amended ING Credit +Agreement with borrowings under the Stockholder Credit Facility. The remaining +$1,000,000 was used for working capital and general corporate purposes. The +Affiliated Stockholders paid the subscription price for 1,200,000 shares +pursuant to their Basic Subscription Privilege in the Rights Offering through +F-16 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +the forgiveness of the amount owed to them under this stockholder credit +facility. +On August 5, 1999, Gulfport entered into a $3,255,000 revolving credit +facility with the "Affiliated Stockholders". Borrowing under this agreement was +due on August 1, 2000, and bore interest at LIBOR plus 3%. Pursuant to the terms +of the agreement, Gulfport paid aggregate commitment fees equal to $65,000 or 2% +of the related borrowings in stock. This debt was extinguished through the +issuance of 4,040,011 shares of common stock to the Affiliated Stockholders in +the Regulation D Offering in August 1999, and through the payment of additional +funds totaling $208,000. +14. COMMITMENTS +Leases +As of December 31, 2001 and 2000, the Company had no long-term, +non-cancelable operating lease commitments. Rental expense for all operating +leases for the years ended December 31, 2001, 2000 and 1999, totaled $127,000, +$112,000 and $119,000, respectively. +Plugging and Abandonment Funds +In connection with the acquisition of the remaining 50% interest in the +WCBB properties, the Company assumed the obligation to contribute approximately +$18,000 per month through March, 2004, to a plugging and abandonment trust and +the obligation to plug a minimum of 20 wells per year for 20 years commencing +March 11, 1997. Texaco retained a security interest in production from these +properties until abandonment obligations to Texaco have been fulfilled. Once the +plugging and abandonment trust is fully funded, the Company can access it for +use in plugging and abandonment charges associated with the property. As of +December 31, 2001, the plugging and abandonment trust totaled $2,272,000, +including interest received during 2001 of approximately $55,000. +During October 2001, Gulfport completed the yearly program to meet its +plugging liability for the twelve month period ending March 2001. The Company +plugged 26 non-producing wells at West Cote Blanche Bay. During March 2002, +Gulfport began to fulfill its yearly plugging commitment of 20 wells at WCBB for +the twelve month period ending, March 2002. +Texaco Global Settlement +Pursuant to the terms of a global settlement between Texaco and the State +of Louisiana which includes the State Lease No. 50 portion of Gulfport's East +Hackberry Field, Gulfport was obligated to commence drilling a well or other +qualifying development operation on certain non-producing acreage in the field +prior to March 1998. Because of prevailing market conditions during 1998, the +Company believed it was commercially impractical to shoot seismic or commence +drilling operations on the subject property. As a result, Gulfport has agreed to +surrender approximately 440 non-producing acres in this field to the State of +Louisiana. At December 31, 2001, Gulfport was in the process of releasing these +properties to the State of Louisiana. +F-17 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +Contributions to 401(k) Plan +During 1999, Gulfport sponsored a 401(k) savings plan under which eligible +employees could chose to contribute up to 15% of their total compensation on a +pre-tax basis, subject to certain IRS limits. Gulfport did not incur any +expense related to this plan during the year ended December 31, 1999. On +February 17, 1999, this 401(k) savings plan was terminated and all contributions +were distributed to the participants. +Effective January 1, 2000, Gulfport began sponsoring new 401(k) and Profit +Sharing plans under which eligible employees may contribute up to 15% of their +total compensation through salary deferrals. Also under these plans, the +Company will make a contribution each calendar year on behalf of each employee +equal to at least 3% of his or her salary, regardless of the employee's +participation in salary deferrals. During the years ended December 31, 2001 and +2000, Gulfport incurred $20,000 and $24,000, respectively, in contributions +expense related to this plan. +Employment Agreement +At December 31, 2001, Gulfport had an employment agreement with its Chief +Executive Officer. This agreement expires June 1, 2004, and calls for an annual +salary of $200,000, which may be adjusted for cost of living increases. +15. CONTINGENCIES +Other Litigation +The Company has been named as a defendant on various other litigation +matters. The ultimate resolution of these matters is not expected to have a +material adverse effect on the Company's financial condition or results of +operations for the periods presented in the financial statements. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry principally in the state of +Louisiana with sales to refineries, re-sellers such as pipeline companies, and +local distribution companies. While certain of these customers are affected by +periodic downturns in the economy in general or in their specific segment of the +oil and gas industry, Gulfport believes that its level of credit-related losses +due to such economic fluctuations has been immaterial and will continue to be +immaterial to the Company's results of operations in the long term. No bad debt +expense was incurred during 2001 or 2000. During 1999, Gulfport incurred bad +debts of $56,000. +The Company maintains cash balances at several banks. Accounts at each +institution are insured by the Federal Deposit Insurance Corporation up to +$100,000. At December 31, 2001 and 2000, Gulfport held cash in excess of +insured limits in these banks totaling $977,000 and $3,556,000, respectively. +During the year ended December 31, 2001, approximately 86% of Gulfport's +revenues from oil and gas sales were attributable to Gulfmark Energy Inc. +During the year ended December 31, 2000, approximately 91% of Gulfport's +revenues from oil and gas sales were attributable to two primary customers: +F-18 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +Black Hills Energy and Equiva Trading Company. During the year ended December +31, 1999, approximately 99% of Gulfport's revenues from oil and gas sales were +attributable to five primary customers: Equiva Trading Company, Black Hills +Energy Resources, Inc., Flash Oil & Gas Southwest, Inc., Burlington Resources, +and Plains All American, Inc. +16. LITIGATION TRUST ENTITY +Pursuant to the Company's 1997 plan of reorganization, all of Gulfport's +possible causes of action against third parties (with the exception of certain +litigation related to recovery of marine and rig equipment assets and claims +against Tri-Deck), existing as of the effective date of that plan, were +transferred into a "Litigation Trust" controlled by an independent party for the +benefit of most of the Company's existing unsecured creditors. The litigation +related to recovery of marine and rig equipment and the Tri-Deck claims were +subsequently transferred to the Litigation Trust as described below. +The Litigation Trust was funded by a $3,000,000 cash payment from the +Company, which was made on the effective date of reorganization. Gulfport owns a +12% interest in the Litigation Trust with the other 88% being owned by the +former general unsecured creditors of Gulfport. For financial statement +reporting purposes, Gulfport has not recognized the potential value of +recoveries which may ultimately be obtained, if any, as a result of the actions +of the Litigation Trust, treating the entire $3,000,000 payment as a +reorganization cost at the time of Gulfport's reorganization. +On January 20, 1998, Gulfport and the Litigation Trust entered into a +Clarification Agreement whereby the rights to pursue various claims reserved by +Gulfport under the plan of reorganization were assigned to the Litigation Trust. +In connection with this agreement, the Litigation Trust agreed to reimburse the +Company $100,000 for legal fees Gulfport had incurred in connection these +claims. As additional consideration for the contribution of this claim to the +Litigation Trust, Gulfport is entitled to 20% to 80% of the net proceeds from +these claims. +There were no funds received from the Litigation Trust during the year +ended December 31, 2001 and 2000. During 1999, Gulfport received $1,342,000 in +proceeds from the Litigation Trust. +17. SUBSEQUENT EVENT +In March 2002, the Company commenced a Private Placement Offering of $10.0 +million dollars consisting of 10,000 Units. Each Unit consists of (i) one (1) +share of Cumulative Preferred Stock, Series A, of the Company (Preferred) and +(ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per +share. Dividends shall accrue on the Preferred Stock prior to the Mandatory +Redemption Date (as defined below) at the rate of 12% per annum payable +quarterly in cash or, at the option of the Company for a period not to exceed +two (2) years from the Closing Date, payable in whole or in part in additional +shares of the Preferred based on the Liquidation Preference (as defined below) +of the Preferred at the rate of 15% per annum. No other dividends shall be +declared or shall accrue on the Preferred. To the extent funds are legally +available, the Company is obligated to declare and pay the dividends on the +Preferred. The Warrants have a term of ten (10) years and an exercise price of +$4.00. The Company is required to redeem the Preferred on the fifth anniversary +of the first issuance and the Company may at its sole option, choose to redeem +the Preferred at any time before the expiration of the five years. +Two-thirds of the Preferred Stockholders can affect any Company action +which would effect their preference position. The Preferred cannot be sold or +transferred by its holders and the Company must use its best efforts to register +with the Securities and Exchange Commission ("SEC") the common stock issued in +connection with the exercise of the Warrants or, if possible, piggyback the +issued common stock if the Company participates in a public offering with the +SEC. +The Offering was made available to stockholders and affiliates of the +Company as of December 31, 2001 who were known to be accredited investors by the +Company. Purchasers were able to participate up to their pro rata share of +ownership in the Company as of December 31, 2001. The Offering's initial closing +will begin March 29, 2002 and will continue until April 15, 2002. Mike +Liddell, the Company's Chief Executive Officer, shall have until September 30, +2002 to subscribe for his proportionate share of the Offering. +On March 29, 2002, Gulfport Funding, LLC, participated in the Offering +through a conversion of its $3.0 million dollar loan along with the accumulated +interest due from the Company for 3,262.98 Units. Additionally, on March 29, +2002, entities controlled by the majority shareholder initially funded a share +of the Preferred Offering in the amount of $2,738,000. +F-19 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +18. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION +ACTIVITIES (UNAUDITED) +The following is historical revenue and cost information relating to the +Company's oil and gas operations located entirely in the southeastern United +States: +Capitalized Costs Related to Oil and Gas Producing Activities +2001 2000 +------------- ------------- +Proven Properties $ 103,344,000 $ 90,640,000 +Accumpulated depreciation, depletion +Amortizaiton and impairment reserve (68,685,000) (65,173,000) +------------- ------------- +Proven properties, net $ 34,659,000 $ 25,467,000 +============= ============= +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +2001 2000 1999 +----------- ---------- ---------- +Acquisition $ - $ - $ 337,000 +Development 12,704,000 6,505,000 6,803,000 +----------- ---------- ---------- +Total $12,704,000 $6,505,000 $7,140,000 +=========== ========== ========== +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the +production and sale of oil and gas. The income tax expense is calculated by +applying the current statutory tax rates to the revenues after deducting costs, +which include depreciation, depletion and amortization allowances, after giving +effect to the permanent differences. The results of operations exclude general +office overhead and interest expense attributable to oil and gas production. +F-20 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +2001 2000 1999 +----------- ---------- ----------- +Revenues $15,458,000 $16,117,000 $10,018,000 +Production costs (6,517,000) (6,732,000) (4,640,000) +Depletion (3,512,000) (3,125,000) (3,410,000) +----------- ----------- ----------- +5,429,000 6,260,000 1,968,000 +----------- ----------- ----------- +Income tax expense +Current 2,172,000 2,504,000 781,000 +Deferred (2,172,000) (2,504,000) (781,000) +----------- ----------- ----------- +- - - +----------- ----------- ----------- +Results of operations +from producting activities $ 5,429,000 $ 6,260,000 $ 1,968,000 +=========== =========== =========== +Oil and Gas Reserves +The following table presents estimated volumes of proven and proven +undeveloped oil and gas reserves as of December 31, 2001, 2000, and 1999 and +changes in proven reserves during the last three years, assuming continuation of +economic conditions prevailing at the end of each year. Volumes for oil are +stated in thousands of barrels (MBbls) and volumes for gas are stated in +millions of cubic feet (MMCF). The weighted average prices at December 31, 2001 +used for reserve report purposes are $16.75 and $2.65, adjusted by lease for +transportation fees and regional price differentials, for oil and gas reserves, +respectively. +Gulfport emphasizes that the volumes of reserves shown below are estimates +which, by their nature, are subject to revision. The estimates are made using +all available geological and reservoir data, as well as production performance +data. These estimates are reviewed annually and revised, either upward or +downward, as warranted by additional performance data. +2001 2000 1999 +-------------- -------------- -------------- +Oil Gas Oil Gas Oil Gas +------ ------ ------ ------ ------ ------ +Proven Reserves +Beginning of the period 22,098 18,188 25,923 6,264 24,282 3,331 +Purchases in oil and +gas reserves in place - - - - 1,594 2,762 +Extensions, discoveries +and other additions - - - - +Revisions of prior +reserve estimates 3,320 6,608 (3,295) 12,007 641 297 +Current production (595) (71) (530) (83) (594) (126) +Sales of oil and gas +reserves in place - - - - - - +------ ------ ------ ------ ------ ------ +End of period 24,823 24,725 22,098 18,188 25,923 6,264 +====== ====== ====== ====== ====== ====== +Proven developed reserves 3,745 3,499 3,066 2,077 6,606 2,073 +====== ====== ====== ====== ====== ====== +F-21 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +Discounted Future Net Cash Flows +Estimates of future net cash flows from proven oil and gas reserves were +made in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing +activities." The following tables present the estimated future cash flows, and +changes therein, from Gulfport's proven oil and gas reserves as of December 31, +2001, 2000, and 1999, assuming continuation of economic conditions prevailing at +the end of each year. +Standardized Measure of Discounted Future Net Cash Flows Relating to Proven Oil +and Gas Reserves +YEAR ENDED DECEMBER 31, +------------------------------------------- +2001 2000 1999 +------------- ------------- ------------- +Future cash flows $ 522,246,000 $ 763,942,000 $ 676,056,000 +Future development costs (132,310,000) (118,857,000) (132,708,000) +Future production costs (88,373,000) (93,817,000) (91,705,000) +Future production taxes (53,247,000) (67,349,000) (83,392,000) +------------- ------------- ------------- +Future net cash flows before +income taxes 248,316,000 483,919,000 368,251,000 +10% discount to reflect timing +of cash flows (117,919,000) (203,025,000) (222,896,000) +------------- ------------- ------------- +Discounted future net cash flows 130,397,000 280,894,000 145,355,000 +Future income taxes, net of 10% +discount (1,475,000) (68,037,000) (14,602,000) +------------- ------------- ------------- +Standardized measure of +discounted future net +cash flows $ 128,922,000 $ 212,857,000 $ 130,753,000 +============= ============= ============= +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to +Proven Oil and Gas Reserves +YEAR ENDED DECEMBER 31, +---------------------------------------- +2001 2000 1999 +------------ ------------ ------------ +Sales and transfers of oil +and gas produced, net of +production costs $ (8,941,000) $ (9,386,000) $ (5,378,000) +Net changes in prices and +production costs (344,592,000) 104,539,000 113,060,000 +Acquisition of oil and gas +reserves in place, less +related production costs - - 4,978,000 +Extensions, discoveries and +improven recovery, less +related costs - - - +Revisions of previous quantity +estimates, less related +production costs 117,930,000 20,515,000 3,722,000 +Sales of reserves in place - - - +Accretion of discount 85,106,000 19,871,000 1,550,000 +Net changes in income taxes 66,562,000 (53,435,000) (14,602,000) +Other - - - +------------ ------------ ------------ +Total change in standardized +measure of discounted future +net cash flows $(83,935,000) $ 82,104,000 $103,330,000 +============ ============ ============ +F-22 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +Comparison of Standardized Measure of Discounted Future Net Cash Flows to the +Net Carrying Value of Proven Oil and Gas Properties at December 31, 2001 and +2000 is as follows: +2001 2000 +------------ ------------ +Standardized measure of discounted +future and net cash flows $130,397,000 $280,894,000 +Proven oil and gas properties 103,344,000 90,640,000 +Less accumulated depreciation, depletion, +amortization and impairment reserve (68,685,000) (65,173,000) +Net carrying value of proven oil and +gas properties 34,659,000 25,467,000 +------------ ------------ +Standardized measure of discounted future net +cash flows in excess of net carrying +value of proven oil and gas properties $ 95,738,000 $255,427,000 +============ ============ +F-23 +EXHIBIT 10.3 +John N. Huff +Vice President +Energy Banking +(405) 272-2028 +Fax 272-2588 +jhuff@bokf.com +February 1, 2001 +Mr. Mike Liddell +Gulfport Energy Corporation +6307 Waterford Blvd., Suite 100 +Oklahoma City, OK 73118 +Re: Loan Agreement Covenants +Dear Mike, +This letter is written to evidence our mutual understanding between Gulfport +Energy Corporation ("Borrower") and Bank of Oklahoma ("Bank") regarding a +$1,760,000 loan to Gulfport Energy Corporation. Borrower agrees to the +following conditions in connection with its obligation to Bank of Oklahoma: +1. Any proceeds from the sale of oil/gas properties having an aggregate +selling price in excess of $100,000 will be applied to the loan +balance. +2. Borrower will not encumber any oil and gas producing properties. +3. No material changes in the ownership of Gulfport without Bank consent. +4. Current assets divided by current liabilities, exclusive of obligations +to Bank shall exceed 1.0 at all times. +5. Borrower's indebtedness other than trade payables incurred in the +ordinary course of business and excluding all loans from Bank of +Oklahoma is limited to $100,000 without prior Bank consent. +6. Borrower will not pay any dividends or redeem any shares without prior +Bank consent. +7. Borrower will maintain its primary depository accounts with the Bank. +Please sign below as your acceptance of these terms and conditions. +We appreciate the opportunity to provide you with this credit facility. +Very truly yours, +John N. Huff +Vice President +Agreed and accepted this _____ day of February 2001. +For the Borrower: +By: +---------------------------------------------------- +Mike Liddell, Chief Executive Officer \ No newline at end of file diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/filing_metadata.csv b/raw/filings/0000874499/2001/0001060830-02-000041/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..a1e3ef4a99a1247ed92bfe11434e0f1f85f346f4 --- /dev/null +++ b/raw/filings/0000874499/2001/0001060830-02-000041/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2002-04-01,2001-12-31,2002-04-01T05:00:00.000Z,0001060830-02-000041,gulfportenergy10k2001.txt,,173966,0,0,https://www.sec.gov/Archives/edgar/data/874499/000106083002000041/gulfportenergy10k2001.txt,https://www.sec.gov/Archives/edgar/data/874499/000106083002000041/,2001,2001,1 diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/item1.txt b/raw/filings/0000874499/2001/0001060830-02-000041/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..18ded52be0129a8a5cf6c230e65d35fb004229e7 --- /dev/null +++ b/raw/filings/0000874499/2001/0001060830-02-000041/item1.txt @@ -0,0 +1,415 @@ +Item 1. Business +Description of Business +Gulfport is an independent oil and gas exploration and production +company with properties located in the Louisiana Gulf Coast. Gulfport has a +market enterprise value of approximately $50.9 million dollars and generated +EBITDA of $9.6 million dollars for the twelve months ended December 31, 2001. As +of December 31, 2001, the Company had 29 MMBOE proved reserves with a present +value (10%) of estimated future net reserves of $130 million dollars. +Gulfport is actively pursuing further development of its properties in +order to fully exploit its reserves. The Company has a substantial portfolio of +low risk developmental projects for the next several years providing the +opportunity to increase production and cash flow. Gulfport's developmental +program is designed to reach the Company's high impact, higher potential rate of +return prospects through the penetration of several producing horizons. +Additionally, Gulfport owns 3-D seismic data, which along with the +Company's technical expertise, will be used to identify exploratory prospects +and test undrilled fault blocks in existing fields. +Background +Gulfport is the successor of WRT Energy Corporation ("WRT"). WRT filed for +bankruptcy in February 1996. Gulfport emerged as the reorganized company in July +1997. +4 +Principal Oil and Gas Properties +Gulfport owns interests in a number of producing oil and gas properties +located along the Louisiana Gulf Coast. The following is a map showing the +locations of Gulfport's principal oil and gas properties. +(MAP OMITTED) +Gulfport serves as the operator of substantially all of the properties in +which it holds a working interest with the exception of the Texaco ("Texaco" or +"ChevronTexaco") well and deep rights at West Cote Blanche Bay. During 2001 +Chevron acquired Texaco. The following table presents certain information as of +January 1, 2002 reflecting Gulfport's net interest in its producing oil and gas +properties. +Net Proved Reserves +Shut-in As of 1/1/02 +------------------- +Field NRI/WI Active Wells wells(1) Acreage(2) Gas Oil Total +-------------- ------------ ----------- +Percentages Gross Net Gross Net Gross Net MBOE MBOE MBOE +--------------------------------------------------------------------------------------------------------- +E Hackberry 78.7/100 17 17 73 73 3,147 3,147 590 3,392 3,982 +W Hackberry 87.5/100 2 2 25 25 592 592 47 248 295 +West Cote +Blanche Bay (3) 78.7/100 48 47 296 296 4,590 4,590 3,384 20,906 24,290 +Overrides/Royalty Various 12 1 6 1 403 403 100 277 377 +------------------------------------------------------------------------ +TOTAL 79 67 400 395 8,732 8,732 4,121 24,823 28,944 +======================================================================== +(1) The following wells produce on an intermittent basis: East Hackberry - +4; West Hackberry - 1; and West Cote Blanche Bay - 6.All of Gulfport's +acreage is Developed Acreage. +(2) Includes 1 producing well and 3 shut-in wells attributable to depths +below the Rob "C" Marker ("Deep Rights"). Gulfport has a 7.45% +non-operated working interest (5.84% NRI) in the Deep Rights. The Deep +Rights are operated by ChevronTexaco Corporation. +(3) In the future, Gulfport will have to plug and abandon almost 400 +wellbores. Gulfport's strategy to meet this obligation is to plug at +least twenty wells a year at WCBB, three at Hackberry and to invest in +plugging escrow accounts. The Company continually deposits money in +the West Cote Blanche Bay Escrow Account, which currently has a +balance of approximately $2.3 million dollars. Additionally, Gulfport +has a $200,000 letter of credit dedicated to the plugging operations +at East Hackberry. +All of the oil and gas leases in which Gulfport owns an interest have been +perpetuated by production. The operator may surrender the leases at any time by +notice to the lessors, or by the cessation of production. +East Hackberry Field +(Map Omitted) +Location and Land +The East Hackberry Field is located along the western shore of Lake +Calcasieu in Cameron Parish, Louisiana approximately 80 miles west of Lafayette +5 +and 15 miles inland from the Gulf of Mexico. In February 1994, Gulfport +purchased a 100% working interest (approximately 79% average NRI) in certain +producing oil and gas properties situated in the East Hackberry Field. The +purchase included two separate lease blocks, the Erwin Heirs Block which is +located on land originally developed by Gulf Oil Company (now ChevronTexaco +Corporation), and the adjacent State Lease 50 Block which is located primarily +in the shallow waters of Lake Calcasieu, originally developed by Texaco. The two +lease blocks together contain 3,147 acres. +In September 1994, Gulfport sold an overriding royalty interest equal to a +50% working interest in certain producing oil and gas wells situated in the East +Hackberry Field to Milam Royalty Corporation a subsidiary of J. P. Morgan and +Company. In April 1999, Gulfport purchased the overriding royalty interest back +from the then current owner, Queen Sand Resources, Inc. giving Gulfport a 100% +working interest in the field. +Geology +The Hackberry Field is a major salt intrusive feature, elliptical in shape +as opposed to a classic "dome," divided into East and West field entities by a +saddle. Structurally, Gulfport's East Hackberry acreage is located on the +eastern end of the Hackberry salt ridge. There are over 30 pay zones at this +field. The salt intrusion trapped Oligocene through Lower Miocene rocks in a +series of complex, steeply dipping fault blocks. The Camerina sand series is a +prolific producer with 1-2 MMBL per well of oil potential. Gulfport's wells +currently produce from perforations found between 5,100' and 12,200'. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company (now +ChevronTexaco Corporation) by a gravitational anomaly survey. The massive +shallow salt stock presented an easily recognizable gravity anomaly indicating a +productive field. Initial production began in 1927 and has continued to the +present. The estimated cumulative oil and condensate production through 2002 +was 111 million barrels of oil with casinghead gas production being 60 billion +cubic feet of gas. There have been a total of 170 wells drilled on Gulfport's +portion of the field with 17 having current daily production; three produce +intermittently; 73 wells are shut-in and 4 wells have been converted to salt +water disposal wells. The remaining 73 wells have been plugged and abandoned. +During 2001, daily net production averaged 305 barrels of oil with a limited +amount of net gas production. +Facilities +Gulfport has land-based production and processing facilities located at +the East Hackberry Field. The facility is comprised of two dehydrating units and +four disposal pumps. Gulfport also has a field office that serves both the East +and West Hackberry fields. Due to the high cost of gas, Gulfport converted the +Erwin Heirs Block from gas lift to other lifting methods in 2000 and returned +the rental compressors. Gulfport reactivated three pumping units from inventory +and purchased an additional surface unit and two electric submersible pumps. +2001 Activity +Gulfport began a program to periodically test shut-in wells on the State +Lease 50 portion of the East Hackberry Field. Additionally, Gulfport +reactivated a satellite tank battery at the State Lease 50 portion of East +Hackberry. The Company also conducted several remedial operations that included +6 +repairing holes in tubing and casing, replaced parted tubing and cleaned out +salt water disposal wells. +West Hackberry Field +Location and Land +The West Hackberry Field is located on land and is five miles West of Lake +Calcasieu in Cameron Parish, Louisiana approximately 85 miles west of Lafayette +and 15 miles inland from the Gulf of Mexico. In November 1992, Gulfport +purchased a 100% working interest (approximately 80% average NRI, subsequently +increased to approximately 87.5% NRI) in 592 acres within the West Hackberry +Field. +Gulfport's leases at West Hackberry are located within two miles of one of +the United States' Department of Energy's Strategic Petroleum Reserves. The +West Hackberry storage facility occupies 525 acres and has capacity to store 222 +million barrels of oil in underground salt caverns. +Geology +Structurally, Gulfport's West Hackberry acreage is located on the western +end of the Hackberry salt ridge. (See graphic above.) There are over 30 pay +zones at this field. West Hackberry consists of a series of fault-bounded traps +in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt +Ridge. Recoveries from these thick, porous, water-drive reservoirs have +resulted in per well cumulatives of almost 700 BOE. +Area History and Production +The first discovery well at West Hackberry was drilled in 1938 and was +developed by Superior Oil Company (now Exxon-Mobil Corporation) between 1938 and +1988. The estimated cumulative oil and condensate production through 2001 was +170 million barrels of oil with casinghead gas production of 120 billion cubic +feet of gas. There have been 36 wells drilled to date on Gulfport's portion of +West Hackberry and currently 2 are producing, 25 are shut-in and 1 well has been +converted to a saltwater disposal well. The remaining 8 wells have been plugged +and abandoned. During 2001, daily net production averaged 40 barrels of oil and +a limited amount of gas. +Facilities +Gulfport has land-based production and processing facilities located at +the West Hackberry field. Gulfport has two dehydrating units and one disposal +pump. During 2000, due to the high cost of gas, Gulfport converted the West +Hackberry field from gas lift to other lifting methods. The Company reactivated +two pumping units from inventory and sold a company owned compressor. Gulfport +maintains a field office that serves both the East and West Hackberry fields. +2001 Activity +Gulfport conducted several remedial operations that included repairing +holes in tubing and casing and replacing parted tubing. +West Cote Blanche Bay Field +(Map Omitted) (Type Log Omitted) +7 +Location and Land +The West Cote Blanche Bay (WCBB) Field lies approximately five miles off +the coast of Louisiana primarily in St. Mary Parish in a shallow bay, with water +depths averaging eight to ten feet. Gulfport originally acquired from Texaco a +6.25% working interest in all zones in the WCBB field in July 1988. In April +1995, Gulfport completed the purchase of an additional 43.75% working interest +in the WCBB field from an affiliate of Benton Oil and Gas Company and two +affiliates of Tenneco, Inc. as to those rights lying above the base of the Rob +"C" marker, located at approximately 10,500'. The sellers retained their +interests in all depths below the base of the Rob "C" marker. In July, 1997 +Gulfport acquired the remaining 50% working interest in the WCBB field in depths +above the Rob "C" marker from Texaco and became the operator of the shallow +rights in the field. In 1999 Gulfport exercised a preferential right to +purchase an additional 1.00% working interest in the rights below the Rob "C" +marker. Currently Gulfport owns a 100% working interest (78.66% NRI) and is +the operator in the depths above the Rob "C" marker and owns a 7.45% +non-operated working interest (5.84% NRI) in depths below the Rob "C" marker. +Texaco is the operator below the base of the Rob "C" marker. Gulfport's +leasehold at WCBB covers a portion of Louisiana State Lease 340 and contains +4,590 acres. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. +The field is characterized by a piercement salt dome, which created traps from +the Pleistocene through the Miocene. The relative movements affected deposition +and created a complex system of fault traps. The compensating fault sets +generally trend NW-SE and are intersected by sets having a major radial +component. Later-stage movement caused extension over the dome and a large +graben system was formed. +There are over 100 distinct sandstone reservoirs recognized throughout +most of the field and nearly 200 major and minor discrete intervals have been +tested. Within the over 800 wellbores that have been drilled to date in the +field, over 4,000 potential zones have been penetrated. These sands are highly +porous and permeable reservoirs primarily with a strong water drive. +Area History and Production +Texaco drilled the discovery well in 1940 based on a seismic and +gravitational anomaly. WCBB was subsequently developed on an even 160-acre +pattern for much of the remainder of the decade. Developmental drilling +continued and reached its peek in the 1970's when over 300 of the over 800 total +wells were drilled in the field. Of the over 800 wells drilled, only 80 were dry +holes and many of these were capable of hydrocarbon production. As a result, the +field has an historic success rate of over 90% for all wells drilled. The +cumulative gross production for the average producer in the field was 237 MBO, +with over 100 of those wells (14% of total wells) producing in excess of 500 +MBO. As of January 1, 2002, field cumulative gross production was 191 MMBO and +232.5 BCF of gas. +There have been 871 wells drilled in WCBB. Of these, 48 are currently +producing, 303 are shut-in and five have been converted to salt water disposal +wells. The balance of the wells (or 515) have been plugged and abandoned. +During 2001, Gulfport's net current daily production averaged 1,280 barrels of +oil, 399 MCF of gas and 11,881 barrels of water at WCBB. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 +shot points per mile that processed out 100 fold. In 1993, an undershoot survey +around the crest and production facilities was added. Gulfport owns the rights +8 +to the seismic data. In December of 1999 Gulfport completed the reprocessing +of the seismic data and its technical staff developed prospects from the data. +The reprocessed data will enable Gulfport to identify prospects in areas of the +field that would otherwise remain obscure. +Facilities +Gulfport owns and operates a production facility at WCBB. The platform +for the production facility stretches over a mile and is equipped with a 30 MMCF +capacity dehydrating system and three 225 horsepower triplex saltwater disposal +pumps. The Company has an ongoing program to modernize and service the +production facilities at WCBB. During 2001, Gulfport installed two new gas +compressors totaling 3,000 horsepower into full time service at the field +replacing three outdated inefficient compressors. The new compressors increased +efficiency and, together with a new header valve the Company installed at one of +the tank batteries, reduced gas usage in the field by 50%. Other work performed +on the facility during 2001 included repairing or replacing flow lines and gas +lift lines. Gulfport also back flowed and cleaned sand from the five saltwater +disposal wells at West Cote Blanche Bay, which allows the wells to handle a +higher volume of water. The Company generates cash flow by handling other +companies' gas and oil and disposing of their saltwater through the facility for +a fee. In 2001, Gulfport earned an average of $33,524 a month from third party +facility charges. +2001 Activity +During April 2001, Gulfport finished the seven well drilling program it +had commenced in January of 2001. The Company successfully drilled, completed +and is currently producing six intermediate depth wells, with total depths +averaging approximately 9,000' and one shallow well, with a total depth of +2,500'. These wells found significant oil and gas deposits in multiple targets +ranging from relatively low risk proven undeveloped objectives to higher +potential exploratory targets. Gulfport feels that by taking most future wells +to a depth of 9,000' there will be an increased chance of converting reserves +currently classified as possible and probable to proved. +Gulfport continued to meet its plugging obligation and plugged 26 wells at +WCBB during 2001 at an average cost of $18,400 per well. The Company has plugged +90 wells at WCBB since it began its plugging program in 1997. +2002 Field Activity +West Cote Blanche Bay +In 2002, Gulfport continues to use the reprocessed 3-D seismic data to +identify and confirm intermediate and shallow prospects at WCBB. The Company +plans to begin a ten well drilling program in the second quarter of 2002. The +ten well program will consist of eight developmental intermediate depth wells, +one developmental shallow horizontal well and one exploratory shallow well. The +Company anticipates that these wells will access significant oil and gas +deposits with most of the wells having multiple targets ranging from relatively +low risk proven undeveloped objectives to higher potential exploratory targets. +Gulfport also anticipates several recompletions and workovers and will continue +to fulfill its plugging obligations during 2002. +East & West Hackberry +Gulfport will continue testing shut-in wells and putting them on permanent +or intermittent production as results warrant. The Company also plans several +recompletion projects for the Erwin and State Lease 50 portion of East +9 +Hackberry. Gulfport is in the process of generating projects in the West +Hackberry field. +Texaco Operated Well +In June of 1999, Gulfport executed a sublease in favor of Texaco of an +approximate 72 acre block below the base of the 8 Sand, located at approximately +9,060 feet, at WCBB and reserved a 25% back-in working interest after the +proceeds of the well totaled $1,000,000. The well paid out in December 1999. +Overriding Royalty Interests +Gulfport also owns overriding royalty interests in an additional 14 +producing oil and gas wells lying in four fields. +When Gulfport sold its interest in the Bayou Penchant Field to Castex +Energy 1996 Limited Partnership effective April 1, 1998, Gulfport retained a 10% +overriding royalty interest in this field. The Bayou Penchant field is located +in Terrebonne Parish, Louisiana and the 2001 average daily gross production from +five producing wells was 1,250 gross MCF of gas. +Gulfport also owns a 2.5% overriding royalty interest in three producing +wells at the Napoleonville Field retained when Gulfport sold its interest to +Plymouth Operating Company in 1998. The Napoleonville field is located in +Assumption Parish, Louisiana and averaged 150 gross barrels of oil per day in +2001. +Additionally, Gulfport owns a net profits interest in one producing well +and all the leasehold rights in the South Atchafalaya Bay Field located in St. +Mary Parish, Louisiana. This well was placed on production in late 1999. This +interest provided over $21,000 in net revenue to Gulfport in 2001. +The land occupied by a warehouse owned by Gulfport in Lafayette, LA covers +approximately one acre. The mineral rights underlying the building were +included in a unit drilled by Newfield Exploration Company. In April 2000, +effective June 1999, Gulfport backed into a working interest in the Gladys +Garber #1 well. During 2001, the well generated over $62,000 net to Gulfport's +interest. +Fee Minerals and Surface Interest +Gulfport owns 230 net acres of fee minerals and surface interest adjacent +to its West Hackberry Field in Cameron Parish, Louisiana. This property +currently contains six producing wells. +Castex Energy 1996 Limited Partnership +Castex Back-In +Gulfport sold its interest in the Bayou Penchant, Bayou Pigeon, Deer Island +and Golden Meadow fields to Castex Energy 1996 Limited Partnership effective +April 1, 1998 subject to a 25% reversionary interest in the partnership after +Castex had received 100% of the initial investment. Castex informed Gulfport +that the investment had paid out effective September 1, 2001. In lieu of a 25% +interest in the partnership, Gulfport elected to take a proportionately reduced +25% working interest in the properties. The Company now owns the following +working interest in the subject fields: +10 +Field Parish Working Interest +Bayou Penchant Terrebonne 3.125% +Bayou Pigeon Iberia 6.250% +Deer Island Terrebonne 6.250% +Golden Meadow Lafourche 3.125% +In addition to the producing wells and associated leasehold rights, +Gulfport has prepaid the drilling and completion costs of three new wells. +Other Interests +Litigation Trust +Gulfport owns a 12% interest in the Trust (the "Litigation Trust") that was +established in WRT's bankruptcy to pursue litigation connected with WRT. +The Litigation Trust filed approximately 400 preference actions and +several substantive actions alleging fraud, malpractice and other wrongdoings. +At this time, Gulfport cannot estimate what the potential future recovery from +the litigation will be. +Oil and Gas Marketing +Gulfport sells its oil and gas at the wellhead and does not refine +petroleum products. Other than normal production facilities, Gulfport does not +own an interest in any bulk storage facilities or pipelines. As is customary in +the industry, Gulfport sells its production in any one area to relatively few +purchasers, including transmission companies that have pipelines near Gulfport's +producing wells. Gas purchase contracts are generally on a short-term "spot +market" basis and usually contain provisions by which the prices and delivery +quantities for future deliveries will be determined. The majority of Gulfport's +crude oil production in 2001 was sold on contracts based on the average closing +price on NYMEX for each trading day during the month of delivery. +During 2001, oil sales to Gulfmark Energy Inc. accounted for 86% of +Gulfport's oil sales. Gulfport had no other purchasers that accounted for +greater than 10% of it's oil sales. Gulfport had no gas purchasers that +accounted for more than 10% of it's total sales. +Competition and Markets +Availability of Markets. The availability of a ready market for any oil +and/or gas produced by Gulfport depends on numerous factors beyond the control +of management, including but not limited to, the extent of domestic production +and imports of oil, the proximity and capacity of gas pipelines, the +availability of skilled labor, materials and equipment, the effect of state and +federal regulation of oil and gas production and federal regulation of gas sold +in interstate commerce. Oil and gas produced by Gulfport in Louisiana is sold to +various purchasers who service the areas where Gulfport's wells are located. +Gulfport's wells are not subject to any agreements that would prevent Gulfport +from either selling its production on the spot market or committing such gas to +a long-term contract; however, there can be no assurance that Gulfport will +continue to have ready access to suitable markets for its future oil and gas +production. +Impact of Energy Price Changes. Oil and gas prices can be extremely +volatile and are subject to substantial seasonal, political and other +fluctuations. The prices at which oil and gas produced by Gulfport may be sold +11 +is uncertain and it is possible that under some market conditions the production +and sale of oil and gas from some or all of its properties may not be +economical. The availability of a ready market for oil and gas and the prices +obtained for such oil and gas, depend upon numerous factors beyond the control +of Gulfport, including competition from other oil and gas suppliers and national +and international economic and political developments. Because of all of the +factors influencing the price of oil and gas, it is impossible to accurately +predict future prices. +Environmental Regulation +Operations of Gulfport are subject to numerous federal, state and local +laws and regulations governing environmental protection. Over the last several +years, state and federal environmental laws and regulations have become more +stringent and may continue to become more stringent in the future. These laws +and regulations may affect Gulfport's operations and costs as a result of their +affect on oil and gas development, exploration, and production operations. It is +not anticipated that Gulfport will be required in the near future to expend +amounts that are material in relation to its total capital expenditures program +by reason of environmental laws and regulations, but inasmuch as such laws and +regulations are frequently changed, Gulfport is unable to predict the ultimate +cost of compliance. +Operational Hazards and Insurance +Gulfport's operations are subject to all of the risks normally incident to +the production of oil and gas, including blowouts, cratering, pipe failure, +casing collapse, oil spills and fires, each of which could result in severe +damage to or destruction of oil and gas wells, production facilities or other +property, or injury to persons. The energy business is also subject to +environmental hazards, such as oil spills, gas leaks, and ruptures and discharge +of toxic substances or gases that could expose Gulfport to substantial liability +due to pollution and other environmental damage. Although Gulfport maintains +insurance coverage considered to be customary in the industry for a company its +size, it is not fully insured against certain of these risks, either because +such insurance is not available or because of high premium costs. The occurrence +of a significant event that is not fully insured against could have a material +adverse effect on Gulfport's financial position. +Headquarters and Other Facilities +Gulfport leases office space in Oklahoma City, Oklahoma under a lease +covering approximately 7,000 square feet. The monthly rent is approximately +$13,000. +In 1996, Gulfport purchased a building in Lafayette, Louisiana to be used +as Gulfport's Louisiana headquarters. The 16 year-old building contains 12,480 +total square feet with 8,180 square feet of finished office area and 6,300 +square feet of clear span warehouse area. The mortgage balance was +approximately $163,000 as of January 1, 2002 with an estimated fair market value +of $350,000. This building allows Gulfport to provide office space for +Louisiana personnel, have access to meeting space close to the fields and to +maintain a corporate presence in Louisiana. +Employees +At December 31, 2001 Gulfport had 13 employees. A Louisiana well +servicing company serves as contract operator of the fields and provides all +necessary field personnel. +12 \ No newline at end of file diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/item13.txt b/raw/filings/0000874499/2001/0001060830-02-000041/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8baa50ba0cdd53a81be03eed69b5d03623db9879 --- /dev/null +++ b/raw/filings/0000874499/2001/0001060830-02-000041/item13.txt @@ -0,0 +1,8 @@ +Item 13. Certain Relationships and Related Transactions +In March 2001, a company that shares common ownership with Gulfport +acquired a majority of the oil and natural gas properties of a mid-continent +exploration and production company. Subsequent to the acquisition, Gulfport +began providing administrative services to effectively manage the day-to-day +operations of this acquisition and in turn receives an administrative service +fee for such services. +26 \ No newline at end of file diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/item9a.txt b/raw/filings/0000874499/2001/0001060830-02-000041/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/rp_note.txt b/raw/filings/0000874499/2001/0001060830-02-000041/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..190810cdaca21a7cd7c807b7d1a37d7c800964f0 --- /dev/null +++ b/raw/filings/0000874499/2001/0001060830-02-000041/rp_note.txt @@ -0,0 +1,56 @@ +13. RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business +activities with a substantial number of its shareholders. +DLB Oil & Gas, Inc. ("DLB") and Wexford Management LLC ("Wexford") were, +along with Gulfport, co-proponents in a 1997 plan of reorganization. During +April of 1998, DLB distributed all of its shares in the Company to its +shareholders prior to DLB's acquisition by Chesapeake Energy Corporation. As a +result of this distribution, Charles Davidson, Mike Liddell and Mark Liddell +collectively received 37.5% of the Company's stock. As of December 31, 2001, +Wexford and its affiliates owned approximately 17.7% of Gulfport's issued +outstanding stock. Charles Davidson, Mike Liddell and the Estate of Mark Liddell +own collectively 55.8% of the Company's outstanding stock as of December 31, +2001. +Administrative Service Agreement +Pursuant to the terms and conditions of an Administrative Services +Agreement, DLB agreed to make available to the Company personnel, services, +facilities, supplies, and equipment as needed, including executive and +managerial, accounting, auditing and tax, engineering, geological and +geophysical, legal, land and administrative and clerical services. The initial +term was one year beginning on the date of the Administrative Services +Agreement. The Administrative Services Agreement was to continue for successive +one-year periods unless terminated by either party. On April 28, 1998, in +connection with the acquisition of DLB, Inc. by Chesapeake Energy Corporation, +the obligations of DLB under the Administrative Services Agreement were assigned +to DLB Equities, L.L.C. +Gulfport paid fees under this agreement totaling $21,000 in 1999 and +believes that such fees are comparable to those that would have been charged by +an independent third party. Effective June of 1999, this Administrative Service +Agreement was terminated. +Stockholder Credit Facility +On August 18, 1998, Gulfport entered into a $3,000,000 revolving credit +facility with Liddell Investments, L.L.C., Liddell Holdings, L.L.C., CD +Holdings, L.L.C. and Wexford Entities (collectively "Affiliated Stockholders"). +Borrowing under the Stockholder Credit Facility was due on August 17, 1999 and +bore interest at LIBOR plus 3%. Pursuant to the facility agreement, Gulfport +paid the eligible Affiliated Stockholders an aggregate commitment fee equal to +$60,000. Gulfport repaid $2,000,000 of principal under the Amended ING Credit +Agreement with borrowings under the Stockholder Credit Facility. The remaining +$1,000,000 was used for working capital and general corporate purposes. The +Affiliated Stockholders paid the subscription price for 1,200,000 shares +pursuant to their Basic Subscription Privilege in the Rights Offering through +F-16 +GULFPORT ENERGY CORPORATION +NOTES TO FINANCIAL STATEMENTS +DECEMBER 31, 2001, 2000 AND 1999 +CONTINUED +the forgiveness of the amount owed to them under this stockholder credit +facility. +On August 5, 1999, Gulfport entered into a $3,255,000 revolving credit +facility with the "Affiliated Stockholders". Borrowing under this agreement was +due on August 1, 2000, and bore interest at LIBOR plus 3%. Pursuant to the terms +of the agreement, Gulfport paid aggregate commitment fees equal to $65,000 or 2% +of the related borrowings in stock. This debt was extinguished through the +issuance of 4,040,011 shares of common stock to the Affiliated Stockholders in +the Regulation D Offering in August 1999, and through the payment of additional +funds totaling $208,000. \ No newline at end of file diff --git a/raw/filings/0000874499/2001/0001060830-02-000041/rpt_disclosure.txt b/raw/filings/0000874499/2001/0001060830-02-000041/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..8baa50ba0cdd53a81be03eed69b5d03623db9879 --- /dev/null +++ b/raw/filings/0000874499/2001/0001060830-02-000041/rpt_disclosure.txt @@ -0,0 +1,8 @@ +Item 13. Certain Relationships and Related Transactions +In March 2001, a company that shares common ownership with Gulfport +acquired a majority of the oil and natural gas properties of a mid-continent +exploration and production company. Subsequent to the acquisition, Gulfport +began providing administrative services to effectively manage the day-to-day +operations of this acquisition and in turn receives an administrative service +fee for such services. +26 \ No newline at end of file diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/filing.txt b/raw/filings/0000874499/2007/0001193125-08-058618/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..afde760ac9f26a6abd1754a1617b2ab85abf3c4d --- /dev/null +++ b/raw/filings/0000874499/2007/0001193125-08-058618/filing.txt @@ -0,0 +1,5273 @@ +10-K +1 +d10k.htm +FORM 10-K +Form 10-K +Table of Contents +Index to Financial Statements +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +x +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES +EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2007 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number: 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant as Specified in Its +Charter) +Delaware +73-1521290 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip code) +(405) 848-8807 +(Registrant’s Telephone Number, Including Area Code) +Securities registered pursuant to +Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the +Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of +the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x +Indicate by check mark whether the +registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and +(2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained +herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a +non-accelerated filer, or a smaller reporting company. See definitions of “accelerated filer and large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): +Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). +Yes ¨ No x +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2007, based on the closing price of the common stock on the NASDAQ Global +Select Market on June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter ($19.98 per share) was $405,264,130. +As of March 3, 2008, 42,550,031 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy Corporation’s Proxy Statement for the 2008 Annual +Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. +Table of Contents +Index to Financial Statements +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +DESCRIPTION OF BUSINESS +2 +ITEM 1A. +RISK FACTORS +13 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +23 +ITEM 2. +PROPERTIES +23 +ITEM 3. +LEGAL PROCEEDINGS +27 +ITEM 4. +SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +29 +PART II +30 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +30 +ITEM 6. +SELECTED FINANCIAL DATA +31 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +33 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +46 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +47 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +47 +ITEM 9A. +CONTROLS AND PROCEDURES +48 +ITEM 9B. +OTHER INFORMATION +49 +PART III +50 +ITEM 10. +DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +50 +ITEM 11. +EXECUTIVE COMPENSATION +50 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +50 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +50 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +50 +PART IV +51 +ITEM 15. +EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES [UPDATE] +51 +Signatures +S-1 +Index to Consolidated Financial Statements +F-1 +Exhibit Index +E-1 +i +Table of Contents +Index to Financial Statements +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking +statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation +Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any +future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” +“would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended +to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including +such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, +goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made +by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which +are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a +number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K +are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in +the forward-looking statements due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All +forward-looking statements speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These +cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +Index to Financial Statements +PART I +ITEM 1. DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf +Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. We have also recently acquired strategic assets in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our +interest in Grizzly Oil Sands ULC and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2007, at our WCBB field, we drilled 26 wells and recompleted 60 existing wells for a total cost of $57.9 million as of +December 31, 2007. Of our 26 new wells drilled at WCBB in 2007, 22 were completed as producing wells and four were non-productive. As of March 1, 2008, we had drilled two new wells at WCBB, both of which are producing and had recompleted +14 wells during 2008. During 2008, we intend to drill a total of eight to ten wells, recomplete 44 wells and conduct other activities at our WCBB field for an estimated aggregate cost of $21 to $23 million. In December 2007, production at WCBB was +105,922 net barrels of oil equivalent, or BOE, or an average of 3,417 BOE per day, 93% of which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil +and 5% of which was from natural gas. +In 2007, at our East Hackberry field, we drilled nine wells in Lake Calcasieu and three wells on +land and recompleted two existing wells for a total cost of $62.4 million as of December 31, 2007. Of the 12 wells drilled during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East +Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land wells, recomplete one additional well and conduct other activities in +2008 for an aggregate estimated cost of $17 to $19 million. In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil and 30% of which was from natural gas. In February 2008, our +average net daily production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas. +On +December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin for approximately $85 million, with an effective date of November 1, 2007. Through this transaction, Gulfport acquired 4,100 net acres +with production at the time of acquisition of approximately 800 net BOE a day from 32 gross wells, predominately from the Wolfcamp formation. Existing production is approximately 64% oil, 23% natural gas liquids and 13% natural gas. At +December 31, 2007, Pinnacle Energy Services LLC, an independent petroleum engineering firm, estimated that proved reserves net to our interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved +developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally +characterized as long-lived, with predictable production profiles. We expect that approximately 17 to 22 net wells will be drilled on this acreage in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average +gross completed well cost of $1.7 million. +During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings +Inc., purchased a 24.9999% interest in Grizzly Oils Sands ULC, or Grizzly, a Canadian unlimited liability company. The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford, an affiliate of ours. During +2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. As of March 1, 2008, Grizzly had approximately 511,000 acres under lease. Grizzly +drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks. Future plans currently include acquiring additional leases, drilling approximately 55 to 60 additional core holes and a seismic +program during the 2007/2008 winter drilling +2 +Table of Contents +Index to Financial Statements +season and initial planning for the construction of a 10,000 barrel per day steam assisted gravity drainage facility, or SAGD, that could lead to initial +production in 2011. Permitting for this initial SAGD facility is expected to commence later in 2008. +During 2005, we purchased a 23.5% +ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an +international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +As of December 31, 2007, we had 29.2 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future +net revenues, discounted at 10%, or PV-10, of approximately $821million and associated standardized measure of discounted future net cash flows of approximately $668.3 million. See Item 2. “Properties—Proved Oil and Natural Gas +Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Principal Oil and Natural Gas Properties +The following table presents certain information as of +December 31, 2007 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast and in the Permian Basin in West Texas. +Proved Reserves +Field +NRI/WI (1) +Producing +Wells (2) +Non-Producing +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay (4) +78.665/100 +111 +111 +166 +166 +5,668 +5,668 +15,891 +15,135 +17,783 +E. Hackberry (5) +79.424/100 +12 +12 +82 +82 +3,265 +3,265 +2,776 +4,119 +4,582 +W. Hackberry +87.5/100 +3 +3 +24 +24 +592 +592 +— +158 +158 +Permian +37.5/50 +32 +16 +— +— +2,560 +1,280 +5,587 +5,699 +6,630 +Overrides/Royalty Non-operated +Various +18 +0.8 +16 +0.7 +4,956 +586 +5 +4 +5 +Total +176 +142.8 +288 +272.7 +17,041 +11,391 +24,259 +25,115 +29,158 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes 30 gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 87% of our acreage is developed acreage and has been perpetuated by production. We have 1,100 and +2,820 net undeveloped acres in the East Hackberry field and the Permian Basin, respectively. +(4) +We have a 100% working interest (78.665% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a +40.40% non-operated working interest (29.95% NRI). +(5) +Does not include an additional 3,233 acres under an option we exercised which will increase our acreage position significantly to approximately 7,598 acres. State approval was +obtained on February 27, 2008, and we are working with the state to finalize the leases. +3 +Table of Contents +Index to Financial Statements +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water +depths averaging eight to ten feet. We own a 100% working interest (78.665% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated +working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this +field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells +were drilled in the field. Of the 900 wells drilled as of December 31, 2007, 809 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in +1997 through December 31, 2007, we drilled 120 new wells, 14 of which were non-productive, for an 88% success rate. As of December 31, 2007, estimated field cumulative gross production was 187.4 MMBOE and 235.5 billion cubic feet, or Bcf, +of gas. Of the 900 wells drilled in WCBB as of December 31, 2007, 81 were producing, 166 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 618 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an +undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The +reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome +structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The +compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) +was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor +discrete intervals have been tested. Within the 900 wellbores that had been drilled in the field as of December 31, 2007, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a +strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB +are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, +and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of +crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the +mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an +4 +Table of Contents +Index to Financial Statements +effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position +within a particular zone. Our inventory of prospects includes 111 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019. +Facilities +We own and operate a production facility at WCBB that includes four production tank +batteries, six natural gas compressors, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2007, we drilled 26 wells and recompleted 60 existing wells at WCBB. Of these 26 new wells, 22 were completed as producers, and four were +non-productive. As of March 1, 2008, we had drilled two new wells, both of which are producing, and had recompleted 14 wells during 2008. Of the 22 wells completed in 2007, ten were considered deep wells. The 22 productive wells, with total +depths ranging from 6,107 to 10,464 feet, have approximately 2,716 feet of aggregate apparent net pay. The other four wells were non-productive, including one exploratory well that was drilled to satisfy our drilling commitment with the State of +Louisiana to hold the non-productive portions of WCBB. We anticipate drilling a total of eight to ten wells and recompleting 44 wells at WCBB during 2008. +Production Status +In December 2007, production at WCBB was 105,922 net BOE, or an average of 3,417 BOE per day, 93% of +which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil and 5% of which was from natural gas. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. +We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 4,365 acres, including the Erwin Heirs Block, +which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. In addition, we exercised our option to acquire an additional 3,233 acres at the Hackberry field. The option will +increase our acreage position significantly to approximately 7,598 acres. State approval was obtained on February 27, 2008, and we are working with the state to finalize the leases. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now +Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated +cumulative oil and condensate production through 2007 was over 263,000 barrels of oil and 330 Bcf of casinghead gas production. There have been a total of 182 wells drilled on our portion of the field. As of December 31, 2007, 12 wells had +daily production, 82 were shut-in and two had been converted to salt water disposal wells. The remaining 86 wells had been plugged and abandoned. +5 +Table of Contents +Index to Financial Statements +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern +end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps +for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East +Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 +barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry. Given that drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken +without the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our probability of drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2007 at East +Hackberry, we drilled nine wells in Lake Calcasieu and three wells on land and recompleted two existing wells. Of the 12 wells drilling during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East +Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land wells and recomplete one additional well at East Hackberry during +2008. Drilling activity in this field during 2008 will target measured depths of up to 13,000 feet using directional drilling techniques. +Production +Status +In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil +and 30% of which was from natural gas. In February 2008, our average net daily production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of +Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States +Department of Energy’s Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between +1938 and 1988. The estimated cumulative oil and condensate production through 2007 was 227 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and +one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. +6 +Table of Contents +Index to Financial Statements +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and +Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In December 2007, net production at West Hackberry was 641 BOE, or 21 BOE per day. +In February 2008, our average net daily production at West Hackberry was 21 BOE. +Facilities +We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West +Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on +December 20, 2007, effective date as of November 1, 2007, from ExL Petroleum, LP and certain other sellers. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major +producing basins in the United States. The terrain in the Permian Bain is semi-arid mesquite-mixed grassland steppe. +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a +long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was +not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 +feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry decided to drill completely +through the Wolfcamp section as Devonian wells. Henry mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry’s Wolfcamp team formed +their own private company, ExL Petroleum, and began replicating Henry’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled +us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. Currently, we hold interests in thirty-two gross producing wells. +Geology +The Wolfcamp/Spraberry play, which we refer +to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 +feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +7 +Table of Contents +Index to Financial Statements +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the +Spraberry section, consisting of approximately 64% oil, 23% natural gas liquids, and 13% natural gas. Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2007, proved reserves net to our +interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre +units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. Wells to be drilled will be approximately 10,200 feet at an estimated average +gross completed well cost of $1.7 million. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is expected to average gross 146,000 BOE per well with an average net revenue interest in the field of +approximately 75%. We have a 50% working interest and approximately 37.5% net revenue interest in the field. +Production Status +At the date of acquisition, there was production of approximately 800 net BOE a day from 32 gross, producing wells. During February 2008, average net +production to Gulfport was 531 BOE a day. +Facilities +There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +We have identified 178 +gross future development drilling locations. We expect approximately 17 to 22 net wells to be drilled in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average gross completed well cost of $1.7 million. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +2 +5 +Bayou Pigeon +Iberia +6.250 +% +0 +% +5 +5 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +6 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +1 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, +or Tatex, at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During the year ended December 31, 2007, we paid $88,000 in cash calls, +bringing our total investment in Tatex (including previous investments) to $3,553,000. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were +achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. Current net production is approximately 100 Mcf per day. Hess Corporation operates the field +with a +8 +Table of Contents +Index to Financial Statements +35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through +Tatex as a member of APICO) in the Phu Horm field is 0.7%. Proved reserves from the Phu Horm field, net to our interest, are 3.5 BCF of gas and 10,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and +Tatex’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +Williston Basin . During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2005 and 2006, Bakken acquired leases on +undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana. At December 31, 2007, our net investment in Bakken was $2,468,000. We are currently participating in the drilling of nine wells and have interests in +eight producing wells with an average working interest of 1.55%. +Marquiss Field . In February 2005, but effective as of +December 1, 2004, we acquired our interest in the Marquiss field, an approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming, for $375,000. As of December 31, 2006, the Marquiss field included a total of 162 wells, +all of which were shut-in as a result of the economic status of the field as a result of a decline in natural gas prices for this field. The wells (when on line) produced from multiple horizons with additional upside potential from deeper coals and +operational efficiencies. Our interest in the Marquiss field was sold in February 2007 for $500,000. +Grizzly Oil Sands . During the +third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired +leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $27,801,000 at +December 31, 2007. Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks using up to four different rigs. Future plans currently include acquiring additional leases, +drilling approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling season and initial planning for the construction of a 10,000 barrel per day SAGD facility that could lead to initial production in 2011. +Gross capital expenditures for such a production facility are currently estimated to be approximately $325 million. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of +these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned +to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government +regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of +our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of +oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to +Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production is being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade month +average P+ value, plus or minus the Platt’s WII/LLS differential less $3.70 per barrel for transportation. During 2007, we sold 99% of our oil production to Shell and 69% of our natural gas production to Chevron and 23% of our natural gas +production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96% +9 +Table of Contents +Index to Financial Statements +of our natural gas production to Chevron. During 2005, we sold 99% of our oil production to Shell and 88% of our natural gas production to Chevron. There can +be no assurance, however, that we will continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under +some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future +prices. +To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales contracts for the sale of +3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, we entered into forward sales contracts for the +sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell 3,500 barrels of production per day for the months of January +through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel +before transportation costs. For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell +3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,000 +barrels of production per day in each such period at weighted average daily prices of $82.20 per barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of our estimated production for January +through December 2008. For the period of January through December 2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before transportation costs. Such arrangements may +expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These contracts require physical delivery of production quantities and are exempted from the provisions +of SFAS 133 as normal sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry +is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, +affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast +and West Texas. These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations +governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas +exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous +governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations to implement and enforce such laws, which often require difficult +10 +Table of Contents +Index to Financial Statements +and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to +comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and +production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or +former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The strict liability nature of such laws and regulations could impose liability upon us regardless +of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations +and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and we have not experienced any material adverse +effect from compliance with these environmental requirements; this trend, however, may not continue in the future. +Waste Handling . +The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the +generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more +stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that +are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes +or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous +wastes.” +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We +believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our +operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural +gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Comprehensive Environmental +Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or +legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner +or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several +liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners +and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials, that, if released, would be subject to +CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous +substances” have been deposited. +11 +Table of Contents +Index to Financial Statements +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the +Clean Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state +waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These proscriptions also prohibit certain activity in wetlands +unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be +associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all permits required under the Clean Water Act. +Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. +Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The +EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our +facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state +regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial +compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas +projects. +Operational Hazards and Insurance +Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or +destruction of oil and natural gas wells, production facilities or other property, or injury to persons. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or +gases that could expose us to substantial liability due to pollution and other environmental damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. +The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. +Headquarters +and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate +headquarters. We lease a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately +6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for +its use. +Employees +At +December 31, 2007, we had 70 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the +estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2007 and 2006, expenses reimbursed +to us under these arrangements were +12 +Table of Contents +Index to Financial Statements +$11,153,000 and $12,738,000, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company +provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. +Available Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished +pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, +or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be +considered part of this report or any other filing that we make with the SEC. +ITEM 1A. RISK FACTORS +Risks Related to Our Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon +the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are +beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +• +weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +political instability or armed conflict in oil and natural gas producing regions; and +• +the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate posted price for crude oil has ranged from +a low of $30.83 per barrel, or bbl, in January 2004 to a high of $102.20 per bbl on March 6, 2008. The Henry Hub spot market price of natural gas has ranged from a low of $4.20 per million British thermal +13 +Table of Contents +Index to Financial Statements +units, or MMBtu, in October 2006 to a high of $13.93 per MMBtu in October 2005. On December 31, 2007, the West Texas Intermediate posted price for crude +oil was $92.50 per bbl and the Henry Hub spot market price of natural gas was $6.80 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of +expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +Our success depends on finding, developing or acquiring additional reserves. +Our future success +depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful +exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these +activities. We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. To date, we have financed capital +expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the level of oil and natural gas we are able to produce from existing wells; +• +the prices at which oil and natural gas are sold; and +• +our ability to acquire, locate and produce new reserves. +We cannot assure you that we will have sufficient resources to undertake our exploration and development activity, production and acquisition of oil and natural gas reserves, that our exploratory projects or other +replacement activities will result in significant additional reserves or that we will have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas +prices increase significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and +integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense competition +for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to +obtain debt and equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage +additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial +position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +Our Canadian oil sands project is a complex undertaking and may not be completed on schedule or at budgeted cost or at all. +During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by +Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort +14 +Table of Contents +Index to Financial Statements +McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and as of December 31, 2007, our total net +investment in Grizzly was approximately $27.8 million. Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks using up to four different rigs. Future plans currently include +acquiring additional leases, drilling approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling season and initial planning for the construction of a 10,000 barrel per day SAGD facility that could lead +to initial production in 2011. Gross capital expenditures for such a production facility are currently estimated to be approximately $325 million. This is a complex project and financing has not yet been secured. There can be no assurance that this +project can be completed on schedule, at our estimated cost or at all. +Shortage of rigs, equipment, supplies or personnel may restrict our operations. +The oil and natural gas industry is cyclical, and at the present time there is a shortage of drilling rigs, equipment, supplies and +personnel. The costs and delivery times of rigs, equipment and supplies has increased as drilling activities have increased. In addition, demand for, and wage rates of, qualified drilling rig crews have risen with increases in the number of active +rigs in service. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, supplies, personnel, trucking +services, tubulars, fracing and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations. +We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues. +Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Mike +Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists, Stuart Maier and Randy Wilson, could disrupt our operations resulting in a loss of revenues. We +do not have an employment contract with any of our executives, with the exception of Mr. Liddell, and our executives are not restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any +employment agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses +resulting from the death of our key employees. +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual +production. +There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of +production and timing of expenditures, including many factors beyond our control. The reserve information incorporated by reference in this prospectus represents only estimates based on reports prepared by Netherland, Sewell & Associates, +Inc. as of December 31, 2007 with respect to our WCBB field, by Pinnacle Energy Services, LLC with respect to our assets in the Permian Basin in West Texas and by our personnel with respect to our Hackberry fields and our overrides and +non-operated interests. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of +future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed +effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary +considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and +estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary +from estimates, and such variances may be material. +15 +Table of Contents +Index to Financial Statements +The present value of future net revenues from our proved reserves is not necessarily the same as the +current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net revenues from our oil +and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved +reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and +risks associated with us or the oil and natural gas industry in general. +There are numerous uncertainties inherent in estimating quantities of bitumen +reserves and resources and no assurance can be given that indicated level of reserves or recovery of bitumen will be realized. +There +are numerous uncertainties inherent in estimating quantities of bitumen reserves and resources, including many factors beyond our or Grizzly’s control, and no assurance can be given that the indicated level of reserves or recovery of bitumen +will be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates +were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary +considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, +the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. +Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon +analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon +production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and +operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. No assurance can be provided as to the gravity or quality of bitumen to be produced from Grizzly’s lands. +The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. +When these facilities are unavailable, our operations can be interrupted and our revenues reduced. +The marketability of our oil and +natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be +limited or denied due to circumstances beyond our control. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or +produce our oil and natural gas and +16 +Table of Contents +Index to Financial Statements +thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field, which +is our largest field. In October 2006, for example, a natural gas line in this field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could +be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. The increasing demand for transportation barges in the Louisiana Gulf Coast region has adversely +impacted our ability to transport our oil production from the tank batteries in our field to shore for delivery. This has required us to shut in or curtail production from time to time as we have only limited storage capacity in the field. If, in +the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we will be required to again shut in or curtail production from +the field. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from the field, would adversely affect our financial condition and results of operations. +Substantially all of our producing properties are located in Louisiana, making us vulnerable to risks associated with operating in this region. +Our operations are concentrated in Louisiana and our largest field, WCBB, is located approximately five miles off the coast of Louisiana in a shallow bay +with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions such as fog or rain, hurricanes or other natural +disasters, or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We cannot assure you that we will be able to obtain and maintain adequate insurance at rates we consider +reasonable or that any particular types of coverage will be available. +Our identified drilling locations comprise an estimation of part of our future +drilling plans over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified over 200 drilling locations on our Louisiana properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a +number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified +will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely +affect our business. +Operating hazards and uninsured risks may result in substantial losses. +Our operations are subject to all of the hazards and operating risks inherent in drilling for and production of oil and natural gas, including the risk of +fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could result in substantial losses to us +due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. For +example, in October 2006, an accident occurred north of our production facilities in the WCBB field in southern Louisiana involving two contracted vessels that were performing work on our behalf in the field. A tugboat and two barges laden with +construction materials ruptured an underwater natural gas pipeline and a subsequent fire damaged the vessels. Six fatalities resulted from the accident. Several lawsuits relating to this incident have been filed against us, among other parties. +Information with respect to this litigation is incorporated by reference in this Form 10-K. Litigation is inherently uncertain and its outcome cannot be predicted at this time; however, if this litigation is not resolved in a manner that is +favorable to us, our financial condition and results of operations may be negatively impacted. +17 +Table of Contents +Index to Financial Statements +In accordance with customary industry practice, we historically have maintained insurance against some, +but not all, of our business risks. We cannot assure you that our insurance will be adequate to cover any losses or liabilities we may suffer. We also cannot predict the continued availability of insurance, or its availability at premium levels that +justify its purchase. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may also be liable for +environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. +Our operations are +subject to various governmental regulations which require compliance that can be burdensome and expensive. +Our oil and natural gas +operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling +operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the +rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, emission and disposal of oil and gas, by-products thereof and other +substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations relating to protection of human health and the environment. These laws and +regulations have continually imposed increasingly strict requirements for water and air pollution control and waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe +the trend of more expansive and stricter environmental legislation and regulations will continue. +We face extensive competition in our industry. +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these +companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to +take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +We depend upon two customers for the sale of most of our oil and natural gas production. +The availability of a ready market for any oil and natural gas we produce depends on numerous factors beyond the control of our management, including but +not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas +production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, +or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. At December 31, 2007, our WCBB production was being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade +month average P+ value, plus or minus the Platt’s WII/LLS differential less $3.70 per Bbl for transportation. For the year ended December 31, 2007 and the year ended December 31, 2006, we sold approximately 99% and 100%, respectively, +of our oil production to Shell and 69% and 96%, respectively, of our natural gas production to Chevron. During 2007, we sold approximately 23% of our natural gas production to Hilcorp Energy Company. During 2005, we sold 99% of our oil production to +Shell and 88% of our natural gas production to Chevron. There can be no assurance that we will continue to have ready access to suitable markets for our future oil and natural gas production. +18 +Table of Contents +Index to Financial Statements +Our method of accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general +and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at +10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an +equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. +Companies that use +the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the +lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated +year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the +balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book +and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a +significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. +Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. +Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist +geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced +technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. +We have entered into forward sales contracts and may in the future enter into additional contracts for a portion of our production, which may result in our making +cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. +To reduce our exposure to +short-term fluctuations in the price of oil and natural gas, we periodically enter into hedging arrangements. Currently, we have entered into agreements to sell 3,500 barrels of production per day for the months of January through May 2008 at a +weighted average daily price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation +costs. For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell 3,000 barrels of +production per day at a weighted average daily price of $82.44 per barrel before transportation costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,000 barrels of production +per day in each such period at weighted average daily prices of $82.20 per barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of our estimated production for January through December 2008. For +the period of January through December 2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before transportation costs. Such arrangements may expose us to risk of +financial loss in certain circumstances, +19 +Table of Contents +Index to Financial Statements +including instances where production is less than expected or oil prices increase. These contracts require physical delivery of production quantities and are +exempted from the provisions of SFAS 133 as normal sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +A terrorist attack or armed conflict could harm our business. +Terrorist activities, anti-terrorist +efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the +resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related +facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a +result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. +Conservation measures and technological +advances could reduce demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer +demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Management cannot predict the impact of the changing demand for oil and gas services +and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows. +We +are subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If the costs related to such compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely +affected. +Commencing with our fiscal year ended December 31, 2007, we became subject to Section 404 of the Sarbanes-Oxley Act +of 2002, or Section 404, which requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our +independent registered public accounting firm audit our internal control over financial reporting. We are required to evaluate our existing controls against the criteria established in Internal Control-Integrated Framework issued by the Committee of +Sponsoring Organizations of the Treadway Commission, or COSO. The out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of +Section 404 have been significant. If the future time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected. If we fail to fully comply with the requirements of +Section 404 or if we determine that we have a material weakness or significant deficiencies, or if our auditors disagree with our assessment in connection with the presentation of our financial statements, the accuracy and timeliness of the +filing of our periodic reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a +material weakness or significant deficiency in our internal control over financial reporting could result in an increased chance of fraud, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, +each of which could have a material adverse effect on our business, results of operations and financial condition. +Due to inherent limitations, there +can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors and fraud, or in making all material information known in a timely manner to management. +Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and internal controls will +prevent all errors and fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the +20 +Table of Contents +Index to Financial Statements +control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must +be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been +detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some +persons, by collusion of two or more people, or by management override of the control. +The design of any system of controls also is based +in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may become inadequate +because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected +that could have a material adverse effect on our business, results of operations and financial condition. +Risks Related to Our Common Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our +stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: +• +changes in oil and natural gas prices; +• +changes in production levels; +• +changes in governmental regulations and taxes; +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the +future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some future quarters, our +operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +Our officers and directors together with our largest stockholder control a significant percentage of our common stock, and their interests may conflict with those of +our other stockholders. +As of December 31, 2007, our executive officers and directors, in the aggregate, beneficially owned +approximately 4% of our outstanding common stock and Charles E. Davidson, one of our major stockholders, beneficially owned approximately 36% of our outstanding common stock. As a result, these stockholders acting together are able to exercise +significant influence over most matters requiring approval by our stockholders, including the election of directors and the approval of significant corporate transactions. Such a concentration of ownership may have the effect of delaying or +preventing a change in control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices. +21 +Table of Contents +Index to Financial Statements +We can give no assurances as to the market for our common stock. +Since July 14, 2006, our common stock has been listed on The NASDAQ Global Select Market under the symbol “GPOR.” From February 28, +2006 until that date, our common stock was listed on the NASDAQ National Market. Prior to that date, our common stock was traded on the NASD OTC Bulletin Board under the symbol “GPOR.OB.” There is a limited market for our shares. We cannot +assure you that an active trading market will develop, or if it does, that it will be sustained. +We do not currently pay dividends on our common stock +and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and there can be no assurance that we +will achieve sufficient earnings to pay cash dividends on our common stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable +future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock. +A change of control +could limit our use of net operating losses. +As of December 31, 2007, we had a net operating loss, or NOL, carry forward of +approximately $93 million for federal income tax purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In +general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +Future sales of our common stock may depress our stock price. +We and certain of our stockholders have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market, or the perception that +these sales may occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of +March 3, 2008, there were 42,550,031 shares of our common stock issued and outstanding, excluding 77,210 shares of restricted stock awarded under our 2005 Stock Incentive Plan. +We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects. +We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued +from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional +and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain +limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, +participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our +common stock and, therefore, could reduce the value of our common stock. +In addition, specific rights granted to future holders of +preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control +of the company by the current stockholders. +22 +Table of Contents +Index to Financial Statements +The existence of some provisions in our organizational documents could delay or prevent a change in +control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Proved Oil and Natural Gas Reserves +The oil and natural gas reserve information set forth below represents estimates of our proved oil and natural gas reserves as prepared by the independent +engineering firm of Netherland, Sewell & Associates, Inc., or NSAI, with respect to WCBB, our primary field, as prepared by Pinnacle Energy Services, LLC with respect to our assets in the Permian Basin in West Texas and by our personnel +with respect to our other interests. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of +the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. +Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and +assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. See “Risk Factors” contained elsewhere in this Form 10-K. We have not filed any estimates of total, +proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. +The +following table sets forth estimates of our proved oil and natural gas reserves at December 31, 2007, 2006 and 2005. Reserve estimates at December 31, 2007 were prepared by NSAI with respect to our WCBB field (61% of proved reserves PV-10 +value at December 31, 2007), by Pinnacle Energy Services, LLC with respect to our assets in the Permian Basin in West Texas (18% of proved reserves PV-10 value at December 31, 2007) and by our personnel with respect to our Hackberry fields +and our overrides and non-operated interests (21% of proved reserves PV-10 value at December 31, 2007). The reserve estimates at December 31, 2006 were prepared by NSAI with respect to our WCBB field (82% of proved reserves PV-10 value at +December 31, 2006) and by our personnel with respect to our Hackberry fields and our overrides and non-operated interests (18% of proved reserves PV-10 value at December 31, 2006). Hackberry reserve estimates at December 31, 2005 were +prepared by NSAI. +December 31, 2007 +December 31, 2006 +December 31, 2005 +Developed +Undeveloped +Total +Developed +Undeveloped +Total +Developed +Undeveloped +Total +Oil (MBbls) +7,116 +17,999 +25,115 +4,876 +14,816 +19,692 +4,308 +15,234 +19,542 +Gas (MMcf) +6,746 +17,513 +24,259 +4,077 +16,724 +20,801 +3,758 +18,023 +21,781 +Mboe +8,240 +20,918 +29,158 +5,556 +17,603 +23,159 +4,934 +18,238 +23,172 +PV-10 (in millions) (1) +$ +294.7 +$ +526.5 +$ +821.2 +$ +120.0 +$ +279.4 +$ +399.4 +$ +135.9 +$ +321.0 +$ +456.9 +Standardized measure (in millions) (2) +$ +668.3 +— +— +$ +352.6 +— +— +$ +369.8 +(1) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future +net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2007. The estimated +future production in our WCBB and Hackberry fields is priced at December 31, 2007, 2006 and 2005, without escalation +23 +Table of Contents +Index to Financial Statements +using $92.50 per barrel and $6.80 per MMBtu, $57.75 per barrel and $5.64 per MMBtu and $57.75 per barrel and $10.08 per MMBtu, respectively, adjusted by +lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income +tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas +companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly +comparable GAAP measure—standardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value: +December 31, +2007 +2006 +2005 +Standardized measure of discounted future net +cash flows +$ +668,295,000 +$ +352,648,000 +$ +369,824,000 +Add: Present value of future income tax discounted +at 10% +152,949,000 +46,804,000 +87,086,000 +PV-10 value +$ +821,244,000 +$ +399,452,000 +$ +456,910,000 +(2) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, +and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes +the effect of future income taxes. +The above table does not include proved reserves net to our interest in Tatex, or 3.5 Bcf +of gas and 10,000 barrels of oil at December 31, 2007. For further discussion of our interest in Tatex, see Item 1. “Description of Business—Additional Properties.” +Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved +undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or +from existing wells on which a relatively major expenditure is required to establish production. +Total proved reserves increased to 29,158 +Mboe at December 31, 2007 from 23,159 Mboe at December 31, 2006. Total proved reserves decreased slightly to 23,159 Mboe at December 31, 2006 from 23,172 Mboe at December 31, 2005. The change in 2007 reserves, as compared to 2006 +reserves, is mainly attributable to the acquisition of the Permian assets in December 2007. The decrease in 2006 reserves, as compared to 2005 reserves, is attributable to reserve revisions and reductions related to our 2006 production, mostly +offset by reserve additions from our 2006 drilling activity. +24 +Table of Contents +Index to Financial Statements +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2007 +2006 +2005 +Production Volumes: +Oil (MBbls) +1,501 +870 +517 +Gas (MMcf) +816 +677 +575 +Oil Equivalents (Mboe) +1,637 +983 +613 +Average Prices: +Oil (per Bbl) +$ +66.71 +(1) +$ +64.43 +(1) +$ +46.39 +(1) +Gas (per Mcf) +$ +7.40 +$ +6.20 +$ +5.98 +Oil Equivalents (per Mboe) +$ +64.86 +$ +61.30 +$ +44.75 +Production Costs: +Average Production Costs (per Boe) +$ +10.18 +(2) +$ +10.86 +(2) +$ +12.49 +(2) +Average Production Taxes (per Boe) +$ +7.74 +$ +7.50 +$ +5.91 +Total Production Costs (per Boe) +$ +17.92 +$ +18.36 +$ +18.40 +(1) +Includes fixed contract prices of: +January – June 2005 +$ +33.10 +July – December 2005 +$ +39.70 +January – December 2006 +$ +64.05 +June – December 2007 +$ +66.10 +Excluding the net effect of the fixed price contracts, the average oil price for 2007 would have +been $72.25 per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represents approximately 43% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the average oil price for +2006 would have been $65.56 per barrel and $62.30 per barrel of oil equivalent. The total volume hedged for 2006 represents approximately 62% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the average +oil price for 2005 would have been $56.17 per barrel and $52.99 per barrel of oil equivalent. Also includes financial hedge contracts with an average mark-to-market value of approximately $50,000 per month for the months of July-December 2005 and +approximately $82,000 per month for the months of January-December 2006. +(2) +Does not include production taxes. +Productive Wells and Acreage +The following table presents our total gross and net productive wells, expressed separately for oil and gas, and the total gross and net +developed acres as of December 31, 2007: +NRI/WI (1) +Producing +Wells (2) +Non-Producing +Wells +Developed +Acreage (3) +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +West Cote Blanche Bay (4) +78.665/100 +111 +111 +166 +166 +5,668 +5,668 +E. Hackberry (5) +79.424/100 +12 +12 +82 +82 +3,265 +3,265 +W. Hackberry +87.5/100 +3 +3 +24 +24 +592 +592 +Permian +37.5/50 +32 +16 +— +— +2,560 +1,280 +Overrides/Royalty Non-operated +Various +18 +0.8 +16 +0.7 +4,956 +586 +Total +176 +142.8 +288 +272.7 +17,041 +11,391 +25 +Table of Contents +Index to Financial Statements +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes 30 gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 87% of our acreage is developed acreage and has been perpetuated by production. We have 1,100 and +2,820 net undeveloped acres in the East Hackberry field and the Permian Basin, respectively. +(4) +We have a 100% working interest (78.665% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a +40.40% non-operated working interest (29.95% NRI). +(5) +Does not include an additional 3,233 acres under an option we exercised which will increase our acreage position significantly to approximately 7,598 acres. State approval was +obtained on February 27, 2008, and we are working with the state to finalize the leases. +Completed and Present Drilling and +Recompletion Activities +The following table sets forth information with respect to wells completed during the periods indicated. The +information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive +wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +2007 +2006 +2005 (1) +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +62 +62 +18 +18 +11 +11 +Dry +— +— +1 +1 +— +— +Total +62 +62 +19 +19 +11 +11 +Development: +Productive +23 +23 +24 +24 +16 +16 +Dry +3 +3 +2 +2 +— +— +Total +26 +26 +26 +26 +16 +16 +Exploratory: +Productive +9 +9 +1 +1 +— +— +Dry +3 +3 +1 +1 +1 +1 +Total +12 +12 +2 +2 +1 +1 +(1) +Includes seven gross and net wells that were drilled during 2005 but not completed due to the damage caused by Hurricane Rita. For further discussion of the impact of Hurricane +Rita, see Item 6. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Impact of Hurricane Rita.” +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make +only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on +material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in +management’s opinion, will in the aggregate materially restrict our operations. +26 +Table of Contents +Index to Financial Statements +ITEM 3. LEGAL PROCEEDINGS +The Louisiana State Mineral Board, or LSMB, is disputing +our royalty payments to the State of Louisiana resulting from the sale of oil under fixed price contracts. The LSMB maintains that we paid approximately $1,400,000 less in royalties under the fixed price contracts than the royalties we would have +had to pay had we sold the oil at prevailing market rates. We denied any liability to the LSMB for underpayment of royalties and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay +royalties based upon the sales proceeds from those contracts. We have met with the Attorney General on several occasions and recently reached a mutual settlement. The settlement requires us to pay $250,000, which has been accrued in accounts payable +and accrued liabilities in the accompanying consolidated balance sheet and all future royalties will be paid at market price, regardless of the presence of fixed price contracts. The settlement was approved during the LSMB’s February 2008 +session, and we are currently awaiting the settlement and release documentation from the LSMB to close this matter. +Litigation +In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us and Great White Pressure Control LLC, an affiliate of ours, among +others, in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleges RICO violations and several other causes +of action relating to an affiliate company’s employment of several former Cudd employees and seeks unspecified monetary damages and injunctive relief. The defendants in the suit are Ronnie Roles, Rocky Roles, Steve Winters, Bert Ballard, Nelson +Britton, Michael Fields, Steve Bickle, Great White Pressure Control LLC, and us. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007. Co-defendant, Steve +Bickle, was dismissed from the case on July 18, 2007. The case against us was stayed by order of the court on July 31, 2007. The court further ordered co-defendant, Great White Pressure Control, to move for summary judgment by +August 24, 2007. Cudd was ordered to respond by September 14, 2007. We filed a motion for summary judgment on October 5, 2007. Plaintiff filed a response on November 15, 2007, and we filed a reply on November 21, 2007. We +are currently awaiting the ruling from the Court. +On July 27, 2007, Robotti & Company, LLC filed a putative class action +lawsuit in the Court of Chancery for the State of Delaware in and for Kent County, Delaware. The lawsuit alleges a breach of fiduciary duty by us and our directors in connection with the pricing of the 2004 rights offering. We received service of +this matter on August 10, 2007. By mutual agreement of the parties, we were not required to respond until notified by the plaintiff, which was received on January 16, 2008. Plaintiff filed an amended complaint on January 15, 2008, and +we filed a motion to dismiss in early February 2008. +In July 2007, Michael Tripkovich filed suit in the 16th Judicial District Court of +the Parish of St. Martin, Louisiana, against 113 entities, including us, alleging his contraction of chronic myeloid leukemia (CML) was caused by exposure to various substances while maintaining natural gas compressors over a nineteen year period. +We were served on July 23, 2007 and filed a response accordingly. The suit is currently in the early phases of discovery. We have no record that Mr. Tripkovich was ever employed by our company. No other deadlines have been set at this +time. +In October 2006, an accident occurred north of the our production facilities in the WCBB field in southern Louisiana involving two +contracted vessels that were performing work on behalf of us in the field. A tugboat, the M/V Miss Megan, and two barges laden with construction materials ruptured an underwater natural gas pipeline and a subsequent fire damaged the vessels. +Six fatalities resulted from the accident. The following lawsuits relating to this incident are currently pending before the courts: +• +On October 13, 2006, Athena Construction LLC, or Athena, filed a limitation action in the United States District Court for the Eastern District of Louisiana, +alleging that all losses and damages as a result of the pipeline incident were incurred without fault on its part. Furthermore, Athena claims the benefit of the limitation of liability provided for in 42 U.S.C. § 183 and seeks an injunction +restraining filing +27 +Table of Contents +Index to Financial Statements +commencement and further prosecution in any court of any lawsuit against Athena related to the pipeline incident. The limitation of liability action was +subsequently transferred to the United States District Court for the Western District of Louisiana, which is where the case remains pending. On December 20, 2006, 4-K Marine LLC, as owner of the M/V Miss Megan, and Central Boat Rentals, +Inc., as operator of the M/V Miss Megan also filed a limitation action in the Western District. On January 10, 2007, the Athena and the 4-K/Central Boat limitation proceedings were consolidated by order of the court. On May 5, 2007, +Diamondback Energy, an affiliate of ours, filed an intervener with the Court to become a party to the suit. The remaining parties filed claims on July 9, 2007, which included claims by Nicholas Aucoin, one of the initial responders to the scene +of the accident. A record hearing was held on August 13, 2007, to discuss the status of the consolidated matters and a subsequent work plan was filed on October 3, 2007. No other deadlines have been set. +• +On October 16, 2006, a lawsuit was filed in the 16th Judicial District Court for the Parish of St. Mary, Louisiana against us, Athena, and Central Boat seeking +compensatory and punitive damages for claims related to the death of the plaintiff’s husband, a crewmember on the Athena barge. The suit alleges that the husband’s death was caused by the defendants’ negligence and the unseaworthiness +of the barge to which he was assigned. Pursuant to the Blanket Time Charter between us and Central Boat, Central Boat tendered the defense and indemnification of the lawsuit to us. On November 2, 2006, all proceedings were stayed as a result of +the limitation of liability action discussed above. Settlement was reached during mediations held in December 2007. We are currently working to obtain settlement approvals and releases within the next 30 to 45 days. +• +On October 22, 2006, a lawsuit was filed in United States District Court for the Southern District of Texas, Galveston Division against us, Central Boat, +Diamondback Energy Services LLC, an affiliate of ours, Chevron Pipeline Company, Chevron USA, Inc., and ChevronTexaco Pipeline Holdings, Inc. This lawsuit is a result of the death of three individuals. These individuals were employed by Athena and +were on the Athena barge at the time of the accident. The plaintiffs seek compensatory and punitive damages as a result of the alleged negligence of defendants. Central Boat has tendered the defense and indemnification of this lawsuit to us. On +April 30, 2007, an order was filed transferring the case to the Western District of Louisiana. A successful settlement was reached during mediations held in December 2007. We are currently working to obtain settlement approvals and releases +within the next 30 to 45 days. +• +On February 2, 2007, a lawsuit was filed in the United States District Court for the Western District of Louisiana, Lafayette Division against Chevron Pipeline +Company, Chevron USA Inc., Chevron Texaco Pipeline Holdings, Inc., Chevron Natural Gas Services Inc., Diamondback Energy Services LLC, an affiliate of ours, and us. The suit was filed on behalf of April Hummel, individually and as the representative +of the minor, Aleya Hummel, the surviving child of Terry Abraham who died in the accident. On March 27, 2007, we filed our answer. On September 2, 2007, the case was stayed by order of the Court. A successful settlement was reached in +mediations held in November 2007. We are currently working to obtain settlement approvals and releases. +• +On October 15, 2007, Brian Dumesnil filed suit in the 16th Judicial District Court for the Parish of St. Mary, Louisiana, against us, Chevron USA, Chevron +Texaco Pipeline Holdings, Chevron Natural Gas, Diamondback Energy Services and the Estate of Timothy Tauzin. Mr. Dumesnil was employed by Athena and was on the Athena barge at the time of the accident. He is seeking unspecified sums as a result +of the alleged negligence of defendants and injuries incurred following the October 12, 2006 accident. By mutual agreement of the parties on October 19, 2007, we are not required to respond until receipt of further notification from the +plaintiff. +Due to the early stages of certain of the above litigation, the outcome is uncertain and management cannot +determine the amount of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse affect on our financial condition or results of operations. +28 +Table of Contents +Index to Financial Statements +In addition to the above, we have been named as a defendant in various other lawsuits related to our +business. The ultimate resolution of such other matters is not expected to have a material adverse effect on our financial condition or results of operations. +ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +None. +29 +Table of Contents +Index to Financial Statements +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Through February 27, 2006, our common stock was traded on the NASD OTC Bulletin Board under the symbol “GPOR.OB.” Since February 28, +2006, our common stock has been quoted on The NASDAQ National Market and since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market, in each instance under the symbol “GPOR.” The following table sets +forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2006 +First Quarter +$ +16.00 +$ +10.00 +Second Quarter +15.89 +9.90 +Third Quarter +13.64 +9.82 +Fourth Quarter +14.11 +9.95 +2007 +First Quarter +13.89 +10.82 +Second Quarter +21.34 +12.86 +Third Quarter +23.70 +15.36 +Fourth Quarter +25.62 +16.60 +2008 +First Quarter (through February 29, 2008) +19.41 +13.49 +On March 3, 2008, the last reported sale price of our common stock on The NASDAQ Global +Select Market was $14.11. The above quotations for the periods prior to February 28, 2006 reflect inter-dealer prices, without retail mark-up, markdown or commissions and may not represent actual transactions. +Unregistered Sales of Equity Securities and Use of Proceeds +None. +Holders of Record +At +the close of business on March 3, 2008, there were 361 stockholders of record holding 42,550,031 shares of our outstanding common stock. There were approximately 8,091 beneficial owners of our common stock as of March 3, 2008. +Dividend Policy +We have never paid dividends on +our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibits the +payment of any dividends to the holders of our common stock. +30 +Table of Contents +Index to Financial Statements +ITEM 6. SELECTED FINANCIAL DATA +You should read the following selected +consolidated financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the related notes appearing elsewhere in this +report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2007, December 31, 2006 and December 31, 2005 and the selected consolidated balance sheet data at December 31, 2007 and +December 31, 2006 are derived from our audited consolidated financial statements appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2004 and December 31, +2003 and the selected consolidated balance sheet data at December 31, 2005, December 31, 2004 and December 31, 2003 are derived from our audited consolidated financial statements that are not included in this report. The +historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during any of the periods set forth in the following table. +Fiscal Year Ended December 31, +2007 +2006 +2005 +2004 +2003 +Selected Consolidated Statements of Operations Data: +Revenues +$ +105,838,000 +$ +60,390,000 +$ +27,559,000 +$ +23,190,000 +$ +15,947,000 +Costs and expenses: +Lease operating expenses +16,670,000 +10,670,000 +7,654,000 +6,586,000 +5,886,000 +Production taxes +12,667,000 +7,366,000 +3,622,000 +2,629,000 +1,882,000 +Depreciation, depletion and amortization +29,681,000 +12,652,000 +4,789,000 +4,952,000 +4,637,000 +General and administrative +5,802,000 +3,251,000 +1,561,000 +2,107,000 +1,843,000 +Accretion expense +554,000 +596,000 +516,000 +490,000 +393,000 +65,374,000 +34,535,000 +18,142,000 +16,764,000 +14,641,000 +Income from Operations +40,464,000 +25,855,000 +9,417,000 +6,426,000 +1,306,000 +Other (Income) Expense: +Interest expense +3,091,000 +1,956,000 +250,000 +246,000 +112,000 +Interest expense—preferred stock +— +— +272,000 +1,949,000 +875,000 +Business interruption insurance recoveries +— +(3,601,000 +) +(1,710,000 +) +— +— +Interest income +(523,000 +) +(308,000 +) +(290,000 +) +(73,000 +) +(30,000 +) +2,568,000 +(1,953,000 +) +(1,478,000 +) +2,122,000 +957,000 +Income before Income Taxes and Effect of Change in Accounting Principle +37,896,000 +27,808,000 +10,895,000 +4,304,000 +349,000 +Income Tax Expense +121,000 +— +— +— +— +Net Income before Effect of Change in Accounting Principle +37,775,000 +27,808,000 +10,895,000 +4,304,000 +349,000 +Cumulative effect of change in accounting principal +— +— +— +— +270,000 +Net Income +37,775,000 +27,808,000 +10,895,000 +4,304,000 +619,000 +Less: Preferred stock dividends +— +— +— +— +(838,000 +) +Net Income (Loss) Available to Common Stockholders +$ +37,775,000 +$ +27,808,000 +$ +10,895,000 +$ +4,304,000 +$ +(219,000 +) +Net Income (Loss) Per Common Share—Basic: +Per common share before effect of change in accounting principle +$ +1.03 +$ +0.85 +$ +0.36 +$ +0.31 +$ +(0.05 +) +Effect per common share of change in accounting principle +— +— +— +— +0.03 +$ +1.03 +$ +0.85 +$ +0.36 +$ +0.31 +$ +(0.02 +) +Net Income (Loss) Per Common Share—Diluted: +Per common share before effect of change in accounting principle +$ +1.01 +$ +0.82 +$ +0.34 +$ +0.28 +$ +(0.05 +) +Effect per common share of change in accounting principle +— +— +— +— +0.03 +$ +1.01 +$ +0.82 +$ +0.34 +$ +0.28 +$ +(0.02 +) +31 +Table of Contents +Index to Financial Statements +At Ended December 31, +2007 +2006 +2005 +2004 +2003 +Selected Consolidated Balance Sheet Data: +Total assets +$ +419,137,000 +$ +195,151,000 +$ +111,820,000 +$ +78,150,000 +$ +58,980,000 +Total debt, including current maturity +$ +66,533,000 +$ +37,691,000 +$ +10,200,000 +$ +3,404,000 +$ +2,318,000 +Total liabilities +$ +115,015,000 +$ +71,342,000 +$ +27,493,000 +$ +29,053,000 +$ +25,832,000 +Stockholders’ equity +$ +304,122,000 +$ +123,809,000 +$ +84,327,000 +$ +49,097,000 +$ +33,148,000 +32 +Table of Contents +Index to Financial Statements +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in +this annual report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial +position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and +“Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this annual report on Form 10-K. +Overview +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf +Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. We have also recently acquired strategic assets in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our +interest in Grizzly Oil Sands ULC and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +2007 Highlights +• +Oil and natural gas revenues increased $45.9 million to $106.1 million for the year ended December 31, 2007 from $60.2 million for 2006. +• +Net income increased 36% to $37.8 million for the year ended December 31, 2007 from $27.8 million for 2006. +• +Production increased 67% to 1,637,000 BOE for the year ended December 31, 2007 from 983,000 BOE for 2006. +• +We received net proceeds of approximately $138.3 million from sales of our common stock in underwritten public offerings completed in February 2007, May +2007, July 2007 and December 2007, after deducting the underwriting discount and offering expenses. These net proceeds were used to pay down existing debt under our credit facility and fund substantially all of the purchase price for the +acquisition of certain strategic assets in West Texas in the Permian Basin discussed in more detail below. +• +On December 20, 2007, we completed an acquisition of strategic assets in West Texas in the Permian Basin for approximately $85 million, effective as of +November 1, 2007. In this transaction we acquired 4,100 net acres with production of approximately 800 net BOE a day from 32 gross wells, predominately from the Wolfcamp formation. Existing production is approximately 64% oil, 23% natural gas +liquids and 13% natural gas. We have identified 178 gross future development drilling locations. We expect 17 to 22 net wells to be drilled on this acreage in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated +average gross completed well cost of $1.7 million. We funded this transaction predominately through a 4.5 million common share offering, which closed on December 12, 2007. Operations from these properties were included in our results of +operations for 2007 only from the closing date of December 21, 2007 through December 31, 2007. +• +During the third quarter of 2006, we purchased a 24.9999% interest in Grizzly Oil Sands ULC, a Canadian unlimited liability company holding leases in the Athabasca +region located in northern Alberta Province, Canada near Fort McMurray near other oil sands development projects. As of December 31, 2007, our net investment in Grizzly was approximately $27.8 million. As of December 31, 2007, Grizzly had +approximately 511,000 acres under lease. Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks with four +33 +Table of Contents +Index to Financial Statements +drilling rigs. Core hole samples have been collected and sent to a lab to assess the quantity and thickness of the bitumen in place on our acreage. Future +plans currently include acquiring additional leases, drilling approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling season, and initial planning for construction of a 10,000 barrel per day SAGD +facility as soon as 2008, which could lead to initial production in 2011. Estimated gross capital expenditures for a comparable production facility are approximately $325 million. +• +During 2007, we drilled 38 wells and recompleted 62 wells. Of our 38 new wells drilled, 32 were completed as producing wells and six were non-productive. +Critical Accounting Policies and Estimates +Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted +in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified +certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those +related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. +Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial +statements: +Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations. +Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are +limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated +future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of +oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of +undeveloped leaseholds and totaled $37,278,000 at December 31, 2007 and $1,459,000 at December 31, 2006. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and +natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available +funds for exploration and development. +Ceiling Test . Companies that use the full cost method of accounting for oil and gas +properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes +or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for any contract +provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties +not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas +properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, +future depletion expense would be reduced. A future decline in oil and gas prices may result in an impairment of oil and gas properties. +34 +Table of Contents +Index to Financial Statements +Asset Retirement Obligations . We have obligations to remove equipment and restore land at the end +of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. +We account for abandonment and restoration liabilities under Statement of Financial Accounting Standards No. 143, “ Accounting for Asset +Retirement Obligations, ” SFAS No. 143, which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the +definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The +liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These +liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the +productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset +retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense +and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates. +Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological +analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., Pinnacle Energy Services, LLC and to a +lesser extent our personnel have prepared reserve reports of our reserve estimates on a well-by-well basis for our properties. +Reserves +and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the +projected cash flows derived from these reserve estimates have been prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and +natural gas eventually recovered. +Income Taxes . We use the asset and liability method of accounting for income taxes, under which +deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss +and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on +deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. +35 +Table of Contents +Index to Financial Statements +Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, +looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2007, a +valuation allowance of $9,750,000 had been provided for deferred tax assets based on the uncertainty of future taxable income. +Revenue +Recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially +all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment +received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. +Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when +it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if +any, may result in the recognition and subsequent payment of legal liabilities. +Derivative Instruments and Hedging Activities . We +seek to reduce our exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of SFAS 133, “ Accounting for Derivative Instruments and Hedging Activities ,” +as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. +These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to +reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative +depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness +guidelines of SFAS 133, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value +between the derivative contract and the hedged item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. +To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average daily +price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, we entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per +barrel before transportation costs. In addition, we have entered into agreements to sell 3,500 barrels of production per day for the month of January through May 2008 at a weighted average daily price of $70.29 per barrel before transportation +costs. For the month of June 2008, we have agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, we have agreements to sell 3,000 +barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel +before transportation costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,000 barrels of production per day in each such period at weighted average daily prices of $82.20 per +barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of our estimated production for January through December 2008. For the period of January through December 2009, we entered into agreements to +sell 2,500 barrels of production per day at a weighted average daily price of +36 +Table of Contents +Index to Financial Statements +$84.62 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where +production is less than expected or oil prices increase. These contracts require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal sales of production. +RESULTS OF OPERATIONS +Results of Operations +The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to +relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +The following table +presents our production volumes, average prices received and average production costs during the periods indicated: +2007 +2006 +2005 +Production Volumes: +Oil (MBbls) +1,501 +870 +517 +Gas (MMcf) +816 +677 +575 +Oil Equivalents (Mboe) +1,637 +983 +613 +Average Prices: +Oil (per Bbl) +$ +66.71 +(1) +$ +64.43 +(1) +$ +46.39 +(1) +Gas (per Mcf) +$ +7.40 +$ +6.20 +$ +5.98 +Oil Equivalents (per Mboe) +$ +64.86 +$ +61.30 +$ +44.75 +Production Costs: +Average Production Costs (per Boe) +$ +10.18 +(2) +$ +10.86 +(2) +$ +12.49 +(2) +Average Production Taxes (per Boe) +$ +7.74 +$ +7.50 +$ +5.91 +Total Production Costs (per Boe) +$ +17.92 +$ +18.36 +$ +18.40 +(1) +Includes fixed contract prices of: +January – June 2005 +$ +33.10 +July – December 2005 +$ +39.70 +January – December 2006 +$ +64.05 +June – December 2007 +$ +66.10 +Excluding the effect of the fixed price contracts, the average oil price for 2007 would have been +$72.25 per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represents approximately 43% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the average oil price for 2006 +would have been $65.56 per barrel and $62.30 per barrel of oil equivalent. The total volume hedged for 2006 represents approximately 62% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the average oil +price for 2005 would have been $56.17 per barrel and $52.99 per barrel of oil equivalent. Also includes financial hedge contracts with an average mark-to-market value of approximately $50,000 per month for the months of July-December 2005 and +approximately $82,000 per month for the months of January-December 2006. +(2) +Does not include production taxes. +From 2006 to 2007, our +net oil production increased 73% from 869,728 barrels to 1,500,818 barrels due to our continued drilling activity. From 2005 to 2006, our oil production increased 68% to 869,728 barrels due to our continued drilling activity and also to a loss of +production during the fourth quarter 2005 as a result of the damage caused to our facilities from Hurricane Rita in September 2005. We currently estimate that our 2008 production will be between 1,900,000 and 2,100,000 BOE with production increasing +during the year. +37 +Table of Contents +Index to Financial Statements +Comparison of the Years Ended December 31, 2007 and December 31, 2006 +We reported net income of $37,775,000 for the year ended December 31, 2007, compared to $27,808,000 for the year ended December 31, 2006. This +36% increase in net income was due primarily to (1) a 67% increase in net production to 1,636,902 BOE for the year ended December 31, 2007 from 982,531 BOE for 2006 as a result of our continued drilling activity and (2) a 6% increase +in the average BOE oil price received to $64.86 per barrel for the year ended December 31, 2007 from $61.30 per barrel for 2006. Although we closed the acquisition of the assets in the Permian Basin in West Texas on December 20, 2007, +effective as of November 1, 2007, under GAAP only the oil and gas activities for the days subsequent to the closing date, which in this case were from December 21 through December 31, 2007, can be included in our 2007 oil and gas +activities. As a result, activities related to these new assets had little impact on our results of operations for the year ended December 31, 2007. +Oil and Gas Revenues . For the year ended December 31, 2007, we reported oil and gas revenues of $106,163,000, compared to oil and gas revenues of $60,232,000 during 2006. This $45,931,000, or 76%, increase +in revenues is primarily attributable to a 67% increase in net production to 1,636,902 BOE for the year ended December 31, 2007 from 982,531 BOE for the year ended December 31, 2006. Production in the first half of 2006 was negatively +impacted by the damage caused by Hurricane Rita, as production from our wells at WCBB was not fully restored until later in 2006. +The +following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2007 and 2006: +Year Ended +December 31, +2007 +2006 +Oil production volumes (MBbls) +1,501 +870 +Gas production volumes (MMcf) +816 +677 +Oil equivalents (Mboe) +1,637 +983 +Average oil price (per Bbl) +$ +66.71 +$ +64.43 +Average gas price (per Mcf) +$ +7.40 +$ +6.20 +Oil equivalents (per Boe) +$ +64.86 +$ +61.30 +Lease Operating Expenses . Lease operating expenses not including production taxes increased +to $16,670,000 for the year ended December 31, 2007 from $10,670,000 for 2006. Since our WCBB facilities continued to be shut in until late in the first quarter of 2006 due to the impact of Hurricane Rita some of the costs that would have +normally been associated with our lease operating expenses were instead spent on ongoing restoration and repair activities during the year ended December 31, 2006. In addition, lease operating expenses for the year ended December 31, 2007 +increased due to increased labor requirements associated with a ramp up in overall activity in both fields, increases in rates paid for labor and other services, increases in the cost of oil-based supplies, non-recurring repairs including repairs to +compressors, and increases in property taxes in both fields as a result of the on-going capital programs. These increases were partially offset by a reduction in lease operating expenses attributable to our interest in the Marquiss field which we +sold during February 2007. +Production Taxes . Production taxes increased to $12,667,000 for the year ended December 31, 2007 +from $7,366,000 for 2006. This increase was directly related to a 76% increase in oil and gas revenues as a result of the increase in production. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense increased to $29,681,000 for the year ended December 31, 2007, and consisted of $29,220,000 in depletion on oil and natural gas +properties and $461,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $12,652,000 for the year ended December 31, 2006. This increase was due primarily to an increase +in our production, an increase in our oil and natural gas property costs associated with our 2006 and 2007 drilling programs and an increase in our future development costs. +38 +Table of Contents +Index to Financial Statements +General and Administrative Expenses . Net general and administrative expenses increased to +$5,802,000 for 2007 from $3,251,000 for 2006. This increase was due primarily to increases in payroll costs and related benefits as a result of increases in the total number of employees. In addition, this increase also resulted from $310,000 of +costs associated with the implementation of Section 404 of the Sarbanes-Oxley Act, an increase of $300,000 in franchise taxes, an increase of $220,000 for the services provided by our external reserve engineers, an increase of $100,000 in our +business and D&O insurance costs and an increase of $95,000 for expenses associated with SFAS No. 123(R), “ Share Based Payment. ” These increases were partially offset by an increase in the amount of capitalized general and +administrative expenses and a decrease in legal expenses and corporate fees. +Accretion Expense . Accretion expense decreased to +$554,000 for 2007 from $596,000 for 2006. Although there was a larger obligation at the beginning of 2007 than there was at the beginning of 2006 resulting from the addition of future abandonment obligations on new wells drilled during 2006, the +effect of the increase on the larger obligations was more than offset by the effect of the sale of the Marquiss properties in February 2007. +Interest Expense . Interest expense increased to $3,091,000 for 2007 from $1,956,000 for 2006 due to an increase in average debt outstanding. Total weighted debt outstanding under our facilities with Bank of America was $33.2 million +for the year ended December 31, 2007, as compared to $18.8 million for 2006. In addition, during July 2006 we entered into a new $5.0 million term loan agreement with Bank of America. As a result, during the year ended December 31, 2007, +we recognized a full year of interest related to the term loan in the amount of $382,000 as compared to only $115,000 for 2006. +Income +Taxes . As of December 31, 2007, we had a net operating loss carry forward of approximately $93 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of +our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s +opinion, it is more likely than not that some portion will not be realized. At December 31, 2007, a valuation allowance of $9.8 million had been provided for deferred tax assets. We had only a slight income tax expense of $121,000 during the +year ended December 31, 2007 related to the payment of alternative minimum taxes due for 2006 and 2007. Although we have substantial net operating loss carryforwards, these cannot be used to offset alternative minimum tax liabilities. +Comparison of the Years Ended December 31, 2006 and December 31, 2005 +We reported net income of $27,808,000 for the year ended December 31, 2006, compared to $10,895,000 for the year ended December 31, 2005. This +155% increase in net income was due primarily to (1) a 60% increase in net production to 982,531 BOE for the year ended December 31, 2006 from 612,840 BOE for 2005, (2) a 39% increase in the average oil price received to $64.43 per +barrel for the year ended December 31, 2006 from $46.39 per barrel for 2005 and (3) business interruption insurance recoveries of $3,601,000 due to Hurricane Rita. +Oil and Gas Revenues . For the year ended December 31, 2006, we reported oil and gas revenues of $60,232,000, compared to oil and gas revenues +of $27,423,000 during 2005. This 120% increase in revenues is mainly attributable to a 60% increase in net production to 982,531 BOE for the year ended December 31, 2006 from 612,840 BOE for 2005 and a 39% increase in the average oil price +received to $64.43 per barrel for the year ended December 31, 2006 from $46.39 per barrel for 2005. This increase in oil and natural gas production was the result of production from our 2006 drilling program and restoration of fields and +facilities for which production was curtailed due to Hurricane Rita. Production in 2005 and 2006 was adversely affected by the damage caused by Hurricane Rita. In addition, production in 2006 was adversely affected by the accident in our field on +October 12, 2006, which shut in our facilities from that date through early December 2006. +39 +Table of Contents +Index to Financial Statements +The following table summarizes our oil and natural gas production and related pricing for the years ended +December 31, 2006 and December 31, 2005: +Year Ended +December 31, +2006 +2005 +Oil production volumes (MBbls) +870 +517 +Gas production volumes (MMcf) +677 +575 +Oil equivalents (Mboe) +983 +613 +Average oil price (per Bbl) +$ +64.43 +$ +46.39 +Average gas price (per Mcf) +$ +6.20 +$ +5.98 +Oil equivalents (per Boe) +$ +61.30 +$ +44.75 +Lease Operating Expenses . Lease operating expenses not including production taxes increased +to $10,670,000 for 2006 from $7,654,000 for 2005. This increase was mainly due to increases in insurance costs, $972,000 in one time non-recurring repairs to the WCBB gas sales pipeline related to the tug boat accident that occurred in October 2006 +and the increases in the general costs of labor and supplies in our operating area along the Louisiana Gulf Coast. +Production +Taxes . Production taxes increased to $7,366,000 for 2006 from $3,622,000 for 2005. This increase was directly related to a 120% increase in oil and gas revenues as a result of the 37% improvement in the price received per barrel oil equivalent +and a 60% increase in production for 2006 compared to 2005. +Depreciation, Depletion and Amortization . Depreciation, depletion and +amortization expense increased to $12,652,000 for the year ended December 31, 2006, and consisted of $12,259,000 in depletion on oil and natural gas properties and $393,000 in depreciation of other property and equipment. This compares to total +depreciation, depletion and amortization expense of $4,789,000 for the year ended December 31, 2005. This increase was due primarily to an increase in our oil and natural gas property costs associated with our 2006 drilling program and an +increase in our oil and gas production for the period. +General and Administrative Expenses . Net general and administrative expenses +increased to $3,251,000 for 2006 from $1,561,000 for 2005. This increase was due primarily to the $1,063,000 effect of the implementation of SFAS No. 123(R), “Share Based Payment” (less $276,000 capitalized for personnel directly +related to our exploration and development activities), a $250,000 increase in corporate fees relating to being a NASDAQ listed company, and general increases in the payroll costs and related benefits as a result of the increased number of +employees. These increases were partially offset by increases in general administrative reimbursements from our affiliates. +Accretion +Expense . Accretion expense increased $80,000 to $596,000 for 2006 from $516,000 for 2005, due to a larger obligation at the beginning of 2006 compared to the beginning of 2005, resulting from the addition of future abandonment obligations on new +wells drilled during 2005. +Interest Expense . Ordinary interest expense increased to $1,956,000 for 2006 from $250,000 for 2005 due +to an increase in average debt outstanding. At December 31, 2006, total debt outstanding under our facility with Bank of America was $34,800,000. At December 31, 2005, $7,000,000 was outstanding under this facility. +Interest Expense—Preferred Stock . During the year ended December 31, 2005, we incurred interest expense on preferred stock classified as +a liability under SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” During 2005, we redeemed all of the remaining outstanding shares of our Series A preferred stock. As a +result, we incurred no interest expense relating to preferred stock during 2006 as compared to $272,000 in interest expense incurred during 2005. +Income Taxes . As of December 31, 2006, we had a net operating loss carry forward of approximately $95.9 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management +performs a forecast of our future taxable income to determine whether it is more likely than not that +40 +Table of Contents +Index to Financial Statements +a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in +management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2006, a valuation allowance of $25.5 million had been provided for our entire net deferred tax asset. We had no income tax expense due +to a change in the valuation allowance for deferred income taxes for the year ended December 31, 2006. +Liquidity and Capital Resources +Overview . Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, the +issuance of equity securities and borrowings under our bank and other credit facilities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and gas production. During +the year ended December 31, 2006, recoveries under our insurance coverages also provided a significant source of funds due to damage from Hurricane Rita in September 2005 and the resulting interruption of our business during the fourth quarter +of 2005 and the six months ended June 2006. +Net cash flow provided by operating activities was $68,902,000 for 2007, as compared to net +cash flow provided by operating activities of $39,523,000 for 2006. This increase was primarily the result of an increase in cash receipts from our oil and gas purchasers due to a 67% increase in net production, partially offset by increases in cash +paid for lease operating expenses and production taxes. +Net cash flow provided by operating activities was $15,200,000 for 2005, as +compared to $39,523,000 for 2006. The increase of $24,323,000 in 2006 was primarily the result of an increase in cash receipts from our oil and gas purchasers due to higher prices received for oil production and a 60% increase in net production, +partially offset by increase in cash paid for lease operating expenses and production taxes. +Net cash used in investing activities for +2007 was $240,733,000, as compared to $73,876,000 for 2006. During the year ended December 31, 2007, we spent $220,044,000 in additions to oil and natural gas properties, of which $96,113,000 was spent on our 2007 drilling program, $85,230,000 +was spent on our acquisition of certain strategic assets in Upton County, Texas in the Permian Basin, $12,319,000 was spent on expenses attributable to the wells drilled during 2006, $9,467,000 was spent on our new Hackberry barge facilities, +$2,834,000 was spent on additions to oil and natural gas properties due to Hurricane Rita, with the remainder attributable mainly to facility enhancement and capitalized general and administrative expenses. During the year ended December 31, +2007, we made investments of $17,316,000 in Grizzly. During the year ended December 31, 2007, we used cash from operations, proceeds from the sale of 8,547,500 shares of our common stock and borrowings under our credit facility to fund our +investing activities. +Net cash used in investing activities for 2005 was $36,703,000, as compared to $73,876,000 for 2006. During the year +ended December 31, 2006, we spent $62,403,000 in additions to oil and natural gas properties, of which $40,040,000 was spent on our 2006 drilling program, $5,175,000 was attributable to the wells drilled during 2005, $2,179,000 was spent on +additions to oil and natural gas properties due to the hurricane net of insurance proceeds, $5,517,000 was spent on new compressors for WCBB, with the remainder attributable mainly to capitalized general and administrative expenses and +recompletions. In addition, during the year ended December 31, 2006, we made investments of $964,000 in Tatex Thailand II, $1,416,000 in Windsor Bakken LLC, and $8,493,000 in Grizzly Oil Sands ULC. We used cash from operations, proceeds from +the sale of company common stock, insurance recoveries and borrowings under our credit facility to fund our investing activities in 2006. +Net cash provided by financing activities for 2007 was $167,968,000, as compared to $38,861,000 for 2006. The 2007 amount provided by financing activities is primarily attributable to borrowings of $76,000,000 under our credit facility with +Bank of America and aggregate proceeds of approximately $138,258,000 from the sale of shares of our common stock in February 2007, May 2007, July 2007 and December 2007, after deducting the underwriting discount and offering expenses, and +$868,000 from the exercise of stock options. Net proceeds were used to pay down $46,328,000 of outstanding existing debt under our credit facility with Bank of America, +41 +Table of Contents +Index to Financial Statements +fund substantially all of the purchase price for the acquisition of our interest in certain strategic assets in Upton County, Texas in the Permian Basin and +for other general corporate purposes. The 2006 amount provided by financing activities is attributable to draws of $33,300,000 on our credit facility with Bank of America and proceeds before offering costs of $10,451,000 from the issuance of common +stock in our May 2006 underwritten public offering and $1,276,000 from the exercise of stock options. +Net cash provided by financing +activities for 2005 was $16,080,000, which amount is primarily attributable to aggregate net cash proceeds of approximately $23,600,000 from (1) the issuance of common stock in two private placements and (2) the exercise of the outstanding +warrants and net borrowings of $6,796,000, partially offset by the approximately $14,292,000 used to redeem all 14,202 outstanding shares of our Series A preferred stock. +Issuance of Equity . In January 2007, we sold 1,150,000 shares of our common stock in an underwritten offering at an offering price to the public of $11.92 per share. In connection with the offering, we granted +the underwriter an option to purchase up to an additional 172,500 shares of our common stock to cover any over-allotments, which the underwriter exercised in full. We received the net proceeds of approximately $15.3 million from the sale of these +shares on February 5, 2007 after deducting the underwriting discount and before offering expenses. These net proceeds were used to pay down outstanding debt under our credit facility. +In May 2007, we sold 1,500,000 shares of our common stock in an underwritten offering at an offering price to the public of $16.00 per share. In +connection with the offering, we granted the underwriter an option to purchase up to an additional 225,000 shares of our common stock to cover any over-allotments, which the underwriter exercised in full. We received the net proceeds of +approximately $26.8 million from the sale of these shares on May 22, 2007 after deducting the underwriting discount and before offering expenses. These net proceeds were used to pay down outstanding debt under our credit facility. +In July 2007, we sold 1,000,000 shares of our common stock in an underwritten offering at an offering price to the public of $22.00 per share. We +received the net proceeds of approximately $21.2 million from our sale of these shares on July 25, 2007 after deducting the underwriting discount and before offering expenses. +In December 2007, we sold 4,500,000 shares of our common stock in an underwritten offering at an offering price to the public of $17.50 per share. We +received the net proceeds of approximately $75.6 million from our sale of these shares on December 12, 2007 after deducting underwriting discounts and commissions and before offering expenses. We used the net proceeds from this offering to fund +substantially all of the purchase price for our interest in the acquisition of certain strategic assets in Upton County, Texas in the Permian Basin. In connection with this offering, a selling stockholder granted the underwriters an option to +purchase an additional 675,000 shares of our common stock at a price of $16.80 per share solely to cover any over-allotments, which underwriters exercised in full. We did not receive any proceeds from the sale of shares of our common stock by the +selling stockholder. +Credit Facility . On March 11, 2005, we entered into a three-year secured reducing credit agreement, as +amended, providing for a revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. On +November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount available under the borrowing base +limitation was increased to $30.0 million. Effective July 19, 2007, the credit facility increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0 million. In connection with our acquisition +of strategic assets in West Texas in the Permian Basin, effective as of December 20, 2007, our borrowing base under the revolving credit facility increased from $60.0 million to $90.0 million and the Eurodollar interest rate, which we can elect +to use at our option, reduced by 0.75%. In addition, the maturity date was extended from March 31, 2009 to March 31, 2010. We agreed to pay a borrowing base increase fee of 0.50% of any increase of the borrowing base over the highest +borrowing base previously in effect, payable on the day such increased borrowing base becomes effective. We make quarterly +42 +Table of Contents +Index to Financial Statements +interest payments on amounts borrowed under the facility, which amounts bear interest at Bank of America prime plus 0.25% (7.5 % at December 31, 2007). +Our obligations under the credit facility are collateralized by a lien on substantially all of our Louisiana and West Texas oil and gas assets. +The credit facility contains certain affirmative and negative covenants, including, but not limited to the following financial covenants: (a) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding +unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest expense, plus exploration costs deducted in determining net income under full cost accounting) for a twelve-month +period may not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with all covenants at December 31, 2007. As of +December 31, 2007, approximately $59.5 million was outstanding under this facility, which is included in long-term debt, net of current maturities on the accompanying consolidated balance sheet. We have used the proceeds of our borrowings under +the credit facility for the exploration of our oil and natural gas properties and other capital expenditures, acquisition opportunities, replacement of facilities and equipment due to Hurricane Rita and for other general corporate purposes. +On July 10, 2006, we entered into a $5.0 million term loan agreement with Bank of America, N.A. related to the purchase of new gas +compressor units. The loan began amortizing quarterly on March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. Amounts borrowed bear interest at Bank of America prime +(7.25 % at December 31, 2007). We make quarterly interest payments on amounts borrowed under the agreement. Our obligations under the agreement are collateralized by a lien on the compressor units. As of December 31, 2007, approximately +$4.3 million was outstanding under this agreement, of which $714,000 and $3,580,000 are included in current maturities of long-term debt and long-term debt, net of current maturities, respectively, on our accompanying consolidated balance sheet. +Building Loans . We had three loans associated with two of our buildings. One loan, in the original principal amount of $115,000, +related to a building in Lafayette, Louisiana, that we purchased in 1996 to be used as our Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. We repaid this loan in full during the third quarter of 2007. In +addition, in June 2004 we purchased the office building we occupy in Oklahoma City, Oklahoma for $3.7 million. One of the two loans associated with this building, with an original principal amount of $389,000, matured in March 2006 and bore interest +at a rate of 6% per annum. The other loan associated with this building, with an original principal amount of $3.0 million, matures in June 2011 and bears interest at a rate of 6.5% per annum. The remaining building loan requires monthly +interest and principal payments and is collateralized by the respective land and buildings. +Capital Expenditures . Our recent +capital commitments have been primarily for the development of our proved reserves, to increase our net acreage position in Grizzly Oil Sands ULC and fund Grizzly’s delineation drilling program and for acquisitions, primarily our recently +completed transaction in the Permian Basin. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties and +(2) explore other acquisition opportunities. We have upgraded our infrastructure and our existing facilities with the goal of increasing operating efficiencies and volume capacities and lowering lease operating expenses. These upgrades were +also intended to better enable our facilities to withstand future hurricanes with less damage. Additionally, we completed the reprocessing of 3-D seismic data in one of our principal properties, WCBB. The reprocessed data enables our geophysicists +to continue to generate new prospects and enhance existing prospects in the intermediate zones in the field, thus creating a portfolio of new drilling opportunities. In addition, with our acquisition of strategic assets in the Permian Basin in West +Texas, we will also be required to pay 50% of all drilling costs for future drilling activity on such properties. +43 +Table of Contents +Index to Financial Statements +In our December 31, 2007 reserve reports, 72% of our net reserves were categorized as proved +undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize +reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities. +Our inventory of prospects includes approximately 111 drilling locations at WCBB. The drilling schedule used in our December 31, 2007 reserve report anticipates that all of those wells will be drilled by 2019. +From January 1, 2008 through March 1, 2008, we drilled two wells and recompleted 14 existing wells at our WCBB field. We currently intend to spend a total of approximately $21 to $23 million for drilling, recompletion and other activities +in our WCBB field during 2008. +In our East Hackberry field, from January 1, 2008 through March 1, 2008, we drilled one well and +recompleted three wells. We intend to drill three to five additional land wells and recomplete one additional well during 2008. Total capital expenditures for our East Hackberry field during 2008 are estimated at $17 to $19 million. +During the third quarter of 2006, we purchased a 24.9999% interest in Grizzly. As of December 31, 2007, our net investment in Grizzly was +approximately $27.8 million. Capital requirements in 2008 for this project are now estimated to be approximately $8 to $10 million, primarily for the expenses associated with our 2007/2008 55 to 60 well core hole drilling program, a seismic program +and additional lease acquisitions. +Capital expenditures in 2008 relating to our interest in Thailand are expected to be approximately $1.0 +million, which we believe will be mostly offset from our share of production from the Phu Horm field. +Capital expenditures in 2008 +relating to our interest in the Bakken Shale in the Williston Basin are expected to be approximately $10.0 million, which we believe will be partially offset from our share of production from the field. +We anticipate that our capital requirements for our properties in the Permian Basin in West Texas purchased on December 20, 2007 will be +approximately $35 million during 2008. We have identified 178 gross future development drilling locations. We currently expect that approximately 17 to 22 net wells will be drilled on this acreage in 2008. +Our total capital expenditures for 2008 are currently estimated to be $95 million. We believe that our cash on hand, cash flow from operations and +borrowings under our credit facility will be sufficient to meet our normal recurring operating needs, debt service obligations, and our WCBB, Hackberry, Bakken, and Permian Basin capital requirements for the next twelve months. In the event we elect +to further expand or accelerate our drilling programs, pursue acquisitions or accelerate our Canadian oil sands project, we will be required to obtain additional funds which we may do so through traditional borrowings, offerings of debt or equity +securities or other means, including the sale of assets. Needed capital may not be available to us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail +implementation of our business plan or not be able to complete acquisitions that may be favorable to us. +Commodity Price Risk +To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales contracts for the sale of 3,000 barrels of production +per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, we entered into forward sales contracts for the sale of 3,500 barrels of +production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell 3,500 barrels of production per day for the month of January through May 2008 at a weighted +average daily price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500 +44 +Table of Contents +Index to Financial Statements +barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, we have +agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily +price of $82.44 per barrel before transportation costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,000 barrels of production per day in each such period at weighted average +daily prices of $82.20 per barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of our estimated production for January through December 2008. For the period of January through December 2009, we +entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain circumstances, including +instances where production is less than expected or oil prices increase. These contracts require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal sales of production. In addition, these +arrangements may limit the benefit to us of increases in the price of oil. +Commitments +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller’s (Chevron) obligation to +contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in +production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2007, the +plugging and abandonment trust totaled approximately $3,104,000, including interest received during 2007 of approximately $126,000. At December 31, 2007, we had plugged 243 wells at WCBB since we began our plugging program in 1997. An +additional ten wells were plugged in January 2008, which management believes fulfills our minimum plugging obligation through March 31, 2008. +Contractual and Commercial Obligations +Payment due by period +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +Short-term and long-term debt +$ +66,533,000 +$ +808,000 +$ +64,288,000 +$ +1,437,000 +$ +— +Asset retirement obligations +8,634,000 +480,000 +1,228,000 +779,000 +6,147,000 +Total +$ +75,167,000 +$ +1,288,000 +$ +65,516,000 +$ +2,216,000 +$ +6,147,000 +New Accounting Pronouncements +We adopted FASB Interpretation No. 48, “ Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109 ,” as of January 1, 2007. The adoption of this +Interpretation had no effect on our consolidated financial statements. We are subject to U.S. federal income tax as well as income tax of multiple state jurisdictions. Our 1996–2006 U.S. federal and state income tax returns remain open to +examination by the Internal Revenue Service. We are continuing our practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. +SFAS 157 +In September 2006, the FASB issued SFAS +No. 157, “ Fair Value Measurements .” SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted +accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, +2007, with earlier adoption permitted. However, in February, 2008, the FASB issued FSP No. FAS 157-2, “ Effective Date of FASB Statement No. 157” which delays +45 +Table of Contents +Index to Financial Statements +the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair +value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for +items within the scope of this FSP. We are currently assessing the impact, if any, of the adoption of SFAS 157. +SFAS No. 159 +In February 2007, the FASB issued SFAS No. 159, “ The Fair Value Option for Financial Assets and Financial Liabilities—Including an +Amendment of FASB Statement No. 115 .” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing companies with the +opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which we elect the fair +value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently assessing the impact, if any, of the adoption of SFAS No. 159. +SFAS No. 141(R) +In December 2007, the FASB +issued SFAS No. 141 (revised 2007), “ Business Combinations ” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures +in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to +evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. We are currently assessing the impact, if any, the +adoption of SFAS No. 141(R) may have on any future acquisitions. +SFAS No. 160 +In December 2007, the FASB issued SFAS No. 160, “ Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB +No. 51. ” SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide +sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit +organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year +beginning after December 15, 2008. We are currently assessing the impact, if any, of the adoption of SFAS 160. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices +have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and +expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can +affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability +of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production +controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +46 +Table of Contents +Index to Financial Statements +These factors and the volatility of the energy markets make it extremely difficult to predict future oil +and natural gas price movements with any certainty. For example, over the last four years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.83 per barrel, or bbl, in January 2004 to a high of $102.20 per bbl on +March 6, 2008. The Henry Hub spot market price of natural gas has ranged from a low of $4.20 per million British thermal units, or MMBtu, in October 2006 to a high of $13.93 per MMBtu in October 2005. On December 31, 2007, the West Texas +Intermediate posted price for crude oil was $92.50 per bbl and the Henry Hub spot market price of natural gas was $6.80 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our +operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. To mitigate the effects of commodity +price fluctuations, during 2007, we entered into forward sales contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the +period of July 2007 through December 2007, we entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In addition, we have entered +into agreements to sell 3,500 barrels of production per day for the months of January through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500 +barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 +per barrel before transportation costs. For August 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation costs. For the periods of September 2008 through +December 2008, we have entered into forward sales contracts for the sale of 3,000 barrels of production per day in each such period at weighted average daily prices of $82.20 per barrel before transportation costs. Under these agreements we have +committed to deliver approximately 60% of our estimated production for January through December 2008. For the period of January through December 2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily +price of $84.62 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These contracts require +physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +Our credit facility and term loan with Bank of America are structured under floating rate terms and, as such, our interest expense is sensitive to +fluctuations in the prime rates in the U.S. Borrowings under our revolving credit facility with Bank of America bear interest at Bank of America prime plus 0.25% (7.5 % at December 31, 2007). Borrowings under our term loan with Bank of America +bear interest at Bank of America prime (7.25 % at December 31, 2007). Based on the current debt structure, a 1% increase in interest rates would increase interest expense by approximately $638,000 per year, based on an aggregate of $63.8 +million outstanding under our credit facilities as of December 31, 2007. As of December 31, 2007, we did not have any interest rate swaps to hedge our interest risks. +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The +information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +47 +Table of Contents +Index to Financial Statements +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of +Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to +be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and +procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding +required disclosures. +As of December 31, 2007, an evaluation was performed under the supervision and with the participation of +management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of +1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2007, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that +occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation +of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the +Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the +preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal +control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted +an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its +evaluation under the framework in Internal Control—Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was +effective as of December 31, 2007. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial +statements for the year ended December 31, 2007 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2007, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +48 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited internal control over +financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over +financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we +plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial +reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the +circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the +company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company +are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the +company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial +reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance +with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over +financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We +have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 17, 2008 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 17, 2008 +ITEM 9B. +OTHER INFORMATION +None. +49 +Table of Contents +Index to Financial Statements +PART III +ITEM 10. +DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our definitive Information Statement, which will be filed with the Securities and Exchange Commission within 120 days after the close +of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning +Item 11—Executive Compensation, see our definitive Information Statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this +reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our +definitive Information Statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein +that are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive Information Statement, which will be filed with the Securities and Exchange +Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For +information concerning Item 14—Principal Accounting Fees and Services, see our definitive Information Statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and +is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +50 +Table of Contents +Index to Financial Statements +PART IV +ITEM 15. +EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES +List +the following documents filed as part of this report: +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian +(incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor +Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the +SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on +July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited +partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party +thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other +affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +51 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Registrant and Mike Liddell (incorporated by reference to Exhibit 10.5 of Amendment No. 1 +to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5 +Credit Agreement, dated as of March 11, 2005, by and among the Company, each lender from time to time party thereto and Bank of America, N.A., as agent (incorporated by reference to Exhibit +10.9 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +10.6 +Second Amendment to Credit Agreement, dated as of July 19, 2007, between the Company and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, +filed by the Company with the SEC on July 19, 2007). +10.7 +Note dated July 19, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company with +the SEC on July 19, 2007). +10.8 +Third Amendment to Credit Agreement, dated as of December 20, 2007, between the Company, Bank of America, N.A., as a lender and administrative agent and such other lenders from time to time +party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2007). +10.9 +Note dated December 20, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company +with the SEC on December 26, 2007). +10.10 +Administrative Services Agreement, effective as of April 1, 2005, by and between Bronco Drilling Company, Inc. and Gulfport Energy Corporation (incorporated by reference from Exhibit 10.1 of +Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on August 15, 2005). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +52 +Table of Contents +Index to Financial Statements +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this +report to be signed on its behalf by the undersigned, thereunto duly authorized. +Date: March 17, 2008 +G ULFPORT E NERGY C ORPORATION +By: +/ S / J AMES D. +P ALM +James D. Palm +Chief Executive Officer +In accordance with the Exchange Act, this report has been signed below by the following +persons on behalf of the registrant and in the capacities and on the dates indicated. +Date: March 17, 2008 +By: +/ S / J AMES D. P ALM +James D. Palm +Chief Executive Officer and Director +(Principal Executive Officer) +Date: March 17, 2008 +By: +/ S / M IKE L IDDELL +Mike Liddell +Chairman of the Board and Director +Date: March 17, 2008 +By: +/ S / M ICHAEL G. M OORE +Michael G. Moore +Vice President and Chief Financial Officer +(Principal Financial and Accounting +Officer) +Date: March 17, 2008 +By: +/ S / D ONALD D ILLINGHAM +Donald Dillingham +Director +Date: March 17, 2008 +By: +/ S / D AVID L. H OUSTON +David L. Houston +Director +Date: March 17, 2008 +By: +/ S / S COTT E. S TRELLER +Scott E. Streller +Director +S-1 +Table of Contents +Index to Financial Statements +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +I +NDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets, December 31, 2007 and December 31, 2006 +F-3 +Consolidated Statements of Operations, Years Ended December 31, 2007, 2006 and 2005 +F-4 +Consolidated Statements of Stockholders’ Equity and Comprehensive Income, Years Ended December 31, 2007, 2006 and 2005 +F-5 +Consolidated Statements of Cash Flows, Years Ended December 31, 2007, 2006 and 2005 +F-6 +Notes to Financial Statements +F-7 +F-1 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of +December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2007. These financial +statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the +financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles +used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation +and Subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in +the United States of America. +As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of Financial Accounting +Standards No. 123 (revised 2004), Share-Based Payment, on a modified prospective basis effective January 1, 2006. +We have also audited, in accordance with +the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated +Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 17, 2008 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 17, 2008 +F-2 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +December 31, +2007 +December 31, +2006 +Assets +Current assets: +Cash and cash equivalents +$ +2,764,000 +$ +6,627,000 +Accounts receivable—oil and gas +10,510,000 +7,585,000 +Insurance settlement receivables +— +541,000 +Accounts receivable—related parties +2,208,000 +4,202,000 +Prepaid expenses and other current assets +1,346,000 +972,000 +Total current assets +16,828,000 +19,927,000 +Property and equipment: +Oil and natural gas properties, full-cost accounting, +$37,278,000 and $1,459,000 excluded from amortization in 2007 and 2006, respectively +484,487,000 +250,838,000 +Other property and equipment +7,108,000 +6,651,000 +Accumulated depletion, depreciation and amortization +(129,496,000 +) +(99,815,000 +) +Property and equipment, net +362,099,000 +157,674,000 +Other assets: +Equity investments +33,822,000 +14,363,000 +Other assets +6,388,000 +3,187,000 +Total other assets +40,210,000 +17,550,000 +Total assets +$ +419,137,000 +$ +195,151,000 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +39,848,000 +$ +24,793,000 +Asset retirement obligation—current +480,000 +480,000 +Current maturities of long-term debt +808,000 +835,000 +Total current liabilities +41,136,000 +26,108,000 +Asset retirement obligation—long-term +8,154,000 +8,378,000 +Long-term debt, net of current maturities +65,725,000 +36,856,000 +Total liabilities +115,015,000 +71,342,000 +Commitments and contingencies (Notes 18 and 19) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and +outstanding +— +— +Stockholders’ equity: +Common stock—$.01 par value, 55,000,000 authorized, 42,453,587 issued and outstanding in 2007 and 33,659,759 in 2006 +424,000 +337,000 +Paid-in capital +271,807,000 +131,610,000 +Accumulated other comprehensive income +2,254,000 +— +Retained earnings (accumulated deficit) +29,637,000 +(8,138,000 +) +Total stockholders’ equity +304,122,000 +123,809,000 +Total liabilities and stockholders’ equity +$ +419,137,000 +$ +195,151,000 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +Year Ended December 31, +2007 +2006 +2005 +Revenues: +Oil and condensate sales +$ +100,120,000 +$ +56,038,000 +$ +23,986,000 +Gas sales +6,043,000 +4,194,000 +3,437,000 +Other income (expense) +(325,000 +) +158,000 +136,000 +105,838,000 +60,390,000 +27,559,000 +Costs and expenses: +Lease operating expenses +16,670,000 +10,670,000 +7,654,000 +Production taxes +12,667,000 +7,366,000 +3,622,000 +Depreciation, depletion and amortization +29,681,000 +12,652,000 +4,789,000 +General and administrative +5,802,000 +3,251,000 +1,561,000 +Accretion expense +554,000 +596,000 +516,000 +65,374,000 +34,535,000 +18,142,000 +INCOME FROM OPERATIONS +40,464,000 +25,855,000 +9,417,000 +OTHER (INCOME) EXPENSE: +Interest expense +3,091,000 +1,956,000 +250,000 +Interest expense—preferred stock +— +— +272,000 +Business interruption insurance recoveries +— +(3,601,000 +) +(1,710,000 +) +Interest income +(523,000 +) +(308,000 +) +(290,000 +) +2,568,000 +(1,953,000 +) +(1,478,000 +) +INCOME BEFORE INCOME TAXES +37,896,000 +27,808,000 +10,895,000 +INCOME TAX EXPENSE +121,000 +— +— +NET INCOME +$ +37,775,000 +$ +27,808,000 +$ +10,895,000 +NET INCOME PER COMMON SHARE: +Basic +$ +1.03 +$ +0.85 +$ +0.36 +Diluted +$ +1.01 +$ +0.82 +$ +0.34 +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME +Common Stock +Additional +Paid-in +Capital +Notes +Receivable +for +Exercise +of Options +Accumulated +Other +Comprehensive +Income +Retained +Earnings +(Accumulated +Deficit) +Total +Stockholders’ +Equity +Shares +Amount +Balance at January 1, 2005 +20,146,566 +$ +201,000 +$ +95,737,000 +$ +— +$ +— +$ +(46,841,000 +) +$ +49,097,000 +Net income +— +— +— +— +— +10,895,000 +10,895,000 +Other Comprehensive Income: +Deferred gain on settled contracts +— +— +— +— +114,000 +— +114,000 +Loss on hedging ineffectiveness +— +— +— +— +24,000 +— +24,000 +Unrealized gain on hedges +— +— +— +— +621,000 +— +621,000 +Total Comprehensive Income +11,654,000 +Issuance of Common Stock +4,000,000 +40,000 +13,960,000 +— +— +— +14,000,000 +Issuance of Common Stock through exercise of warrants +7,958,470 +80,000 +9,390,000 +— +— +— +9,470,000 +Issuance of Common Stock through exercise of options +63,167 +1,000 +105,000 +(105,000 +) +— +— +1,000 +Repayment of Notes Receivable for Stock +— +— +— +105,000 +— +— +105,000 +Balance at December 31, 2005 +32,168,203 +322,000 +119,192,000 +— +759,000 +(35,946,000 +) +84,327,000 +Net income +— +— +— +— +— +27,808,000 +27,808,000 +Other Comprehensive Income: +Deferred gain on settled contracts +— +— +— +— +(114,000 +) +— +(114,000 +) +Gain on hedging ineffectiveness +— +— +— +— +(24,000 +) +— +(24,000 +) +Reclassification adjustment on settled hedges +— +— +— +— +(621,000 +) +— +(621,000 +) +Total Comprehensive Income +27,049,000 +Stock Compensation +— +— +1,063,000 +— +— +— +1,063,000 +Issuance of Common Stock in public offering, net of related expenses of $479,000 +790,000 +8,000 +9,965,000 +— +— +— +9,973,000 +Issuance of Restricted Stock +21,981 +— +— +— +— +— +— +Issuance of Common Stock through exercise of Warrants +113,852 +1,000 +120,000 +— +— +— +121,000 +Issuance of Common Stock through exercise of Options +565,723 +6,000 +1,270,000 +— +— +— +1,276,000 +Balance at December 31, 2006 +33,659,759 +337,000 +131,610,000 +— +— +(8,138,000 +) +123,809,000 +Net income +— +— +— +— +— +37,775,000 +37,775,000 +Other Comprehensive Income: +Foreign currency translation adjustment +— +— +— +— +2,254,000 +— +2,254,000 +Total Comprehensive Income +40,029,000 +Stock Compensation +— +— +1,158,000 +— +— +— +1,158,000 +Issuance of Common Stock in public offerings, net of related expenses of $740,000 +8,547,500 +85,000 +138,173,000 +— +— +— +138,258,000 +Issuance of Restricted Stock +35,930 +— +— +— +— +— +— +Issuance of Common Stock through exercise of options +210,398 +2,000 +866,000 +— +— +— +868,000 +Balance at December 31, 2007 +42,453,587 +$ +424,000 +$ +271,807,000 +$ +— +$ +2,254,000 +$ +29,637,000 +$ +304,122,000 +See accompanying notes to consolidated financial statements. +F-5 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +Year Ended December 31, +2007 +2006 +2005 +Cash flows from operating activities: +Net income +$ +37,775,000 +$ +27,808,000 +$ +10,895,000 +Adjustments to reconcile net income to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +554,000 +596,000 +516,000 +Interest expense—preferred stock +— +— +272,000 +Depletion, depreciation and amortization +29,681,000 +12,652,000 +4,789,000 +Stock-based compensation expense +845,000 +787,000 +— +Loss from equity investments +477,000 +76,000 +— +Unrealized (gain) loss on hedge ineffectiveness +— +(24,000 +) +24,000 +Changes in operating assets and liabilities: +(Increase) decrease in accounts receivable +(2,925,000 +) +(6,609,000 +) +2,584,000 +Decrease (increase) in business interruption insurance settlement receivable +— +1,710,000 +(1,710,000 +) +Decrease (increase) in accounts receivable—related party +1,994,000 +(832,000 +) +(2,347,000 +) +Increase in prepaid expenses +(374,000 +) +(490,000 +) +(270,000 +) +Decrease in deposits +— +107,000 +— +Increase in accounts payable and accrued liabilities +2,153,000 +4,608,000 +1,074,000 +(Increase) decrease in deferred hedge gains +— +(114,000 +) +114,000 +Settlement of asset retirement obligation +(1,278,000 +) +(752,000 +) +(741,000 +) +Net cash provided by operating activities +68,902,000 +39,523,000 +15,200,000 +Cash flows from investing activities: +Additions to cash held in escrow +(121,000 +) +(105,000 +) +(57,000 +) +Additions to deposits for oil and gas properties +(3,080,000 +) +— +— +Additions to other property, plant and equipment +(457,000 +) +(495,000 +) +(467,000 +) +Additions to oil and gas properties +(220,044,000 +) +(62,403,000 +) +(31,995,000 +) +Proceeds from sale of oil and gas properties +500,000 +— +70,000 +Investment in Grizzly Oil Sands ULC +(17,316,000 +) +(8,493,000 +) +— +Investment in Tatex Thailand II, LLC +(88,000 +) +(964,000 +) +(2,502,000 +) +Investment in Windsor Bakken, LLC +(127,000 +) +(1,416,000 +) +(1,752,000 +) +Net cash used in investing activities +(240,733,000 +) +(73,876,000 +) +(36,703,000 +) +Cash flows from financing activities: +Principal payments on borrowings +(47,158,000 +) +(10,809,000 +) +(204,000 +) +Borrowings on line of credit +76,000,000 +38,300,000 +7,000,000 +Redemption of Series A, Preferred Stock +— +— +(14,292,000 +) +Proceeds from issuance of common stock, net of offering costs of $740,000 and $479,000, and exercise of stock options +139,126,000 +11,370,000 +23,576,000 +Net cash provided by financing activities +167,968,000 +38,861,000 +16,080,000 +Net increase (decrease) in cash and cash equivalents +(3,863,000 +) +4,508,000 +(5,423,000 +) +Cash and cash equivalents at beginning of period +6,627,000 +2,119,000 +7,542,000 +Cash and cash equivalents at end of period +$ +2,764,000 +$ +6,627,000 +$ +2,119,000 +Supplemental disclosure of cash flow information: +Interest payments +$ +3,341,000 +$ +1,956,000 +$ +250,000 +Income tax payments +$ +121,000 +$ +— +$ +— +Supplemental disclosure of non-cash transactions: +Investment subscription payable +$ +151,000 +$ +— +$ +688,000 +Capitalized stock based compensation +$ +313,000 +$ +276,000 +$ +— +Payment of Series A Preferred Stock dividends through issuance of Series A Preferred Stock +$ +— +$ +— +$ +272,000 +Asset retirement obligation capitalized +$ +500,000 +$ +405,000 +$ +1,382,000 +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2007, 2006 AND 2005 +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy Corporation (“Gulfport” or the “Company”) is a domestic independent oil and gas exploration, +development and production company with its principal properties located in the Louisiana Gulf Coast. Gulfport also recently acquired strategic assets in West Texas in the Permian Basin and has investments in companies operating in Canada and +Thailand. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly +owned subsidiaries, Grizzly Holdings Inc. and Jaguar Resources LLC. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas +industry located in the southwestern part of the United States. The majority of its receivables are from two purchasers of the Company’s oil and gas. Credit is extended based on evaluation of a customer’s payment history and, generally, +collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the +contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s +current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific +accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2007 and December 31, 2006. +Oil and Gas Properties +The Company +uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas +properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, as adjusted for the Company’s cash flow hedge positions and net of tax effects, discounted at 10% per year, from proven oil and gas +reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent +units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship +between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $37,278,000 and $1,459,000 at December 31, 2007 and December 31, 2006, +respectively. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of +F-7 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other +operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. +The Company +accounts for its abandonment and restoration liabilities under Statement of Financial Accounting Standards No. 143, “ Accounting for Asset Retirement Obligations ” (“SFAS No. 143”), which requires the Company to +record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed +into service. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the +capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, +estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment is provided on a straight-line basis over estimated useful lives of the related assets, which range from 7 to +30 years. +Foreign Currency +The U.S. +dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment +are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income +and are included in accumulated other comprehensive income in stockholders’ equity. +Net Income per Common Share +Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding +for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their +effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 14. +Income Taxes +Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the +future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and +liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income +during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred +tax assets will not be realized. +F-8 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Revenue Recognition +Gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property +are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. There is no such liability or asset recorded at December 31, 2007 and 2006 because the Company has no +imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month produced. +Investments—Equity Method +Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, the Company’s share of +investees’ earnings or loss is recognized in the statement of operations. +Accounting for Stock-Based Compensation +Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123(R), “ Share-Based Payment ” +(“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires share-based payments to employees, including grants of employee stock options, to be recognized as equity or liabilities at the fair +value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized as compensation expense over +the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were +required upon the Company’s adoption of SFAS No. 123(R) (see Note 10). The shares of stock issued once the options are exercised will be from authorized but unissued common stock. +Prior to adopting SFAS No. 123(R), the Company accounted for its fixed-plan employee stock options using the intrinsic-value based method prescribed +by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), and related interpretations. This method required compensation expense to be recorded on the date of grant +only if the current market price of the underlying stock exceeded the exercise price. +If the Company had elected the fair value provisions +of SFAS No. 123(R) and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, the Company’s 2005 net income and net income per share would have differed from the +amounts actually reported as shown in the following table. +Year Ended +December 31, 2005 +Net income, as reported +$ +10,895,000 +Stock-based employee compensation expense +248,000 +Net income, pro forma +$ +10,647,000 +Net income per share: +As reported: +Basic +$ +0.36 +Diluted +$ +0.34 +Pro forma: +Basic +$ +0.35 +Diluted +$ +0.33 +F-9 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Accounting for Derivative Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy swaps and collars (collectively “price swap +contracts”). The Company follows the provisions of SFAS 133, “ Accounting for Derivative Instruments and Hedging Activities.” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the +statement of financial position, measured at fair value. +The Company estimates the fair value of all derivative instruments using +established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values reported in the +consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +Accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For +derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at +least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company had no derivative +contracts at December 31, 2007 and 2006. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the +reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these +financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations and the realization of future net +operating loss carryforwards available as reductions of income tax expense. +Recent Accounting Pronouncements +The Company adopted FASB Interpretation No. 48, “ Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement +No. 109, ” as of January 1, 2007. The adoption of FIN 48 had no effect on the Company’s consolidated financial statements. The Company is subject to U.S. federal income tax as well as income tax of multiple state +jurisdictions. The Company’s 1996-2006 U.S. federal and state income tax returns remain open to examination by tax authorities. As of December 31, 2007, the Company has no unrecognized tax benefits that would have a material impact on the +effective tax rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended December 31, 2007, +there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements. +In +September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure +purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for +fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in +F-10 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +February, 2008, the FASB issued FSP No. FAS 157-2, “ Effective Date of FASB Statement No. 157” which delays the effective date of SFAS +No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date +of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. The Company is currently assessing the impact, if any, of the adoption of SFAS 157. +In February 2007, the FASB issued SFAS No. 159, “ The Fair Value Option for Financial Assets and Financial +Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial +reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses +on any items for which the Company elects the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS +No. 159 to have a material impact to its consolidated financial statements. +In December 2007, the FASB issued SFAS No. 141 +(revised 2007), “ Business Combinations ” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial +statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature +and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. The Company is currently assessing the impact, if any, the adoption of +SFAS No. 141(R) may have on any future acquisitions. +In December 2007, the FASB issued SFAS No. 160, “ Noncontrolling +Interests in Consolidated Financial Statements—an amendment of ARB No. 51. ” SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component +of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all +entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This +statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company is currently assessing the impact, if any, of the adoption of SFAS 160. +2. +ACQUISITIONS +On December 20, 2007, Gulfport +closed on the acquisition of an ownership interest in certain oil and gas properties located in the Permian Basin of West Texas, consisting of approximately 4,100 net acres with 32 gross producing wells from ExL Petroleum, LP and 12 other sellers +for a cash price of approximately $85 million. The effective date of the acquisition was November 1, 2007. The total purchase price for the assets, as adjusted at the original closing on December 20, 2007, was $85.2 million, which was +recorded as oil and natural gas properties on the accompanying consolidated balance sheet. This amount includes an adjustment for the results of operations of the assets between the November 1, 2007 effective date and the December 20, 2007 +closing date. The Company may adjust the purchase price for any post closing adjustments, scheduled 90 days from the original closing date of December 20, 2007. The results of operations from these properties were included in the 2007 +consolidated statement of operations only for the period subsequent to the closing date, in this case, for the period of December 21, 2007 through December 31, 2007. +F-11 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Gulfport funded this transaction predominately through a 4.5 million common share offering, +which closed on December 12, 2007. The Company received net proceeds of approximately $75.6 million from the equity offering, as discussed below in Note 9. The Company funded the remainder of the purchase price from borrowings on its line of +credit. +The following unaudited pro forma results for the year ended December 31, 2006 show the effect on the Company’s consolidated +results of operations as if the acquisition had occurred on January 1, 2006. The unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company’s consolidated results of operations as if the acquisition had +occurred on January 1, 2007. The pro forma results for the 2006 and 2007 periods presented are the result of combining the Company’s consolidated statements of operations with the revenues and direct operating expenses of the acquired +properties adjusted for (1) incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the acquisition, amortized on a unit-of-production basis over the remaining life of total proved reserves, as +applicable, (2) incremental accretion of discount on asset retirement obligation associated with the acquired properties, (3) estimated incremental interest expense associated with borrowings under Gulfport’s revolving credit facility +to fund the acquisition, and (4) the issuance of 4.5 million shares of common stock in the offering at January 1, 2006 and January 1, 2007 rather than December 12, 2007. The pro forma information is based upon numerous assumptions, and is not +necessarily indicative of what the Company’s actual results would have been or the Company’s future results of operations. +Unaudited +Year Ended December 31, +2007 +2006 +Total revenue +$ +121,903,000 +$ +64,458,000 +Net income +46,799,000 +29,029,000 +Net income per common share: +Basic +$ +1.14 +$ +0.78 +Diluted +$ +1.12 +$ +0.76 +3. +INSURANCE SETTLEMENT RECEIVABLE +The Company +sustained damage to both its Hackberry field located in Cameron Parish, Louisiana and its West Cote Blanche Bay (“WCBB”) field located in St. Mary Parish, Louisiana as a result of Hurricane Rita in September 2005. As of December 31, +2007, the Company had incurred costs of $14,388,000 relating to the damage to the fields and facilities. Of this amount, $250,000 represents insurance deductible amounts that were expensed to lease operating expenses in 2005. The Company received +$8,396,000 in insurance proceeds related to physical damage, of which $541,000 was received in the first quarter of 2007, which are reflected as investing activity in the consolidated statements of cash flows. Approximately $5,634,000 of costs +incurred during 2006 and the first quarter of 2007 related to equipment and facilities replacement costs which will not be reimbursed by insurance and are included in the full cost pool. Approximately $108,000 previously included in insurance +settlement receivables was not collected and was expensed in 2006. At December 31, 2007, the Company had collected all outstanding insurance receivable amounts related to physical damage. +The Company maintained business interruption insurance to cover lost production revenue in the event of shut-in production. The business interruption +insurance began 60 days after the occurrence of the insurable event, subject to a daily limit of $45,000 and had a maximum coverage of 180 days. Coverage began on November 24, 2005 for shut-in production caused by Hurricane Rita. For the years +ended December 31, 2006 and 2005, the Company recognized $3,601,000 and $1,710,000, respectively, of business interruption insurance proceeds in other income in the consolidated statements of operations. As of December 31, 2006, the +Company had received +F-12 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +proceeds of $5,311,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period of November 24, 2005 to May 1, +2006. Such recoveries are presented as operating cash flows in the consolidated statements of cash flows. All business interruption recoveries were collected in 2006. +4. +ACCOUNTS RECEIVABLE—RELATED PARTIES +Included +in the accompanying December 31, 2007 and December 31, 2006 consolidated balance sheets are amounts receivable from affiliates of the Company. These receivables represent amounts billed by the Company for general and administrative +functions, such as accounting, human resources, legal, and technical support, performed by Gulfport’s personnel on behalf of the affiliates. These services are solely administrative in nature and for entities in which the Company has no +property interests. The amounts reimbursed to the Company for these services are for the purpose of Gulfport recovering costs associated with the services and do not include the assessment of any fees or other amounts beyond the estimated costs of +performing such services. At December 31, 2007 and December 31, 2006, this receivable amount totaled $2,208,000 and $4,202,000, respectively. The Company was reimbursed $11,153,000, $12,738,000 and $6,232,000 for the years ended +December 31, 2007, 2006 and 2005, respectively, for general and administrative functions which are reflected as a reduction of general and administrative expenses in the consolidated statements of operations and include the amounts under +service contracts discussed below. +The Company is or has been a party to administrative service agreements with Caliber Development +Company, LLC, Bronco Drilling Company, Inc., Great White Energy Services LLC, Diamondback Energy Services LLC, Stampede Investments LLC and Grizzly Oil Sands ULC. Under the agreements, the Company’s services include accounting, human resources, +legal and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. The administrative service agreements have a three-year term, and upon expiration of that term the agreements will +continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative service agreements are terminable (1) by the entity at any time with at least 30 days prior written notice to the +Company and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. The Company was reimbursed the following amounts in consideration for those +services for the years ended December 31, 2007, 2006 and 2005. These amounts are reflected as a reduction of general and administrative expenses in the consolidated statements of operations. +Agreement +Effective Date +Entity +December 31, +2007 +2006 +2005 +2/9/2005 +Caliber Development Company, LLC +$ +1,249,000 +$ +431,000 +$ +147,000 +4/1/2005 +Bronco Drilling Company, Inc. * +— +49,000 +346,000 +7/22/2006 +Great White Energy Services LLC +754,000 +2,222,000 +— +9/26/2006 +Diamondback Energy Services LLC +17,000 +823,000 +294,000 +11/1/2007 +Stampede Investments LLC +123,000 +— +— +11/15/2007 +Grizzly Oil Sands ULC +953,000 +198,000 +— +* +Agreement was terminated effective April 1, 2006. +F-13 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +5. +PROPERTY AND EQUIPMENT +The major categories of +property and equipment and related accumulated depletion, depreciation and amortization as of December 31, 2007 and 2006 are as follows: +December 31, +2007 +2006 +Oil and gas properties +$ +484,487,000 +$ +250,838,000 +Office furniture and fixtures +2,922,000 +2,465,000 +Building +3,926,000 +3,926,000 +Land +260,000 +260,000 +Total property and equipment +491,595,000 +257,489,000 +Accumulated depreciation, depletion,amortization and impairment reserve +(129,496,000 +) +(99,815,000 +) +Property and equipment, net +$ +362,099,000 +$ +157,674,000 +Included in oil and gas properties at December 31, 2007 and December 31, 2006 is the +cumulative capitalization of $5,969,000 and $3,928,000, respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s +estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not +directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $2,041,000, $976,000 and $346,000 for the years ended December 31, +2007, 2006 and 2005, respectively. +At December 31, 2007, approximately $1,106,000 of oil and gas properties related to the +Company’s Belize properties are excluded from amortization as they relate to non-producing properties. In addition, approximately $34,540,000 of non-producing leasehold costs resulting from the Company’s acquisition of West Texas Permian +properties are excluded from amortization at December 31, 2007. Approximately $1,632,000 of non-producing leasehold costs related to the Company’s Southern Louisiana assets was also excluded from amortization at December 31, 2007. At +December 31, 2006, approximately $1,459,000 of non-producing leasehold costs related to the Company’s Louisiana assets was excluded from amortization. +A reconciliation of the asset retirement obligation for the years ended December 31, 2007 and 2006 is as follows: +December 31, +2007 +2006 +Asset retirement obligation, beginning of period +$ +8,858,000 +$ +8,609,000 +Liabilities incurred +500,000 +405,000 +Liabilities settled +(1,278,000 +) +(639,000 +) +Change in cash flow estimate +— +(113,000 +) +Accretion expense +554,000 +596,000 +Asset retirement obligation as of end of period +8,634,000 +8,858,000 +Less current portion +480,000 +480,000 +Asset retirement obligation, long-term +$ +8,154,000 +$ +8,378,000 +F-14 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +6. +EQUITY INVESTMENTS +Investments accounted for by +the equity method consist of the following as of December 31, 2007 and 2006: +December 31, +2007 +2006 +Investment in Tatex Thailand II, LLC +$ +3,553,000 +$ +3,465,000 +Investment in Windsor Bakken, LLC +2,468,000 +2,433,000 +Investment in Grizzly Oil Sands ULC +27,801,000 +8,465,000 +$ +33,822,000 +$ +14,363,000 +Tatex Thailand II, LLC +During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford Capital +LLC, an affiliate of Gulfport. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia +through its ownership of concessions covering three million acres which includes the Phu Horm Field. During 2007, Gulfport paid $88,000 in cash calls, bringing its total investment in Tatex (including previous investments) to $3,553,000. The loss on +equity investment related to Tatex was immaterial for the years ended December 31, 2007 and 2006. +Windsor Bakken, LLC +During 2005, the Company purchased a 20% ownership interest in Windsor Bakken, LLC (“Bakken”). The remaining interests in Bakken are owned by +entities controlled by Wexford Capital LLC, an affiliate of Gulfport. In 2005 and 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana. As of December 31, 2007 and +December 31, 2006, Gulfport’s net investment in Bakken was $2,468,000 and $2,433,000, respectively. As of December 31, 2007, Bakken had commenced drilling of some of its undeveloped acreage. The Company recognized losses on equity +investment of $92,000 and $48,000 for the years ended December 31, 2007 and 2006, respectively, which are included in other income (expense) in the consolidated statements of operations. The loss on equity investment related to Bakken was +immaterial for the year ended December 31, 2005. +Grizzly Oil Sands ULC +During the third quarter of 2006, the Company, through its wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly Oils +Sands ULC (“Grizzly”), a Canadian unlimited liability company, for approximately $8.2 million. The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LLC, an affiliate of Gulfport. During 2006 and 2007, +Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has commenced drilling of core holes for feasibility of oil production in five separate lease +blocks but has not commenced development of operations. As of December 31, 2007 and 2006, Gulfport’s net investment in Grizzly was $27,801,000 and $8,465,000, respectively. Grizzly’s functional currency is the Canadian dollar. The +Company’s investment in Grizzly was increased by $2,254,000 as a result of a currency translation gain for the year ended December 31, 2007. The Company recognized a loss on equity investment of $385,000 and $28,000 for the years ended +December 31, 2007 and 2006, respectively, which is included in other income (expense) in the consolidated statements of operations. +F-15 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +7. +OTHER ASSETS +Other assets consist of the following +as of December 31, 2007 and 2006: +December 31, +2007 +2006 +Plugging and abandonment escrow account on the WCBB properties (Note 18) +$ +3,104,000 +$ +2,983,000 +Certificates of deposit securing letter of credit +200,000 +200,000 +Deposits +3,084,000 +4,000 +$ +6,388,000 +$ +3,187,000 +8. +LONG-TERM DEBT +A break-down of long-term debt as +of December 31, 2007 and 2006 is as follows: +December 31, +2007 +2006 +Reducing credit agreement (1) +$ +59,521,000 +$ +29,848,000 +Term loan (1) +4,294,000 +5,000,000 +Building loans (2) +2,718,000 +2,843,000 +Less: current maturities of long term debt +(808,000 +) +(835,000 +) +Debt reflected as long term +$ +65,725,000 +$ +36,856,000 +Maturities of long-term debt as of December 31, 2007 are as follows: +2008 +$ +808,000 +2009 +815,000 +2010 +60,342,000 +2011 +3,131,000 +2012 +714,000 +Thereafter +723,000 +Total +$ +66,533,000 +(1) On March 11, 2005, Gulfport entered into a three-year secured reducing credit agreement +providing for a $30.0 million revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. On +November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount available under the borrowing base +limitation was increased to $30.0 million. Effective July 19, 2007, the credit facility was increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0 million. On December 20, 2007, the +amount available under the borrowing base limitation was increased to $90.0 million and the Eurodollar interest rate, which the Company can elect to use at its option, was reduced by 0.75%. In addition, the maturity date was extended from +March 31, 2009 to March 31, 2010. The Company makes quarterly interest payments on amounts borrowed under the facility. Amounts borrowed under the credit facility +F-16 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +bear interest at Bank of America Prime plus 0.25% (7.5% at December 31, 2007). The Company’s obligations under the credit facility are +collateralized by a lien on substantially all of the Company’s Louisiana and West Texas assets. The credit facility contains certain affirmative and negative covenants, including, but not limited to the following financial covenants: +(a) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest expense, plus +exploration costs deducted in determining net income under full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than +3.00 to 1.00. The Company was in compliance with all covenants at December 31, 2007. As of December 31, 2007, approximately $59.5 million was outstanding under this facility, which is included in long-term debt, net of current maturities +on the accompanying consolidated balance sheet. +On July 10, 2006, Gulfport entered into a $5 million term loan agreement with Bank of +America, N.A. related to the purchase of new gas compressor units. The loan amortizes quarterly beginning March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. Amounts +borrowed bear interest at Bank of America Prime (7.25% at December 31, 2007). The Company makes quarterly interest payments on amounts borrowed under the agreement. The Company’s obligations under the agreement are collateralized by a lien +on the compressor units. As of December 31, 2007, approximately $4.3 million was outstanding under this agreement, of which $714,000 and $3,580,000 are included in current maturities of long-term debt and long-term debt, net of current +maturities, respectively, on the accompanying consolidated balance sheet. +(2) In June 2004, the Company purchased the office building it +occupies in Oklahoma City, Oklahoma, for $3,700,000. One loan associated with this building matured in March 2006 and bore interest at the rate of 6% per annum, while the other loan matures in June 2011 and bears interest at the rate of +6.5% per annum. In addition, the building loans included a loan related to a building in Lafayette, Louisiana, purchased in 1996 to be used as the Company’s Louisiana headquarters. This loan bore interest at the rate of 5.75% per +annum. The Company paid this loan in full during the third quarter of 2007, in advance of its February 2008 maturity date. All building loans require monthly interest and principal payments and are collateralized by the respective land and +buildings . +9. +COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is +administered by the Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be granted, the number of +shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are defined as (i) all directors of the Company; +(ii) all officers of the Company; and (iii) all key employees of the Company with a customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted under the Plan, as +adjusted for changes in capitalization which have taken place since the Plan’s adoption, was 883,000. The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, +2007. No additional securities will be issued under the Plan other than upon exercise of options that are outstanding. +F-17 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 +Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine: when options shall be granted, to which eligible participants options shall be granted, the number of shares covered by such options, +the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the 2005 Plan to include (a) Incentive Stock Options, (b) Nonstatutory Stock Options, +(c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights; and to increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from +1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 2007, the Company has granted 997,269 options for the purchase of +shares of the Company’s common stock under the 2005 Plan. +During the first quarter of 2005, the Company granted a total of 677,269 +options for the purchase of shares of the Company’s common stock. The exercise price per share of these options is $3.36. During the third quarter of 2005, the Company granted a total of 120,000 options for the purchase of shares of the +Company’s common stock. The exercise price per share of these options is $9.07. In the fourth quarter 2005, the Company granted a total of 200,000 options for the purchase of shares of the Company’s common stock. The exercise price per +share of these options is $11.20. All options were issued at the market value of the Company’s stock on the date of issuance. During the second and third quarters of 2005, several non-executive employees of the Company exercised stock options +by signing full recourse notes receivable for the exercise price of those options. The notes bore interest at an annual rate of 6%. All principal amounts along with related accrued interest were paid as of December 31, 2005. +During the first quarter of 2006, the Company granted a total of 40,000 options for the purchase of shares of the Company’s common stock. The +exercise price per share of these options is $12.17. The options vest in equal monthly installments over a three-year period and expire ten years after the date of grant. During August 2006, these options were cancelled and 6,666 restricted shares +of the Company’s common stock were issued to the option holder. These shares were fully vested on the date of grant. +Restricted Stock +On May 16, 2006, the Company issued 57,000 shares of restricted common stock of the Company. These shares vest in equal monthly +installments over a three year period. During August and September 2006, 29,666 shares of restricted common stock were issued. These shares vest in equal monthly installments over a three year period. On August 17, 2006, the Company issued an +additional 6,666 shares of fully vested restricted common stock in connection with the cancellation of 40,000 options to purchase the Company’s common stock. +On April 1, 2007, the Company granted 16,389 shares of restricted common stock of the Company. These shares vest monthly over a three year period. On May 15, 2007, the Company granted 10,000 shares of +restricted common stock of the Company. These shares vest in equal monthly installments over a three year period. On August 14, 2007, the Company granted 8,000 shares of restricted common stock of the Company. These shares vest in equal monthly +installments over a three year period. On November 9, 2007, the Company granted 3,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three year period. All shares of restricted common +stock of the Company were granted under the 2005 Plan, as amended. +F-18 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Exercise of Warrants +During the first quarter of 2006, the holders of warrants issued in 2002 in conjunction with a private placement offering exercised their warrants resulting in 12,171 net shares of the Company’s common stock +issued. No proceeds were received by the Company related to the exercise of these warrants. During the third quarter of 2006, the holders of warrants exercised their warrants resulting in 101,681 net shares of the Company’s common stock issued. +The Company had 60,550 warrants outstanding at December 31, 2007 which can be converted into 203,529 shares of common stock at current exercise price of $1.19 per share. The warrants expire in 2012. +Sale of Common Stock +On February 17, 2005, the +Company entered into a stock purchase agreement with certain accredited investors providing for the issuance by the Company of an aggregate of 2,000,000 shares of the Company’s common stock at a price of $3.50 per share for gross proceeds to +the Company of $7,000,000. On February 22, 2005 the Company entered into another stock purchase agreement with certain other accredited investors providing for the issuance by the Company of an aggregate of 2,000,000 shares of the +Company’s common stock at a price of $3.50 per share for gross proceeds to the Company of $7,000,000. The transactions closed effective as of February 18, 2005 and February 23, 2005, respectively. The Company granted certain piggyback +registration rights to the investors. The Company also filed a registration statement on Form S-3 with respect to the resale of the shares of common stock purchased by the investors in the private placements, which was declared effective by the +Securities and Exchange Commission on December 31, 2005. No underwriting discounts or commissions were paid in conjunction with the issuances. +In May 2006, the Company closed a public offering of 6,050,000 shares of common stock at a price of $14.00 per share. All shares were sold by the Company’s selling shareholders and the Company did not receive any proceeds. In +connection with the offering, the Company granted the underwriters a 30-day option to purchase additional shares of the Company’s common stock to cover over-allotments, if any. On May 8, 2006, the underwriters exercised their option with +respect to 790,000 shares. The Company received net proceeds of $10,452,000 from the sale of these shares on May 10, 2006 after deducting the underwriting discount and before offering expenses. +On January 30, 2007, the Company sold 1,150,000 shares of common stock in an underwritten offering at an offering price to the public of $11.92 per +share. In connection with the offering, the Company granted the underwriter an option to purchase up to an additional 172,500 shares of common stock to cover any over-allotments, which the underwriter exercised in full on February 1, 2007. The +Company received the net proceeds of approximately $15.3 million from the sale of these shares on February 5, 2007 after deducting the underwriting discount and before offering expenses. +In May 2007, the Company sold 1,500,000 shares of common stock in an underwritten offering at an offering price to the public of $16.00 per share. In +connection with the offering, the Company granted the underwriter an option to purchase up to an additional 225,000 shares of common stock to cover any over-allotments, which the underwriter exercised in full. The Company received the net proceeds +of approximately $26.8 million from the sale of these shares on May 22, 2007 after deducting the underwriting discount and before offering expenses. +F-19 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +In July 2007, the Company sold 1,000,000 shares of common stock in an underwritten offering at an +offering price to the public of $22.00 per share. The Company received the net proceeds of approximately $21.2 million from the sale of these shares on July 25, 2007 after deducting the underwriting discount and before offering expenses. +In December 2007, the Company sold 4,500,000 shares of common stock in an underwritten offering at an offering price to the public of +$17.50 per share. The Company received the net proceeds of approximately $75.6 million from the sale of these shares on December 12, 2007 after deducting underwriting discounts and before offering expenses. In connection with the offering, a +selling stockholder granted the underwriter an option to purchase an additional 675,000 shares of common stock to cover any over-allotments, which the underwriter exercised in full. The Company did not receive any proceeds from the sale of shares of +the common stock by the selling stockholder. +Private Placement Offering +In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred +Stock, Series A, of the Company (Preferred) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per share, of the Company. Holders of the Preferred were entitled to receive dividends at the rate of 12% of the +liquidation preference per annum payable quarterly in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of Preferred at the rate of 15% of the +liquidation preference per annum. All preferred shares were redeemed in 2005. +The 2,322,962 Warrants issued have a term of ten years and +an exercise price of $1.19 per share of common stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the +warrants. The Company considered the valuation of these warrants and did not consider them materially significant. At December 31, 2007 and 2006, 60,550 warrants were outstanding. +Exercise of Warrants and Redemption of Preferred Stock +During 2005, the holders of warrants to +purchase 7,958,470 shares of the Company’s common stock exercised their warrants for an exercise price of $1.19 per share resulting in proceeds to the Company of $9.5 million. No underwriting discounts or commissions were paid in conjunction +with the issuances. The total warrants exercised in 2005 included 108,625 warrants issued to CD Holdings, LLC, in accordance with the origination of the note payable to Gulfport Funding in 2002 (and retired during 2002). +Also during 2005, the Company redeemed all of the 14,292 shares of the Company’s outstanding Series A preferred stock for an aggregate of $14.3 +million, including accrued but unpaid dividends. +10. +STOCK-BASED COMPENSATION +During the year ended +December 31, 2007 and December 31, 2006, the Company’s stock-based compensation expense was $1,158,000 and $1,063,000, respectively, of which the Company capitalized +F-20 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +$313,000 and $276,000 respectively, relating to its exploration and development efforts, which reduce basic and diluted earnings per share by $0.02 and $0.02 +for the year ended December 31, 2007 and December 31, 2006, respectively. +The fair value of each option award is estimated on +the date of grant using the Black-Scholes option valuation model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period +of time ending on the grant date. Based upon historical experience of the Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based +on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant. +No stock options were issued during the twelve months ended December 31, 2007. The following table provides information relating to stock options +granted for the years ended December 31, 2006 and 2005: +December 31, +2006 +December 31, +2005 +Expected volatility +40.9 +% +40.70 +% +Expected life in years +4.0 +4.0 +Weighted average risk free interest rate +4.0 +% +4.0 +% +The Company has not declared dividends and does not intend to do so in the foreseeable future, and +thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually +realizes will be at or near the value estimated using the Black-Scholes model. +A summary of the status of stock options and related +activity for the years ended December 31, 2007, 2006 and 2005 are presented below: +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value +Options outstanding at December 31, 2004 +627,337 +$ +2.00 +4.85 +$ +816,000 +Granted +997,269 +5.62 +Exercised +(63,167 +) +2.01 +Forfeited/expired +(2,666 +) +3.36 +Options outstanding at December 31, 2005 +1,558,773 +4.31 +7.33 +12,061,000 +Granted +40,000 +12.17 +Cancelled +(40,000 +) +12.17 +Exercised +(565,723 +) +2.26 +5,770,000 +Forfeited/expired +(25,817 +) +3.26 +Options outstanding at December 31, 2006 +967,233 +5.54 +7.76 +7,782,000 +Granted +— +— +Exercised +(210,398 +) +4.13 +2,284,000 +Forfeited/expired +(82,445 +) +3.66 +Options outstanding at December 31, 2007 +674,390 +$ +6.22 +6.97 +$ +8,098,000 +Options exercisable at December 31, 2007 +269,917 +$ +8.19 +6.59 +$ +2,717,000 +F-21 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +The 40,000 options granted in 2006 and subsequently cancelled had a fair value of $4.40 per share, or +$176,000. +Unrecognized compensation expense as of December 31, 2007 related to outstanding stock options and restricted shares was +$1,593,000. The expense is expected to be recognized over a weighted average period of 1.38 years. +The following table summarizes +information about the stock options outstanding at December 31, 2007: +Exercise +Price +Number +Outstanding +Weighted Average +Remaining Life +(in years) +Number +Exercisable +$ 2.00 +53,250 +1.85 +53,250 +$ 3.36 +345,695 +7.06 +27,333 +$ 9.07 +75,445 +7.69 +50,445 +$11.20 +200,000 +7.92 +138,889 +674,390 +269,917 +The following table summarizes restricted stock activity for the twelve months ended +December 31, 2007 and 2006: +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2005 +— +$ +— +Granted +93,332 +12.78 +Vested +(21,981 +) +12.64 +Forfeited +(1,833 +) +13.27 +Unvested shares as of December 31, 2006 +69,518 +$ +12.81 +Granted +37,389 +$ +15.66 +Vested +(35,930 +) +13.13 +Forfeited +(11,944 +) +15.24 +Unvested shares as of December 31, 2007 +59,033 +$ +13.94 +11. +DIVIDENDS ON SERIES A PREFERRED STOCK +The Company +may, at its option, accrue additional shares of Preferred Stock for the payment of dividends at a rate of 15% per annum rather than accrue cash dividends at a rate of 12% per annum during the initial two years following the closing date of +its offering which expired on March 31, 2004. Effective April 1, 2004, as a result of the amendment discussed below, the Company continued to issue additional shares of Preferred Stock for payment of dividends. As a result, the Company +issued additional shares with liquidation preference totaling $272,000 for the year ended December 31, 2005 related to the Preferred Stock Series A shares issued and outstanding during that time period. These dividends were calculated based +upon the Preferred’s $1,000 per share redemptive value. As a result of the adoption of SFAS 150, the dividends issued as additional shares for the year ended December 31, 2005 are shown as “Interest expense—preferred stock” +in the accompanying consolidated statements of operations. +F-22 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +12. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying +amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current and long-term debt are carried at cost, which approximates market value. +The fair value of the derivative instruments are computed based on the difference between the prices provided by the fixed-price contracts and forward +market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and are subject to significant volatility. +13. +INCOME TAXES +A reconciliation of the statutory +federal income tax amount to the recorded expense follows: +2007 +2006 +2005 +Income before federal income taxes +$ +37,775,000 +$ +27,808,000 +$ +10,895,000 +Expected income tax at statutory rate +13,221,000 +9,455,000 +3,704,000 +Interest expense not tax deductible +— +— +272,000 +State income taxes +2,131,000 +1,668,000 +654,000 +Other differences +528,000 +1,034,000 +(849,000 +) +Changes in valuation allowance +(15,759,000 +) +(12,157,000 +) +(3,781,000 +) +Income tax expense recorded +$ +121,000 +$ +— +$ +— +The tax effects of temporary differences and net operating loss carryforwards, which give rise to +deferred tax assets and liabilities at December 31, 2007, 2006 and 2005 are estimated as follows: +2007 +2006 +2005 +Deferred tax assets: +Net operating loss carryforward +$ +37,197,000 +$ +38,373,000 +$ +40,143,000 +SFAS 123(R) compensation expense +216,000 +319,000 +— +Investment in pass through entities +72,000 +— +— +AMT credit +64,000 +— +— +Unrealized loss on hedging activities +— +— +211,000 +Non-oil and gas property basis difference +148,000 +99,000 +144,000 +Total deferred tax assets +37,697,000 +38,791,000 +40,498,000 +Deferred tax liabilities: +Oil and gas property basis difference +27,947,000 +13,273,000 +2,821,000 +Unrealized gain on hedging activities +— +9,000 +— +Total deferred tax liabilities +27,947,000 +13,282,000 +2,821,000 +Total deferred tax asset +9,750,000 +25,509,000 +37,677,000 +Valuation allowance +(9,750,000 +) +(25,509,000 +) +(37,677,000 +) +Net deferred tax asset (liability) +$ +— +$ +— +$ +— +F-23 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +The Company has an available tax net operating loss carry forward estimated at approximately +$92,991,000 as of December 31, 2007. This carryforward will begin to expire in the year 2012. A valuation allowance has been provided at December 31, 2007, 2006, and 2005 because it is management’s belief, based upon the +Company’s past history of no taxable income, it is more likely than not the net deferred tax assets will not be realized. +The Company +had income tax expense of $121,000 during the year ended December 31, 2007 related to the payment of alternative minimum taxes due for 2006 and 2007. Although the Company has substantial net operating loss carryforwards, these cannot be used to +offset alternative minimum tax liabilities. +14. +EARNINGS PER SHARE +A reconciliation of the +components of basic and diluted net income per common share is presented in the table below: +2007 +2006 +2005 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per +Share +Basic: +Net income +$ +37,775,000 +36,774,163 +$ +1.03 +$ +27,808,000 +32,789,280 +$ +0.85 +$ +10,895,000 +30,329,682 +$ +0.36 +Effect of dilutive securities: +Stock options and awards +— +676,935 +— +1,146,794 +— +2,171,782 +Diluted: +Net income +$ +37,775,000 +37,451,098 +$ +1.01 +$ +27,808,000 +33,936,074 +$ +0.82 +$ +10,895,000 +32,501,464 +$ +0.34 +Options to purchase 200,000 shares at $11.20 per share were excluded from the calculation of +dilutive earnings per share for the year ended December 31, 2006 because they were anti-dilutive. Options to purchase 120,000 shares at $9.07 per share and 200,000 shares at $11.20 per share were excluded from the calculation of dilutive +earnings per share for the year ended December 31, 2005 because they were anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive for the year ended December 31, 2007. +15. +FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES +Oil Price Hedging +Activities +The Company established an oil price-hedging program in August 2005. The Company may seek to reduce its exposure to +unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by taking receive-fixed positions in price swap contracts. The Company pays the counterparty the excess of the oil market price over the fixed price +and will receive the excess of the fixed price over the market price as defined in each contract. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating +cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. For the years +ended December 31, 2006 and 2005, price swap contracts hedged 62% and 8.7% of the Company’s oil production, respectively. As of December 31, 2005, price swap contracts were in place to hedge 540,000 barrels (“Bbls”) of +estimated future production during 2006. There were no price swap contracts in place as of December 31, 2006 and 2007. +F-24 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +The Company’s price swap contracts were tied to commodity prices on the New York Mercantile +Exchange (“NYMEX”). The Company received the fixed price amount stated in the contract and paid to its counterparty the current market price for oil as listed on the NYMEX West Texas Index (WTI). However, due to the geographic location of +the Company’s assets and the cost of transporting oil to another market, the amount that the Company receives when it actually sells its oil differs from the index price. The difference between oil prices on the NYMEX WTI and average price +received by the Company during the month for its oil is referred to as a basis differential. +The following table summarizes the estimated +volumes, fixed prices, fixed-price sales and fair value attributable to the price swap contracts as of December 31, 2005. +Year Ending +December 31, +2005 +Contract volumes (Bbls) +540,000 +Weighted average fixed price per Bbls +$ +64.05 +Fixed-price sales +$ +34,587,000 +Fair value, of hedging (assets) +$ +621,000 +The estimates of fair value of the price swap contracts are computed based on the difference +between the prices provided by the price swap contracts and forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and +are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change. +All price swap contracts have been executed in connection with the Company’s oil price hedging program. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated +contract volume is the contract profit or loss. For price swap contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil sales in the period for which the underlying production was hedged. +For the years ended December 31, 2006 and 2005, there were net realized losses of $1,008,000 and $26,000 under price swap contracts, respectively, which are included in oil sales on the consolidated statements of operations. The losses for the +year ended December 31, 2006 included $191,000 of gains that had previously been deferred within other comprehensive income and are further discussed in the subsequent paragraph. +The Company’s oil production was shut-in during the fourth quarter of 2005 and for a portion of the first quarter of 2006 due to Hurricane +Rita’s impact on the Company’s facilities. In accordance with SFAS 133 Derivative Implementation Group Issue Number G3, certain extenuating circumstances that impact the timing of the forecasted transaction and are outside the control +or influence of the Company permit the gain or loss related to the cash flow hedge being reported in accumulated other comprehensive income until the forecasted transaction is recognized in earnings. As a result, all fourth quarter 2005 and first +quarter 2006 contract profits and losses (net gain of $114,000 and $77,000, respectively) remained in accumulated other comprehensive income at March 31, 2006. During the second quarter of 2006, production was restored and the Company +recognized gains of $47,000 in the second quarter of 2006. The remaining deferred gain of $144,000 was recognized during the third quarter of 2006. +For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge +effectiveness is measured at least quarterly based on the relative changes in fair +F-25 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in +earnings. During the year ended December 31, 2006, a gain of $24,000 was recognized into earnings resulting from hedge ineffectiveness. +In October 2006, the company terminated the remaining three months of its hedging contracts. Through the termination of these remaining contracts the Company received a total of $566,000 of proceeds during the fourth quarter of 2006 +resulting from the differential in the fixed hedged price of $64.05 per barrel and the market prices of the associated futures contracts at the date of the termination of these contracts. In accordance with SFAS 133, these amounts were recognized +into earnings during the fourth quarter of 2006, the period in which the hedged forecasted transactions occurred. The Company has no derivative contracts at December 31, 2007 and 2006. +16. +OPERATING LEASES +In October 2006, the Company +began leasing the Louisiana building that it owns to an unrelated party. The cost of the building totaled approximately $217,000 and accumulated depreciation amounted to approximately $75,000 as of December 31, 2007. The lease commenced on +October 15, 2006 and expires October 14, 2009, with equal monthly installments of $10,500. The future minimum lease payments to be received are as follows: +Fiscal year ending December 31 +2008 +126,000 +2009 +94,500 +$ +220,500 +17. +RELATED PARTY TRANSACTIONS +In the ordinary course +of business, the Company conducts business activities with certain entities affiliated with its largest stockholder. +Certain personnel of +the Company perform management and administrative services for affiliate companies. The Company is reimbursed for salaries and benefits of these individuals based on the estimated time spent on those affiliates compared to time spent on the Company. +For the years ended December 31, 2007, 2006 and 2005, expenses reimbursed to the Company under this arrangement and reflected as a reduction to general and administrative expense were $11,153,000, $12,738,000 and $6,232,000, respectively. +Windsor Energy Group (“WEG”), an affiliate of Gulfport, operated the Marquiss wells in Wyoming. At December 31, 2007 and +December 31, 2006, the Company owed WEG approximately $440,000 and $225,000, respectively, related to reimbursement for services provided. Approximately $125,000 and $1,217,000 of services provided by WEG are included in lease operating +expenses in the consolidated statements of operations for the years ended December 31, 2007 and 2006, respectively. +Athena Construction +LLC (“Athena”), an affiliate of Gulfport, performs services for the Company at its WCBB and Hackberry fields. At December 31, 2007 and December 31, 2006, the Company owed Athena approximately $1,561,000 and $1,045,000, +respectively, related to these services. Approximately $989,000 and $197,000 of services provided by Athena are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2007 and 2006, +respectively. Approximately $4,784,000 and $980,000 related to services performed by Athena are included in oil and natural gas properties at December 31, 2007 and 2006, respectively. +F-26 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Packers & Service Tools, Inc. (“Packers”), an affiliate of Gulfport, performs +services for the Company at its WCBB and Hackberry fields. At December 31, 2007 and December 31, 2006, the Company owed Packers approximately $425,000 and $354,000, respectively, related to these services. Approximately $41,000 of services +provided by Packers are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2007. Approximately $1,439,000 and $954,000 related to services performed by Packers are included in oil and +natural gas properties at December 31, 2007 and 2006, respectively. +Diamondback Completions LLC (“Completions”), an +affiliate of Gulfport, performs services for the Company at its WCBB and Hackberry fields. At December 31, 2007, the Company owed Completions approximately $241,000 related to these services. There were no amounts outstanding at +December 31, 2006. Approximately $519,000 relating to services performed by Completions in 2007 are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 2007. +Great White Towing LLC (“Towing”), an affiliate of Gulfport, performs services for the Company at its WCBB field. At December 31, 2007, +the Company owed Towing approximately $50,000 related to these services. There were no amounts outstanding at December 31, 2006. Approximately $13,000 of services performed by Towing is included in lease operating expenses in the consolidated +statements of operations for the year ended December 31, 2007. Approximately $133,000 relating to services performed during 2007 are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2007. +At December 31, 2007, the Company’s wholly owned subsidiary, Grizzly Holdings Inc., owed Grizzly Oil Sands ULC approximately +$151,000 for shares issued in 2007. +18. +COMMITMENTS +Plugging and Abandonment Funds +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed the seller’s (Chevron) +obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security +interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company can access the trust for use in plugging and abandonment charges associated with the property. As of +December 31, 2007, the plugging and abandonment trust totaled approximately $3,104,000 including interest received during 2007 of approximately $126,000. At December 31, 2007, the Company has plugged 243 wells at WCBB since it began its +plugging program in 1997. An additional ten wells were plugged in January 2008, which management believes fulfills its minimum plugging obligation through March 31, 2008. +Texaco Global Settlement +Pursuant to the terms of a global settlement between Texaco and the State +of Louisiana which includes the State Lease No. 50 portion of Gulfport’s East Hackberry Field, Gulfport was obligated to commence drilling a well or other qualifying development operation on certain non-producing acreage in the field prior +to March 1998. Because of prevailing market conditions during 1998, the Company believed it was commercially impractical to shoot seismic or commence drilling operations on the subject property. As a result, Gulfport has agreed to surrender +approximately 440 non-producing acres in this field to the State of Louisiana. At December 31, 2007, Gulfport was in the process of releasing these properties to the State of Louisiana. +F-27 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Contributions to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 15% of their total compensation through salary deferrals. Also under these plans, the Company will make a +contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals. During the years ended December 31, 2007, 2006, and 2005 Gulfport +incurred $640,000, $308,000 and $144,000, respectively, in contributions expense related to this plan. +Employment Agreement +In May 1999, Gulfport entered into an employment agreement with its Chairman of the Board. The original term of the agreement expired on May 31, +2004, but automatically renews for successive terms of one year unless Gulfport or the Chairman elects otherwise. The employment agreement calls for an annual salary of $200,000, which may be adjusted for cost of living increases. +19. +CONTINGENCIES +The Louisiana State Mineral +Board (“LSMB”) is disputing Gulfport’s royalty payments to the State of Louisiana resulting from the sale of oil under fixed price contracts. The LSMB maintains that Gulfport paid approximately $1,400,000 less in royalties under +the fixed price contracts than the royalties Gulfport would have had to pay had it sold the oil at prevailing market rates. Gulfport has denied any liability to the LSMB for underpayment of royalties and has maintained that it was entitled to enter +into the fixed price contracts with unrelated third parties and pay royalties based upon the sales proceeds from those contracts. Gulfport met with the Attorney General on several occasions and recently reached a mutual settlement. The settlement +requires Gulfport to pay $250,000, which has been accrued in accounts payable and accrued liabilities in the accompanying consolidated balance sheets and all future royalties will be paid at market price, regardless of the presence of fixed price +contracts. The settlement was approved by the LSMB during its February 2008 session. Gulfport is currently awaiting the settlement and release documentation from the LSMB to finalize the matter. +Other Litigation +In November 2006, Cudd Pressure +Control, Inc. (“Cudd”) filed a lawsuit against Gulfport and Great White Pressure Control LLC, an affiliate of the Company, among others, in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the +United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleges RICO violations and several other causes of action relating to an affiliate company’s employment of several former Cudd employees. The +defendants in the suit are Ronnie Roles, Rocky Roles, Steve Winters, Bert Ballard, Nelson Britton, Michael Fields, Steve Bickle, Great White Pressure Control LLC and Gulfport. On stipulation by the parties, the Plaintiff’s RICO claim was +dismissed without prejudice by order of the court on February 14, 2007. Co-defendant, Steve Bickle, was dismissed from the case on July 18, 2007. The case against Gulfport was stayed by order of the court on July 31, 2007. The court +further ordered co-defendant, Great White Pressure Control, to move for summary judgment by August 24, 2007. Cudd was ordered to respond by September 14, 2007. The Company filed a motion for summary judgment on October 5, 2007. +Plaintiff filed a response on November 15, 2007, and Gulfport filed a reply on November 21, 2007. Gulfport is currently awaiting the ruling from the court. +In October 2006, an accident occurred north of the Company’s production facilities in the WCBB field in southern Louisiana involving two contracted vessels that were performing work on behalf of the Company in +the field. A tugboat, the M/V Miss Megan, and two barges laden with construction materials ruptured an underwater +F-28 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +natural gas pipeline and a subsequent fire damaged the vessels. Six fatalities resulted from the accident. The following lawsuits relating to this incident +are currently pending before the courts: +• +On October 13, 2006, Athena Construction LLC (“Athena”) filed a limitation action in the United States District Court for the Eastern District of +Louisiana, alleging that all losses and damages as a result of the pipeline incident were incurred without fault on its part. Furthermore, Athena claims the benefit of the limitation of liability provided for in 42 U.S.C. § 183 and seeks an +injunction restraining filing commencement and further prosecution in any court of any lawsuit against Athena related to the pipeline incident. The limitation of liability action was subsequently transferred to the United States District Court for +the Western District of Louisiana, which is where the case remains pending. On December 20, 2006, 4-K Marine LLC, as owner of the M/V Miss Megan, and Central Boat Rentals, Inc., as operator of the M/V Miss Megan also filed a +limitation action in the Western District. On January 10, 2007, the Athena and the 4-K/Central Boat limitation proceedings were consolidated by order of the court. On May 5, 2007, Diamondback Energy Services LLC (“Diamondback”), +an affiliate of Gulfport, filed an intervener with the Court to become a party to the suit. The remaining parties filed claims on July 9, 2007, which included claims by Nicholas Aucoin, one of the initial responders to the scene of the +accident. A record hearing was held on August 13, 2007, to discuss the status of the consolidated matters and a subsequent work plan was filed on October 3, 2007. No other deadlines have been set. +• +On October 16, 2006, a lawsuit was filed in the 16th Judicial District Court for the Parish of St. Mary, Louisiana against Gulfport, Athena, and Central Boat +seeking compensatory and punitive damages for claims related to the death of the plaintiff’s husband, a crewmember on the Athena barge. The suit alleges that the husband’s death was caused by the defendants’ negligence and the +unseaworthiness of the barge to which he was assigned. Under the Blanket Time Charter between Gulfport and Central Boat, Central Boat tendered the defense and indemnification of the lawsuit to Gulfport. On November 2, 2006, all proceedings were +stayed as a result of the limitation of liability action discussed above. Settlement was reached during mediations held in December 2007. The Company is currently working to obtain settlement approvals and releases within the next 30 to 45 days. +• +On October 22, 2006, a lawsuit was filed in United States District Court for the Southern District of Texas, Galveston Division against Gulfport, Central Boat, +Diamondback, Chevron Pipeline Company, Chevron USA, Inc., and ChevronTexaco Pipeline Holdings, Inc. This lawsuit is a result of the death of three individuals. These individuals were employed by Athena and were on the Athena barge at the time of the +accident. The plaintiffs seek compensatory and punitive damages as a result of the alleged negligence of defendants. Central Boat has tendered the defense and indemnification of this lawsuit to Gulfport. On April 30, 2007, an order was filed +transferring the case to the Western District of Louisiana. A successful settlement was reached during mediations held in December 2007. The Company is currently working to obtain settlement approvals and releases within the next 30 to 45 days. +• +On February 2, 2007, a lawsuit was filed in the United States District Court for the Western District of Louisiana, Lafayette Division against Chevron Pipeline +Company, Chevron USA Inc., Chevron Texaco Pipeline Holdings, Inc., Chevron Natural Gas Services Inc., Diamondback and Gulfport. The suit was filed on behalf of April Hummel, individually and as the representative of the minor, Aleya Hummel, the +surviving child of Terry Abraham who died in the accident. On March 27, 2007, the Company filed its answer. On September 2, 2007, the case was stayed by order of the Court. A successful settlement was reached in mediations held in November +2007. We are currently working to obtain settlement approvals and releases. +• +On October 15, 2007, Brian Dumesnil filed suit in the 16th Judicial District Court for the Parish of St. Mary, Louisiana, against Gulfport, Chevron USA, +Chevron Texaco Pipeline Holdings, Chevron Natural +F-29 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Gas, Diamondback, and the Estate of Timothy Tauzin. Mr. Dumesnil was employed by Athena and was on the Athena barge at the time of the accident. He is +seeking unspecified sums as a result of the alleged negligence of defendants and injuries incurred following the October 12, 2006 accident. By mutual agreement of the parties on October 19, 2007, Gulfport is not required to respond until +receipt of further notification from the plaintiff. +On July 27, 2007, Robotti & Company, LLC filed a +putative class action lawsuit in the Court of Chancery for the State of Delaware in and for Kent County, Delaware. The lawsuit alleges a breach of fiduciary duty by Gulfport and its directors in connection with the pricing of the 2004 rights +offering. The Company received service of this matter on August 10, 2007. By mutual agreement of the parties, Gulfport was not required to respond until notified by the plaintiff, which was received on January 16, 2008. Plaintiff filed an +amended complaint on January 15, 2008, and Gulfport filed a motion to dismiss in early February 2008. +In July 2007, Michael +Tripkovich filed suit in the 16th Judicial District Court of the Parish of St. Martin, Louisiana, against 113 entities, including Gulfport, alleging his contraction of chronic myeloid leukemia (CML) was caused by exposure to various substances while +maintaining natural gas compressors over a nineteen year period. Gulfport was served on July 23, 2007 and filed a response accordingly. The suit is currently in the early phases of discovery. Gulfport has no record that Mr. Tripkovich was +ever employed by the Company. No other deadlines have been set at this time. +Due to the early stages of certain of the above litigation, +the outcome is uncertain and management cannot determine the amount of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse effect on the +Company’s financial condition or results of operations. +The Company has been named as a defendant on various other litigation +matters. The ultimate resolution of these matters is not expected to have a material adverse effect on the Company’s financial condition or results of operations for the periods presented in the consolidated financial statements. +Concentration of Credit Risk +Gulfport operates in +the oil and gas industry principally in the state of Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in +general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of +operations in the long term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal +Deposit Insurance Corporation up to $100,000. At December 31, 2007, Gulfport held cash in excess of insured limits in these banks totaling $2,440,000. +During the year ended December 31, 2007, approximately 99% of Gulfport’s oil sales and 69% and 23% of Gulfport’s natural gas sales were attributable to three purchasers: Shell, Chevron, and Hilcorp, +respectively. During the year ended December 31, 2006, Gulfport sold approximately 100% of its oil production to Shell and approximately 96% of its natural gas production to Chevron. During the year ended December 31, 2005, Gulfport sold +approximately 99% of its oil production to Shell and 88% of its natural gas production to Chevron. +F-30 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Forward Sales Contracts +The Company has entered into forward sales contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. +For the period of July 2007 through December 2007, the Company has entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In +addition, the Company has entered into forward sales contracts for the sale of 3,500 barrels of production per day for the months of January 2008 through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. +For June 2008, the Company has agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, the Company has agreements to sell 3,000 barrels of +production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, Gulfport has agreements to sell 3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before +transportation costs. For the periods of September 2008 through December 2008, the Company has entered into forward sales contracts for the sale of 3,000 barrels of production per day in each such period at weighted average daily prices of $82.20 +per barrel before transportation costs. For the period of January 2009 through December 2009, the Company entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before +transportation costs. These contracts require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal sales of production. +20. +LITIGATION TRUST ENTITY +Pursuant to the +Company’s 1997 plan of reorganization, all of Gulfport’s possible causes of action against third parties (with the exception of certain litigation related to recovery of marine and rig equipment assets and claims against Tri-Deck), +existing as of the effective date of that plan, were transferred into a “Litigation Trust” controlled by an independent party for the benefit of most of the Company’s existing unsecured creditors. The litigation related to recovery of +marine and rig equipment and the Tri-Deck claims were subsequently transferred to the Litigation Trust as described below. +The Litigation +Trust was funded by a $3,000,000 cash payment from the Company, which was made on the effective date of reorganization. Gulfport owns a 12% interest in the Litigation Trust with the other 88% being owned by the former general unsecured creditors of +Gulfport. For financial statement reporting purposes, Gulfport has not recognized the potential value of recoveries which may ultimately be obtained, if any, as a result of the actions of the Litigation Trust, treating the entire $3,000,000 payment +as a reorganization cost at the time of Gulfport’s reorganization. +On January 20, 1998, Gulfport and the Litigation Trust +entered into a Clarification Agreement whereby the rights to pursue various claims reserved by Gulfport under the plan of reorganization were assigned to the Litigation Trust. In connection with this agreement, the Litigation Trust agreed to +reimburse the Company $100,000 for legal fees Gulfport had incurred in connection with these claims. As additional consideration for the contribution of this claim to the Litigation Trust, Gulfport is entitled to 20% to 80% of the net proceeds from +these claims. +No proceeds were received from the Litigation Trust for the years ended December 31, 2007, 2006, and 2005. The Company +does not have knowledge of the amount or timing of any future proceeds. +F-31 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +21. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES +The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the southeastern United States: +Capitalized Costs Related to Oil and Gas Producing Activities +December 31, +2007 +2006 +Proven Properties +$ +447,209,000 +$ +249,379,000 +Unproven Properties +36,172,000 +1,459,000 +483,381,000 +250,838,000 +Accumulated depreciation, depletion amortization and +impairment reserve +(126,793,000 +) +(97,574,000 +) +Net capitalized costs +$ +356,588,000 +$ +153,264,000 +Equity investment in Windsor Bakken LLC +$ +4,292,000 +$ +1,995,000 +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +Year Ended December 31, +2007 +2006 +2005 +Acquisition +$ +85,247,000 +$ +— +$ +376,000 +Development of Proved +Undeveloped Properties +55,930,000 +41,770,000 +19,783,000 +Exploratory +57,668,000 +8,607,000 +4,382,000 +Recompletions +9,875,000 +4,235,000 +5,593,000 +Capitalized Asset Retirement Obligation +500,000 +405,000 +1,382,000 +Total +$ +209,220,000 +$ +55,017,000 +$ +31,516,000 +Equity investment in Windsor Bakken LLC +$ +2,297,000 +$ +1,995,000 +$ +— +F-32 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is calculated by +applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office +overhead and interest expense attributable to oil and gas production. +2007 +2006 +2005 +Revenues +$ +106,163,000 +$ +60,232,000 +$ +27,423,000 +Production costs +(29,337,000 +) +(18,036,000 +) +(11,276,000 +) +Depletion +(29,220,000 +) +(12,259,000 +) +(4,468,000 +) +47,606,000 +29,937,000 +11,679,000 +Income tax expense +Current +121,000 +— +— +Deferred +— +— +— +121,000 +— +— +Results of operations from producing activities +$ +47,485,000 +$ +29,937,000 +$ +11,679,000 +Depletion per BOE +$ +17.85 +$ +12.48 +$ +7.29 +Net earnings from equity method investment in Windsor Bakken LLC +$ +20,000 +$ +— +$ +— +F-33 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Oil and Gas Reserves (Unaudited) +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2007, 2006 and 2005 and changes in proved reserves during the last three years, assuming +continuation of economic conditions prevailing at the end of each year. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The weighted average prices at December 31, 2007 +used for reserve report purposes are $92.50 per barrel and $6.80 per MMbtu, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The weighted average prices at December 31, 2006 and +2005 used for reserve report purposes are $57.75 per barrel and $5.64 per MMbtu and $57.75 per barrel and $10.08 per MMbtu, respectively. +Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. +These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. +2007 +2006 +2005 +Oil +Gas +Oil +Gas +Oil +Gas +Proved Reserves +Beginning of the period +19,692 +20,801 +19,542 +21,781 +20,905 +23,162 +Purchases of oil and gas reserves in place +5,699 +5,587 +— +— +— +— +Revisions of prior reserve estimates +1,225 +(1,313 +) +1,020 +(303 +) +(846 +) +(806 +) +Current production +(1,501 +) +(816 +) +(870 +) +(677 +) +(517 +) +(575 +) +End of period +25,115 +24,259 +19,692 +20,801 +19,542 +21,781 +Proved developed reserves +7,116 +6,746 +4,876 +4,077 +4,308 +3,758 +Equity Investment in Windsor Bakken LLC +Net proved developed and undeveloped reserves +77 +26 +— +— +— +— +Net proved developed reserves +18 +8 +— +— +— +— +Discounted Future Net Cash Flows (Unaudited) +Estimates of future net cash flows from proven oil and gas reserves were made in accordance with SFAS No. 69, “Disclosures about Oil and Gas +Producing activities.” The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2007, 2006 and 2005 assuming continuation of economic conditions +prevailing at the end of each year. +F-34 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves +Year ended December 31, +2007 +2006 +2005 +Future cash flows +$ +2,405,458,000 +$ +1,296,729,000 +$ +1,380,555,000 +Future development and abandonment costs +(326,229,000 +) +(193,543,000 +) +(174,462,000 +) +Future production costs +(420,646,000 +) +(261,955,000 +) +(234,508,000 +) +Future production taxes +(275,977,000 +) +(155,566,000 +) +(172,282,000 +) +Future income taxes +(280,538,000 +) +(93,569,000 +) +(172,045,000 +) +Future net cash flows +1,102,068,000 +592,096,000 +627,258,000 +10% discount to reflect timing of cash flows +(433,773,000 +) +(239,448,000 +) +(257,434,000 +) +Standardized measure of discounted future net cash flows +$ +668,295,000 +$ +352,648,000 +$ +369,824,000 +Equity investment in Windsor Bakken Standardized measure of discounted cash flows +$ +1,753,000 +$ +— +$ +— +In order to develop its proved undeveloped reserves according to the drilling schedule used by the +engineers in Gulfport’s reserve report, the Company will need to spend $97,962,000, $81,634,000 and $22,849,000 during years 2008, 2009 and 2010, respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves +Year ended December 31, +2007 +2006 +2005 +Sales and transfers of oil and gas produced, net of production costs +$ +(76,826,000 +) +$ +(42,196,000 +) +$ +(16,147,000 +) +Net changes in prices, production costs, and development costs +246,657,000 +(67,273,000 +) +126,255,000 +Acquisition of oil and gas reserves in place +121,267,000 +— +— +Revisions of previous quantity estimates, less related production costs +27,970,000 +14,419,000 +(14,869,000 +) +Accretion of discount +35,265,000 +36,982,000 +30,105,000 +Net changes in income taxes +(106,145,000 +) +40,282,000 +(26,591,000 +) +Change in production rates and other +67,459,000 +610,000 +(29,976,000 +) +Total change in standardized measure of discounted future net cash flows +$ +315,647,000 +$ +(17,176,000 +) +$ +68,777,000 +F-35 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2007, 2006 AND 2005 +22. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The +following table summarizes quarterly financial data for the years ended December 31, 2007 and 2006: +2007 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +20,381,000 +$ +25,009,000 +$ +29,975,000 +$ +30,473,000 +Income from operations +7,870,000 +10,136,000 +13,245,000 +9,213,000 +Income tax expense +53,000 +— +4,000 +64,000 +Net income +7,287,000 +9,570,000 +12,701,000 +8,217,000 +Income per share: +Basic +$ +0.21 +$ +0.27 +$ +0.34 +$ +0.21 +Diluted +$ +0.21 +$ +0.26 +$ +0.33 +$ +0.21 +2006 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +4,456,000 +$ +14,360,000 +$ +23,988,000 +$ +17,586,000 +Income from operations +395,000 +6,779,000 +12,744,000 +5,937,000 +Income tax expense +— +— +— +— +Net income +2,828,000 +7,059,000 +12,517,000 +5,404,000 +Income per share: +Basic +$ +0.09 +$ +0.22 +$ +0.38 +$ +0.16 +Diluted +$ +0.08 +$ +0.21 +$ +0.37 +$ +0.16 +F-36 +Table of Contents +Index to Financial Statements +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian +(incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor +Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the +SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on +July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited +partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party +thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other +affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Registrant and Mike Liddell (incorporated by reference to Exhibit 10.5 of Amendment No. 1 +to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +E-1 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +10.5 +Credit Agreement, dated as of March 11, 2005, by and among the Company, each lender from time to time party thereto and Bank of America, N.A., as agent (incorporated by reference to Exhibit +10.9 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +10.6 +Second Amendment to Credit Agreement, dated as of July 19, 2007, between the Company and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, +filed by the Company with the SEC on July 19, 2007). +10.7 +Note dated July 19, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company with +the SEC on July 19, 2007). +10.8 +Third Amendment to Credit Agreement, dated as of December 20, 2007, between the Company, Bank of America, N.A., as a lender and administrative agent and such other lenders from time to +time party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2007). +10.9 +Note dated December 20, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company +with the SEC on December 26, 2007). +10.10 +Administrative Services Agreement, effective as of April 1, 2005, by and between Bronco Drilling Company, Inc. and Gulfport Energy Corporation (incorporated by reference from Exhibit 10.1 of +Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on August 15, 2005). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +E-2 \ No newline at end of file diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/filing_metadata.csv b/raw/filings/0000874499/2007/0001193125-08-058618/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..50c51f7bc2aa325e0ccf925201d56f1e4da13faf --- /dev/null +++ b/raw/filings/0000874499/2007/0001193125-08-058618/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2008-03-17,2007-12-31,2008-03-17T17:59:04.000Z,0001193125-08-058618,d10k.htm,FORM 10-K,1199888,0,0,https://www.sec.gov/Archives/edgar/data/874499/000119312508058618/d10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000119312508058618/,2007,2007,1 diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/item1.txt b/raw/filings/0000874499/2007/0001193125-08-058618/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..610a8eaf7b9bfc1c3e33d2b771e98d5f1879159a --- /dev/null +++ b/raw/filings/0000874499/2007/0001193125-08-058618/item1.txt @@ -0,0 +1,470 @@ +ITEM 1. DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf +Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. We have also recently acquired strategic assets in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our +interest in Grizzly Oil Sands ULC and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2007, at our WCBB field, we drilled 26 wells and recompleted 60 existing wells for a total cost of $57.9 million as of +December 31, 2007. Of our 26 new wells drilled at WCBB in 2007, 22 were completed as producing wells and four were non-productive. As of March 1, 2008, we had drilled two new wells at WCBB, both of which are producing and had recompleted +14 wells during 2008. During 2008, we intend to drill a total of eight to ten wells, recomplete 44 wells and conduct other activities at our WCBB field for an estimated aggregate cost of $21 to $23 million. In December 2007, production at WCBB was +105,922 net barrels of oil equivalent, or BOE, or an average of 3,417 BOE per day, 93% of which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil +and 5% of which was from natural gas. +In 2007, at our East Hackberry field, we drilled nine wells in Lake Calcasieu and three wells on +land and recompleted two existing wells for a total cost of $62.4 million as of December 31, 2007. Of the 12 wells drilled during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East +Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land wells, recomplete one additional well and conduct other activities in +2008 for an aggregate estimated cost of $17 to $19 million. In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil and 30% of which was from natural gas. In February 2008, our +average net daily production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas. +On +December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin for approximately $85 million, with an effective date of November 1, 2007. Through this transaction, Gulfport acquired 4,100 net acres +with production at the time of acquisition of approximately 800 net BOE a day from 32 gross wells, predominately from the Wolfcamp formation. Existing production is approximately 64% oil, 23% natural gas liquids and 13% natural gas. At +December 31, 2007, Pinnacle Energy Services LLC, an independent petroleum engineering firm, estimated that proved reserves net to our interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved +developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally +characterized as long-lived, with predictable production profiles. We expect that approximately 17 to 22 net wells will be drilled on this acreage in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average +gross completed well cost of $1.7 million. +During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings +Inc., purchased a 24.9999% interest in Grizzly Oils Sands ULC, or Grizzly, a Canadian unlimited liability company. The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford, an affiliate of ours. During +2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. As of March 1, 2008, Grizzly had approximately 511,000 acres under lease. Grizzly +drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks. Future plans currently include acquiring additional leases, drilling approximately 55 to 60 additional core holes and a seismic +program during the 2007/2008 winter drilling +2 +Table of Contents +Index to Financial Statements +season and initial planning for the construction of a 10,000 barrel per day steam assisted gravity drainage facility, or SAGD, that could lead to initial +production in 2011. Permitting for this initial SAGD facility is expected to commence later in 2008. +During 2005, we purchased a 23.5% +ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an +international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +As of December 31, 2007, we had 29.2 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future +net revenues, discounted at 10%, or PV-10, of approximately $821million and associated standardized measure of discounted future net cash flows of approximately $668.3 million. See Item 2. “Properties—Proved Oil and Natural Gas +Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Principal Oil and Natural Gas Properties +The following table presents certain information as of +December 31, 2007 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast and in the Permian Basin in West Texas. +Proved Reserves +Field +NRI/WI (1) +Producing +Wells (2) +Non-Producing +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay (4) +78.665/100 +111 +111 +166 +166 +5,668 +5,668 +15,891 +15,135 +17,783 +E. Hackberry (5) +79.424/100 +12 +12 +82 +82 +3,265 +3,265 +2,776 +4,119 +4,582 +W. Hackberry +87.5/100 +3 +3 +24 +24 +592 +592 +— +158 +158 +Permian +37.5/50 +32 +16 +— +— +2,560 +1,280 +5,587 +5,699 +6,630 +Overrides/Royalty Non-operated +Various +18 +0.8 +16 +0.7 +4,956 +586 +5 +4 +5 +Total +176 +142.8 +288 +272.7 +17,041 +11,391 +24,259 +25,115 +29,158 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes 30 gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 87% of our acreage is developed acreage and has been perpetuated by production. We have 1,100 and +2,820 net undeveloped acres in the East Hackberry field and the Permian Basin, respectively. +(4) +We have a 100% working interest (78.665% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a +40.40% non-operated working interest (29.95% NRI). +(5) +Does not include an additional 3,233 acres under an option we exercised which will increase our acreage position significantly to approximately 7,598 acres. State approval was +obtained on February 27, 2008, and we are working with the state to finalize the leases. +3 +Table of Contents +Index to Financial Statements +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water +depths averaging eight to ten feet. We own a 100% working interest (78.665% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated +working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this +field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells +were drilled in the field. Of the 900 wells drilled as of December 31, 2007, 809 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in +1997 through December 31, 2007, we drilled 120 new wells, 14 of which were non-productive, for an 88% success rate. As of December 31, 2007, estimated field cumulative gross production was 187.4 MMBOE and 235.5 billion cubic feet, or Bcf, +of gas. Of the 900 wells drilled in WCBB as of December 31, 2007, 81 were producing, 166 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 618 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an +undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The +reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome +structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The +compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) +was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor +discrete intervals have been tested. Within the 900 wellbores that had been drilled in the field as of December 31, 2007, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a +strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB +are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, +and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of +crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the +mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an +4 +Table of Contents +Index to Financial Statements +effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position +within a particular zone. Our inventory of prospects includes 111 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019. +Facilities +We own and operate a production facility at WCBB that includes four production tank +batteries, six natural gas compressors, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2007, we drilled 26 wells and recompleted 60 existing wells at WCBB. Of these 26 new wells, 22 were completed as producers, and four were +non-productive. As of March 1, 2008, we had drilled two new wells, both of which are producing, and had recompleted 14 wells during 2008. Of the 22 wells completed in 2007, ten were considered deep wells. The 22 productive wells, with total +depths ranging from 6,107 to 10,464 feet, have approximately 2,716 feet of aggregate apparent net pay. The other four wells were non-productive, including one exploratory well that was drilled to satisfy our drilling commitment with the State of +Louisiana to hold the non-productive portions of WCBB. We anticipate drilling a total of eight to ten wells and recompleting 44 wells at WCBB during 2008. +Production Status +In December 2007, production at WCBB was 105,922 net BOE, or an average of 3,417 BOE per day, 93% of +which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil and 5% of which was from natural gas. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. +We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 4,365 acres, including the Erwin Heirs Block, +which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. In addition, we exercised our option to acquire an additional 3,233 acres at the Hackberry field. The option will +increase our acreage position significantly to approximately 7,598 acres. State approval was obtained on February 27, 2008, and we are working with the state to finalize the leases. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now +Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated +cumulative oil and condensate production through 2007 was over 263,000 barrels of oil and 330 Bcf of casinghead gas production. There have been a total of 182 wells drilled on our portion of the field. As of December 31, 2007, 12 wells had +daily production, 82 were shut-in and two had been converted to salt water disposal wells. The remaining 86 wells had been plugged and abandoned. +5 +Table of Contents +Index to Financial Statements +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern +end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps +for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East +Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 +barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry. Given that drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken +without the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our probability of drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2007 at East +Hackberry, we drilled nine wells in Lake Calcasieu and three wells on land and recompleted two existing wells. Of the 12 wells drilling during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East +Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land wells and recomplete one additional well at East Hackberry during +2008. Drilling activity in this field during 2008 will target measured depths of up to 13,000 feet using directional drilling techniques. +Production +Status +In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil +and 30% of which was from natural gas. In February 2008, our average net daily production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of +Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States +Department of Energy’s Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between +1938 and 1988. The estimated cumulative oil and condensate production through 2007 was 227 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and +one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. +6 +Table of Contents +Index to Financial Statements +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and +Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In December 2007, net production at West Hackberry was 641 BOE, or 21 BOE per day. +In February 2008, our average net daily production at West Hackberry was 21 BOE. +Facilities +We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West +Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on +December 20, 2007, effective date as of November 1, 2007, from ExL Petroleum, LP and certain other sellers. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major +producing basins in the United States. The terrain in the Permian Bain is semi-arid mesquite-mixed grassland steppe. +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a +long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was +not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 +feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry decided to drill completely +through the Wolfcamp section as Devonian wells. Henry mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry’s Wolfcamp team formed +their own private company, ExL Petroleum, and began replicating Henry’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled +us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. Currently, we hold interests in thirty-two gross producing wells. +Geology +The Wolfcamp/Spraberry play, which we refer +to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 +feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +7 +Table of Contents +Index to Financial Statements +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the +Spraberry section, consisting of approximately 64% oil, 23% natural gas liquids, and 13% natural gas. Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2007, proved reserves net to our +interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre +units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. Wells to be drilled will be approximately 10,200 feet at an estimated average +gross completed well cost of $1.7 million. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is expected to average gross 146,000 BOE per well with an average net revenue interest in the field of +approximately 75%. We have a 50% working interest and approximately 37.5% net revenue interest in the field. +Production Status +At the date of acquisition, there was production of approximately 800 net BOE a day from 32 gross, producing wells. During February 2008, average net +production to Gulfport was 531 BOE a day. +Facilities +There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +We have identified 178 +gross future development drilling locations. We expect approximately 17 to 22 net wells to be drilled in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average gross completed well cost of $1.7 million. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +2 +5 +Bayou Pigeon +Iberia +6.250 +% +0 +% +5 +5 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +6 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +1 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, +or Tatex, at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During the year ended December 31, 2007, we paid $88,000 in cash calls, +bringing our total investment in Tatex (including previous investments) to $3,553,000. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were +achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. Current net production is approximately 100 Mcf per day. Hess Corporation operates the field +with a +8 +Table of Contents +Index to Financial Statements +35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through +Tatex as a member of APICO) in the Phu Horm field is 0.7%. Proved reserves from the Phu Horm field, net to our interest, are 3.5 BCF of gas and 10,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and +Tatex’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +Williston Basin . During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2005 and 2006, Bakken acquired leases on +undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana. At December 31, 2007, our net investment in Bakken was $2,468,000. We are currently participating in the drilling of nine wells and have interests in +eight producing wells with an average working interest of 1.55%. +Marquiss Field . In February 2005, but effective as of +December 1, 2004, we acquired our interest in the Marquiss field, an approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming, for $375,000. As of December 31, 2006, the Marquiss field included a total of 162 wells, +all of which were shut-in as a result of the economic status of the field as a result of a decline in natural gas prices for this field. The wells (when on line) produced from multiple horizons with additional upside potential from deeper coals and +operational efficiencies. Our interest in the Marquiss field was sold in February 2007 for $500,000. +Grizzly Oil Sands . During the +third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired +leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $27,801,000 at +December 31, 2007. Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks using up to four different rigs. Future plans currently include acquiring additional leases, +drilling approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling season and initial planning for the construction of a 10,000 barrel per day SAGD facility that could lead to initial production in 2011. +Gross capital expenditures for such a production facility are currently estimated to be approximately $325 million. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of +these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned +to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government +regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of +our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of +oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to +Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production is being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade month +average P+ value, plus or minus the Platt’s WII/LLS differential less $3.70 per barrel for transportation. During 2007, we sold 99% of our oil production to Shell and 69% of our natural gas production to Chevron and 23% of our natural gas +production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96% +9 +Table of Contents +Index to Financial Statements +of our natural gas production to Chevron. During 2005, we sold 99% of our oil production to Shell and 88% of our natural gas production to Chevron. There can +be no assurance, however, that we will continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under +some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future +prices. +To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales contracts for the sale of +3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, we entered into forward sales contracts for the +sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell 3,500 barrels of production per day for the months of January +through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel +before transportation costs. For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell +3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,000 +barrels of production per day in each such period at weighted average daily prices of $82.20 per barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of our estimated production for January +through December 2008. For the period of January through December 2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before transportation costs. Such arrangements may +expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These contracts require physical delivery of production quantities and are exempted from the provisions +of SFAS 133 as normal sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry +is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, +affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast +and West Texas. These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations +governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas +exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous +governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations to implement and enforce such laws, which often require difficult +10 +Table of Contents +Index to Financial Statements +and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to +comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and +production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or +former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The strict liability nature of such laws and regulations could impose liability upon us regardless +of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations +and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and we have not experienced any material adverse +effect from compliance with these environmental requirements; this trend, however, may not continue in the future. +Waste Handling . +The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the +generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more +stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that +are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes +or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous +wastes.” +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We +believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our +operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural +gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Comprehensive Environmental +Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or +legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner +or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several +liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners +and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials, that, if released, would be subject to +CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous +substances” have been deposited. +11 +Table of Contents +Index to Financial Statements +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the +Clean Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state +waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These proscriptions also prohibit certain activity in wetlands +unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be +associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all permits required under the Clean Water Act. +Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. +Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The +EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our +facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state +regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial +compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas +projects. +Operational Hazards and Insurance +Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or +destruction of oil and natural gas wells, production facilities or other property, or injury to persons. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or +gases that could expose us to substantial liability due to pollution and other environmental damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. +The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. +Headquarters +and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate +headquarters. We lease a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately +6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for +its use. +Employees +At +December 31, 2007, we had 70 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the +estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2007 and 2006, expenses reimbursed +to us under these arrangements were +12 +Table of Contents +Index to Financial Statements +$11,153,000 and $12,738,000, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company +provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. +Available Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished +pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, +or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be +considered part of this report or any other filing that we make with the SEC. \ No newline at end of file diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/item13.txt b/raw/filings/0000874499/2007/0001193125-08-058618/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..aa968c4973dd4706435458071efed78647245d00 --- /dev/null +++ b/raw/filings/0000874499/2007/0001193125-08-058618/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive Information Statement, which will be filed with the Securities and Exchange +Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/item9a.txt b/raw/filings/0000874499/2007/0001193125-08-058618/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e33207ef0c9916f657c3bac8e160b2089cddf498 --- /dev/null +++ b/raw/filings/0000874499/2007/0001193125-08-058618/item9a.txt @@ -0,0 +1,65 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of +Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to +be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and +procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding +required disclosures. +As of December 31, 2007, an evaluation was performed under the supervision and with the participation of +management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of +1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2007, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that +occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation +of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the +Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the +preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal +control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted +an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its +evaluation under the framework in Internal Control—Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was +effective as of December 31, 2007. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial +statements for the year ended December 31, 2007 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2007, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +48 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited internal control over +financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over +financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we +plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial +reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the +circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a +process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s +internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the +company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company +are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the +company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial +reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance +with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over +financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We +have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the related consolidated statements of +operations, stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 17, 2008 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 17, 2008 \ No newline at end of file diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/rp_note.txt b/raw/filings/0000874499/2007/0001193125-08-058618/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2007/0001193125-08-058618/rpt_disclosure.txt b/raw/filings/0000874499/2007/0001193125-08-058618/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..52aa67776c03810efe44f458684bb91b3dfabc78 --- /dev/null +++ b/raw/filings/0000874499/2007/0001193125-08-058618/rpt_disclosure.txt @@ -0,0 +1,90 @@ +Certain Relationships and Related Transactions +Administrative Services Agreements +We are a party to administrative service agreements with Diamondback Energy Services LLC, +which we refer to as Diamondback, Great White Energy Services LLC, which we refer to as Great White, Caliber Development Company, LLC, which we refer to as Caliber, Stampede Investments LLC, which we refer to as Stampede, and Grizzly Oil Sands ULC, +which we refer to as Grizzly, which agreements were entered into effective as of September 29, 2006, July 26, 2006, February 9, 2005, November 1, 2007 and November 15, 2007, respectively. Under these +agreements, our services include accounting, human resources, legal and technical support. The services provided to these entities and the fees for such services can be amended by mutual agreement of the parties to these agreements. Each +administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at least 30 days prior written notice. Each +administrative services agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within +30 days of receipt of written notice of such breach. Each of Diamondback, Great White, Caliber, Stampede and Grizzly reimbursed us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time +our employees spent performing services for such entity. We were reimbursed approximately $17,000, $754,000, $1,249,000, $123,000 and $953,000 by Diamondback, Great White, Caliber, Stampede and Grizzly, respectively, for services provided under +these agreements during the year ended December 31, 2007. Each of Diamondback, Great White, Caliber, Stampede and Grizzly is controlled by Wexford Capital LLC. Charles Davidson, who beneficial owned approximately 35.7% of our outstanding common +stock as of April 23, 2008, is the Chairman and Chief Investment Officer of Wexford Capital LLC. Our Chairman of the Board, Mike Liddell, is also the Chairman of the Board of Diamondback Energy Services, Inc., a subsidiary of Diamondback. Two +of our directors, Scott Streller and Donald L. Dillingham, are also director nominees of Diamondback Energy Services, Inc. +We provide office space, +furniture, telecommunications and computer and other information technology support to certain employees of Windsor Energy Resources LLC, or Windsor. Windsor has agreed to reimburse us for such services based on the number of employees we office and +nature of services provided by us to such employees, which can vary from time to time. Windsor is controlled by Wexford Capital LLC. +Two of our petroleum +engineers are providing services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to Tatex Thailand II, LLC, or Tatex II, and Tatex Thailand III LLC, or Tatex III. +Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities, which can vary from time to time. Tatex II and Tatex III +are controlled by Wexford Capital LLC. +We provide certain general and administrative services to Floran Technologies LLC, or Floran. We are reimbursed for +our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing such services. For the year ended December 31, 2007, we were reimbursed approximately $61,000 by +Floran and were owed an additional $31,000 for such services at that date. +Services Provided to Us by Our Affiliates +We contract with Athena Construction, L.L.C. to provide barge services in our West +Cote Blanche Bay, or WCBB, and Hackberry fields located along the Louisiana Gulf Coast. In January 31, 2006, Athena was acquired by an entity controlled by Wexford Capital LLC. For the year ended December 31, 2007, we paid Athena +$5,902,000 and owed an additional $1,561,000 for such services at that date. +26 +Table of Contents +In February 2005, but effective as of December 1, 2004, we acquired an interest in the Marquiss field, an +approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming. Windsor Energy Group, LLC, an entity controlled by Wexford Capital LLC, was the operator of this field. For the year ended December 31, 2007, we paid Windsor Energy +Group $363,000 and owed an additional $440,000 related to reimbursement for services provided. Our interest in the Marquiss field was sold in February 2007. +Packers & Service Tools, Inc., which we refer to as Packers, performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2007, we paid Packers $1,406,000 and owed an additional $425,000 related +to these services at that date. Packers is an entity controlled by Wexford Capital LLC. +Diamondback Completions LLC, which we refer to as Completions, +performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2007, we paid Completions $278,000 and owed an additional $241,000 related to these services at that date. Completions is an entity controlled by Wexford +Capital LLC. +Great White Towing LLC, which we refer to as Towing, performs services for us at our WCBB field. For the year ended December 31, 2007, +we paid Towing $95,000 and owed an additional $50,000 related to these services at that date. Towing is an entity controlled by Wexford Capital LLC. +Effective March 1, 2008, Windsor provides tax planning, preparation of supporting tax schedules and consultation services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of +the parties. Windsor is controlled by Wexford Capital LLC. +Caliber provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. +For the year ended December 31, 2007, we paid Caliber $14,000 and owed an additional $3,000 related to these services at that date. Caliber is an entity controlled by Wexford Capital LLC. +Our Investments in Affiliates and Related Agreements +During 2005, we purchased a 23.5% ownership interest in Tatex II at a +cost of $2,400,000. The remaining interests in Tatex II are owned by other entities controlled by Wexford Capital LLC. Tatex II, a privately-owned entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil +and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During 2007, we paid $88,000 in cash calls in respect of our +investment in Tatex II. +During 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. Approximately 68.7% of the remaining +interests in Tatex III are owned by other entities and individuals affiliated with Wexford Capital LLC. +During 2005, we purchased a 20% ownership interest +in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by other entities controlled by Wexford Capital LLC. In 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and +eastern Montana, which we refer to as the contract area. During 2007, we paid $127,000 in respect of our interest in Bakken. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our +20% interest in Bakken. +In addition, effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor Dakota +LLC, or Windsor Dakota, to jointly acquire oil and gas leases on certain lands located in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each party must +offer the other party the right to participate in such acquisition in proportion to its participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain exceptions, to share +third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy Group, L.L.C., as the +operator, also entered into the exploration agreement, effective as of January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and +27 +Table of Contents +Windsor Energy Group, L.L.C. agreed to act as the operator under the terms of a joint operating agreement, effective as of March 4, 2008. In the event +Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport as the operator. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with +respect to the contract area as provided in the joint operating agreement. +During the third quarter of 2006, we purchased, through our wholly owned +subsidiary Grizzly Holdings, Inc., a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for approximately $8,200,000. The remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LLC. During 2006, +Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands projects. Grizzly has commenced drilling of core holes for feasibility of oil production in three +separate lease blocks but has not commenced development of operations. As of December 31, 2007, our net investment in Grizzly was $27,801,000. +At +December 31, 2007, our wholly owned subsidiary, Grizzly Holdings Inc., owed Grizzly approximately $151,000 for shares issued in 2007. +Option and Purchase Agreement and Related Agreements +On November 30, 2007, we entered into an option agreement with +Windsor Permian LLC, an entity controlled by Wexford Capital LLC, which we refer to as Windsor Permian. Under the option agreement, we were granted the right to participate on a 50/50 basis with Windsor Permian in the acquisition of certain +strategic assets in Upton County, Texas in the Permian Basin. We paid Windsor Permian $8.5 million for the option, which amount was applied to our portion of the purchase price for the acquisition. On December 12, 2007, we exercised the option +and on December 18, 2007, the purchase agreement was amended to, among other things, add Gulfport as a buyer under the purchase agreement. On December 20, 2007, the acquisition was closed, effective as of November 1, 2007. We and +Windsor Permian also agreed to share equally all third-party costs and expenses incurred by each of us in connection with the transaction, none of which had been paid as of December 31, 2007. +In addition, effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly acquire oil and gas leases in the +Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion +to their respective participating interests and pay certain other fees as provided in the agreement. On March 20, 2008, in connection with this agreement, we received a six-month option to acquire a direct, undivided interest of up to 25% in +Windsor Permian’s oil and gas interests acquired on February 29, 2008 in Midland County, Texas. The option price is the sum of (i) the option percentage of the acquisition consideration paid by Windsor Permian to a third party in +connection with the acquisitions of these assets, subject to certain exceptions, (ii) a fee equal to 1% of our purchase price, (iii) the option percentage of the sum of all third-party costs and expenses incurred by Windsor Permian in +connection with the acquisition of these assets, subject to certain exceptions, (iv) the option percentage of all capital costs and lease operating expenses incurred subsequent to Windsor Permian’s acquisition of these assets and prior to +the date of the option exercise by Gulfport, subject to certain exceptions, and (v) interest, at 8% per annum, on the amounts set forth in items (i), (iii) and (iv) calculated from the time of accrual to the closing date of the +option. +In connection with the Area of Mutual Interest Agreement, we, Windsor Permian and Windsor Energy Group, L.L.C., as the operator, entered into the +joint development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy Group, L.L.C. agreed to act as the +operator under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either party has greater than a 50% interest in a prospect, as defined in the development agreement, the majority party may designate the +operator of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. +28 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/filing.txt b/raw/filings/0000874499/2008/0001193125-09-055183/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..41a08def7f8cd59ca9a6b21346b311b77801b3c9 --- /dev/null +++ b/raw/filings/0000874499/2008/0001193125-09-055183/filing.txt @@ -0,0 +1,5395 @@ +10-K +1 +d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +x +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2008 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission +File Number: 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant as Specified in Its Charter) +Delaware +73-1521290 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip code) +(405) 848-8807 +(Registrant’s Telephone Number, Including Area Code) +Securities registered pursuant to +Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the +Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 +of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x +Indicate by check mark whether the +registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and +(2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained +herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a +non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): +Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange +Act). Yes ¨ No x +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2008, based on the closing price of the common stock on the NASDAQ Global +Select Market on June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter ($16.47 per share) was $701,877,647. +As of March 1, 2009, 42,647,034 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy Corporation’s Proxy Statement for the 2009 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. +Table of Contents +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +DESCRIPTION OF BUSINESS +2 +ITEM 1A. +RISK FACTORS +14 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +23 +ITEM 2. +PROPERTIES +24 +ITEM 3. +LEGAL PROCEEDINGS +28 +ITEM 4. +SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +28 +PART II +29 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY +SECURITIES +29 +ITEM 6. +SELECTED FINANCIAL DATA +30 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +32 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +46 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +47 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +47 +ITEM 9A. +CONTROLS AND PROCEDURES +48 +ITEM 9B. +OTHER INFORMATION +49 +PART III +50 +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +50 +ITEM 11. +EXECUTIVE COMPENSATION +50 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +50 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +50 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +50 +PART IV +51 +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +51 +Signatures +S-1 +Index to Consolidated Financial Statements +F-1 +Exhibit Index +E-1 +i +Table of Contents +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of +1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These +statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the +forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” +“anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, +other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and +gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and +operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our +best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that +are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future +performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements +due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements speak only +as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all +forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +PART I +ITEM 1. +DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf +Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and +in the Bakken Shale, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2008, at our WCBB field, we drilled eight wells and recompleted 48 existing wells for a total cost of approximately $31.0 million as of +December 31, 2008. Of our eight new wells drilled at WCBB in 2008, seven were completed as producing wells and one was non-productive. During 2009, we currently anticipate drilling four wells and recompleting 20 wells at our WCBB field for an +estimated aggregate cost of $7.5 to $8.5 million. In December 2008, production at WCBB was 109,292 net barrels of oil equivalent, or BOE, or an average of 3,526 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From +January 1, 2009 through March 9, 2009, our average net daily production at WCBB was 3,037 BOE, 99% of which was from oil and 1% of which was from natural gas. +In 2008, at our East Hackberry field, we drilled five wells and recompleted seven existing wells for a total cost of approximately $18.0 million as of December 31, 2008. All five wells drilled during 2008 were +completed as producing wells. During 2009, we currently anticipate drilling four land wells and recompleting three wells for an aggregate estimated cost of $4.5 to $5.5 million. In December 2008, net production at East Hackberry was 12,243 BOE, or +an average of 395 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2009 through March 9, 2009, our average net daily production at East Hackberry was 439 BOE, 95% of which was from oil and 5% of +which was from natural gas. +On December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin +for approximately $83.8 million, with an effective date of November 1, 2007. Through this transaction, we acquired 4,100 net acres with production at the time of acquisition of approximately 800 net BOE a day from 32 gross wells, predominately +from the Wolfcamp formation. In 2008, 31 gross (15.5 net) wells were drilled on this acreage, including one gross well spud in 2007 and completed in 2008 and one Henry Petroleum operated well for a total cost of approximately $33.9 million. As of +March 1, 2009, 29 of the 31 wells had been completed and the other two wells were awaiting completion. We currently anticipate drilling three gross (1.5 net) wells on this acreage in 2009 for an estimated average completed gross well cost of +$1.34 million. In December 2008, net production from our Permian acreage was 26,943 BOE, or an average of 869 BOE per day, 84% of which was from oil and natural gas liquids and 16% of which was from natural gas. From January 1, 2009 through +March 9, 2009, our average daily net production from our Permian acreage was 725 BOE per day, 83% of which was from oil and natural gas liquids and 17% of which was from natural gas. +During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining +interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development +projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9 million at December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate +of 117 core holes, tested five separate lease blocks using up to four different rigs and undertook a seismic program. Grizzly’s 2009 plans currently include drilling 15 additional core holes, which were completed in the first quarter of 2009 +for approximately $4.3 million. +2 +Table of Contents +During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining +interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base +located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +During +2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2006, Bakken acquired leases for undeveloped acreage in the Williston Basin area of +western North Dakota and eastern Montana. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. As of December 31, 2008, we had participated, or +committed to participate, in 53 gross wells in the Williston Basin with an average working interest of 2.52%. In December 2008, net production from this acreage was 8,692 BOE, or an average of 280 BOE per day. From January 1, 2009 through +March 9, 2009, our average net daily production from this acreage was 271 BOE and was 100% oil. Plans for 2009 currently include drilling approximately 0.5 net wells for an estimated net cost of $2.5 million. +As of December 31, 2008, we had 25.5 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future +net revenues, discounted at 10%, or PV-10, of approximately $126.2 million and associated standardized measure of discounted future net cash flows of approximately $126.2 million. See Item 2. “Properties—Proved Oil and Natural Gas +Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Principal Oil and Natural Gas Properties +The following table presents certain information as of +December 31, 2008 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas and in the Williston Basin. +Proved Reserves +Field +NRI/WI (1) +Producing +Wells (2) +Non-Producing +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay (4) +80.335/100 +107 +107 +158 +158 +5,668 +5,668 +2,009 +11,391 +13,400 +E. Hackberry (5) +79.424/100 +18 +18 +80 +80 +3,291 +3,291 +282 +2,441 +2,723 +W. Hackberry +87.5/100 +3 +3 +24 +24 +592 +592 +— +132 +132 +Permian +38.075/49.48 +61 +30.5 +— +— +8,075 +4,150 +1,367 +7,028 +8,395 +Bakken (6) +2.285/2.181 +38 +0.8 +— +— +8,153 +891 +47 +776 +823 +Overrides/Royalty Non-operated +Various +9 +.5 +17 +.8 +4,956 +586 +1 +3 +4 +Total +236 +159.8 +279 +262.8 +30,735 +15,178 +3,706 +21,771 +25,477 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes 30 gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 42% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.335% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a +40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +3 +Table of Contents +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water +depths averaging eight to ten feet. We own a 100% working interest (80.335% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated +working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this +field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells +were drilled in the field. Of the 908 wells drilled as of December 31, 2008, 816 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in +1997 through December 31, 2008, we drilled 128 new wells, 15 of which were non-productive, for an 88% success rate. As of December 31, 2008, estimated field cumulative gross production was 188.6 MMBOE and 235.9 billion cubic feet, or Bcf, +of gas. Of the 908 wells drilled in WCBB as of December 31, 2008, 77 were producing, 158 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 638 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an +undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The +reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome +structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The +compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) +was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor +discrete intervals have been tested. Within the 908 wellbores that had been drilled in the field as of December 31, 2008, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a +strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB +are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, +and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of +crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the +mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to +wells +4 +Table of Contents +that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2008 included 81 PUD wells. +The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, six natural gas compressors, a dehydration unit and a salt +water disposal system. +Recent and Future Activity +In 2008, we drilled eight wells and recompleted 48 existing wells at WCBB. Of these eight new wells, seven were completed as producers, and one was non-productive. As of March 1, 2009, we had recompleted seven +wells during 2009. Of the eight wells drilled in 2008, all eight were considered deep wells. The seven productive wells, with total depths ranging from 6,900 to 9,600 feet, have approximately 824 feet of aggregate apparent net pay. We currently +anticipate drilling four wells and recompleting 20 wells at WCBB during 2009. +Production Status +In December 2008, production at WCBB was 109,292 net BOE, or an average of 3,526 BOE per day, 98% of which was from oil and 2% of which was from natural +gas. From January 1, 2009 through March 9, 2009, our average net daily production at WCBB was 3,037 BOE, 99% of which was from oil and 1% of which was from natural gas. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. +We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 7,233 acres, including the Erwin Heirs Block, +which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. +Area History and +Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly +survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through +2008 was over 409,701 barrels of oil and 330 Bcf of casinghead gas production. A total of 187 wells have been drilled on our portion of the field. As of December 31, 2008, 18 wells had daily production, 80 were shut-in and two had been +converted to salt water disposal wells. The remaining 86 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field +entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault +blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +5 +Table of Contents +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the +ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey +at East Hackberry. Given that drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken without the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our +probability of drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2008 at East Hackberry, we drilled four land wells and one well on water and recompleted seven existing wells. All of the +five wells drilled during 2008 were completed as producing wells. As of March 1, 2009, we had recompleted three wells during 2009. We currently intend to drill four land wells and have recompleted three wells at East Hackberry during 2009. +Production Status +In December 2008, +net production at East Hackberry was 12,243 BOE, or an average of 395 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2009 through March 9, 2009, our average net daily production at East +Hackberry was 439 BOE, 95% of which was from oil and 5% of which was from natural gas. Production has increased since year end as a result of mechanical well enhancements. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of +Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States +Department of Energy’s Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between +1938 and 1988. The estimated cumulative oil and condensate production through 2008 was 242 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and +one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West +Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production +of almost 700 MBOE. +Production Status +In December 2008, net production at West Hackberry was 763 BOE, or 25 BOE per day. From January 1, 2009 through March 9, 2009, our average net daily production at West Hackberry was 34 BOE and was 100% oil. +6 +Table of Contents +Facilities +We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, effective date as of +November 1, 2007, from ExL Petroleum, LP and certain other sellers. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The +terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy is the operator of this field. +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a +long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was +not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 +feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill +completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry +Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize +approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. Currently, we hold +interests in 61 gross producing wells. +Geology +The Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The +Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin +Platform. +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Pinnacle +Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2008, proved reserves net to our interest in these assets were approximately 8.4 million BOE, of which 25% were classified as proved +developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 115 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally +characterized as long-lived, with predictable production profiles. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is expected to average gross 145,000 BOE per well or approximately 55,000 BOE net to our +interest. +7 +Table of Contents +Production Status +In December 2008, net production from the Permian field was 26,943 BOE or an average of 869 BOE per day, 59% of which was oil, 25% was natural gas liquids and 16% was natural gas. From January 1, 2009 through +March 9, 2009, our average daily net production from our Permian acreage was 725 BOE per day, 83% of which was from oil and natural gas liquids and 17% of which was from natural gas. As a result of the cessation of drilling, fracing and +recompletion activities, production has decreased since year end due to normal production declines. +Facilities +There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, +oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2008, 31 gross (15.5 net) wells were drilled in our Permian acreage, including one gross well spud in 2007 and completed in 2008 and one Henry +Petroleum operated well. We have identified 147 gross future development drilling locations. We currently expect an estimated three gross (1.5 net) wells to be drilled on our acreage in 2009. The wells are expected to be drilled to approximately +10,200 feet at an estimated average completed gross well cost of $1.34 million. +Bakken +Location and Land +Bakken is located in the Williston +Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. Beginning in 2005, Bakken +acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% +interest in Bakken’s assets in redemption of our 20% interest in Bakken. As a result, we currently hold interests in approximately 17,801 net acres, which includes approximately 4,600 acres in Mountrail Country, in the Bakken play. +As of December 31, 2008, we had participated, or committed to participate, in 53 gross wells in the Williston Basin with an average working +interest of 2.52%. Windsor Energy, the operator of our acreage, drilled and completed the first two Windsor operated wells in 2008. We own working interests of approximately 15.5% and 3.9%, respectively, in these two wells. +Production Status +In December 2008, net production +from the Bakken field was 8,692 BOE, or an average of 280 BOE per day, 100% of which was oil. From January 1, 2009 through March 9, 2009, our average net daily production from this acreage was 271 BOE and was 100% oil. +Facilities +There are typical land oil and gas +processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +8 +Table of Contents +Recent and future activities +In 2008, 37 gross (0.95 net) wells were drilled in our Bakken acreage including both those operated by Windsor and other non-operated wells. We have identified 31 gross future development drilling locations. We +currently expect an estimated 0.5 net wells to be drilled on our Bakken acreage in 2009. The wells are expected to be drilled to approximately 14,500 total measured depth, or TMD, feet at an estimated average gross completed well cost of $4.7 +million. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +2 +5 +Bayou Pigeon +Iberia +6.250 +% +0 +% +4 +5 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +6 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +1 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, +or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During the year ended December 31, 2008, we paid $50,000 in cash calls +and received $912,000 in distributions, bringing our total investment in Tatex (including previous investments) to $2.7 million. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method. +In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. Current net production is approximately 90 Mcf per +day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm +field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2007, net to our interest, are 3.5 BCF of gas and 19,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s +investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +Grizzly +Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and +2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9 +million at December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate of 117 core holes, tested five separate lease blocks and undertook a seismic program. Grizzly’s 2009 plans +currently include drilling approximately 15 additional core holes, which were completed in the first quarter 2009. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of +these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or +9 +Table of Contents +worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such +as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports +of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. +The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil +storage barge. Our production from WCBB, other than the production sold under forward sales contracts, is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month +average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $3.45 per barrel for transportation. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group LLC, or Windsor, the operator +of the Permian wells, 100% of our natural gas liquids production to Windsor, and 60%, 22%, and 16% of our natural gas production to Chevron, Windsor, and Hilcorp Energy Company, respectively. During 2007, we sold 99% of our oil production to Shell +and 69% of our natural gas production to Chevron and 23% of our natural gas production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96% of our natural gas production to Chevron. There can be no +assurance, however, that we will continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and +natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market +conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500 +barrels of WCBB production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had +entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 +million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August +2009. We have also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. For +the period January 2010 through February 2010, we have entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period +March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these contracts, we +have committed to deliver approximately 50% of our estimated 2009 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. +Since these contracts require physical delivery of production quantities, they normally would be exempted from the provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008, +we will not be able to apply this election on new contracts and they will be accounted for at fair value until we re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of +increases in the price of oil. +10 +Table of Contents +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of +legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements +carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, West Texas and the Williston Basin. +These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation +matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas +exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the +U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to +comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and +production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or +former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict liability nature of such laws and +regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, +disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable +environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect +oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the +individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas +are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or +the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to +re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” +Administrative, +civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste +11 +Table of Contents +handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under +such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production +wastes could increase our costs to manage and dispose of such wastes. +Comprehensive Environmental Response, Compensation and Liability +Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or legality of conduct, on classes of +persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the +time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several liability for the costs of cleaning up +the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims +for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. +Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Oil Pollution +Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state waters or waters of the United +States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws and regulations also prohibit certain activity in wetlands unless authorized by a +permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the +treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all permits required under the Clean Water Act. Sanctions for +failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. +Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and +continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations, +and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose +administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air +emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Our air emissions may +also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +Our operations are +subject to all of the risks normally incident to the production of oil and natural gas, including, but not limited to, blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which +12 +Table of Contents +could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury or death to persons and +wildlife. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental +damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully insured against could have a +material adverse effect on our financial position. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of +this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of finished office +area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2008, we had 37 +employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the estimated time they spent working for +those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2008 and 2007, expenses reimbursed to us under these arrangements were +$1.4 million and $11.2 million, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. +Available Information +Our annual +report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor +Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on +other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +13 +Table of Contents +ITEM 1A. +RISK FACTORS +Risks Related to Our Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon +the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are +beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +• +weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +political instability or armed conflict in oil and natural gas producing regions; and +• +the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate posted price for crude oil has ranged from +a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $3.53 per million British thermal units, or MMBtu, in September 2006 to a high of +$15.52 per MMBtu in January 2006. On December 31, 2008, the West Texas Intermediate posted price for crude oil was $44.60 per bbl and the Henry Hub spot market price of natural gas was $5.63 per MMBtu. Any substantial decline in the price of +oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties +due to ceiling test limitations. +Declining general economic, business or industry conditions may have a material adverse effect on our results of +operations, liquidity and financial condition. +Recently, concerns over inflation, energy costs, geopolitical issues, the availability +and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with +volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant +adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could +14 +Table of Contents +continue to diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect our vendors, suppliers and +customers ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition. +Our success +depends on finding, developing or acquiring additional reserves. +Our future success depends upon our ability to find, develop or +acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire +properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect in the future to +make substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with cash flow from +operations, the issuance of equity securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the level of oil and natural gas we are able to produce from existing wells; +• +the prices at which oil and natural gas are sold; and +• +our ability to acquire, locate and produce new reserves. +We may not have sufficient resources to undertake our exploration, development and production activities or the, acquisition of oil and natural gas reserves, our exploratory projects or other replacement activities +may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase +significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and integrate future +acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense competition for acquisition +opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and +equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional +employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and +results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +Our Canadian oil sands project is a complex undertaking and may not be completed at our estimated cost or at all. +During +the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly +acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9 million at +December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate of 117 core holes, tested five separate lease blocks and undertook a seismic program. 2009 plans currently include drilling +approximately 15 additional core holes and possibly acquiring additional leases. This is a complex project and financing has not been secured. This project may not be completed at our estimated cost or at all. +15 +Table of Contents +Shortage of rigs, equipment, supplies or personnel may restrict our operations. +The oil and natural gas industry is cyclical, which can result in a shortage of drilling rigs, equipment, supplies and personnel. As a result, the costs +and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in the number of active rigs in service. In accordance with customary industry practice, we rely on +independent third party service providers to provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, supplies, personnel, trucking services, tubulars, fracing and completion services and production equipment +could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations. +We +rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues. +Many key +responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our +Chief Financial Officer, or our two geophysicists, Stuart Maier and Randy Wilson, could disrupt our operations resulting in a loss of revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Liddell, +and our executives are not restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment agreement we may enter into will not assure the retention of our employees. In addition, we do not +maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees. +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production. +There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information included in this report represents only estimates +based on reports prepared by Netherland, Sewell & Associates, Inc. as of December 31, 2008 with respect to our WCBB field, by Pinnacle Energy Services, LLC with respect to our assets in the Permian Basin in West Texas and by our +personnel with respect to our Hackberry and Bakken fields and our overrides and non-operated interests. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering +estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production +from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, +capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group +of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual +production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. +The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved +reserves on prices and costs in effect on the day of estimate. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +16 +Table of Contents +The timing of both our production and our incurrence of costs in connection with the development and +production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash +flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources and the indicated level of reserves or recovery of bitumen may not be realized. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen +may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource +estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary +considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, +the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. +Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon +analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon +production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and +operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly’s lands cannot be determined at this time. +The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do +not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced. +The marketability of +our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to +them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural +gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field, which is our largest field. In October 2006, for example, a natural gas line in this field +operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges +necessary to transport our oil production from the WCBB field. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related +difficulties, we will be required to again shut in or curtail production from the field. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from the field, would adversely +affect our financial condition and results of operations. +17 +Table of Contents +An substantial portion of our producing properties is located in Louisiana, making us vulnerable to risks associated +with operating in this region. +Our operations are concentrated in Louisiana and our largest field, WCBB, is located approximately five +miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions +such as fog or rain, hurricanes or other natural disasters, or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate +insurance at rates we consider reasonable or that any particular types of coverage will be available. +Our identified drilling locations comprise an +estimation of part of our future drilling plans over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified over 150 drilling locations on our Louisiana properties. These drilling locations represent a significant part of our growth strategy. +Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs and drilling results. Because of these uncertainties, we do not know +if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially +differ from those presently identified, which could adversely affect our business. +Operating hazards and uninsured risks may result in substantial +losses. +Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and +natural gas, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could +result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and +penalties and suspension of operations. For example, in October 2006, an accident occurred north of our production facilities in the WCBB field in southern Louisiana involving two contracted vessels that were performing work on our behalf in the +field. A tugboat and two barges laden with construction materials ruptured an underwater natural gas pipeline and a subsequent fire damaged the vessels. Six fatalities resulted from the accident. Several lawsuits relating to this incident were filed +against us, among other parties. These lawsuits against us have all been settled. +In accordance with customary industry practice, we +historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its +availability may be at premium levels that do not justify its purchase. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the +Gulf Coast region. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. +Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive. +Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to +regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls +and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, emission and disposal of +oil and gas, by-products thereof and other substances and +18 +Table of Contents +materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations +relating to protection of human health and the environment. These laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and waste management. Significant expenditures may be required to +comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. +We face extensive competition in our industry. +The oil and natural gas industry is intensely +competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products +on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, +the availability of alternative energy sources and the application of government regulation. +We depend upon two customers for the sale of most of our +oil and natural gas production. +The availability of a ready market for any oil and natural gas we produce depends on numerous factors +beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and +federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the +majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. At December 31, 2008, our WCBB production, other than production sold under forward sales contracts, was being sold +in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $3.45 per Bbl for +transportation. For the year ended December 31, 2008 and the year ended December 31, 2007, we sold approximately 87% and 99%, respectively, of our oil production to Shell and 60% and 69%, respectively, of our natural gas production to +Chevron. During 2008, we sold approximately 11%, 100%, and 22% of our oil, natural gas liquids, and natural gas production, respectively, to Windsor and 16% of our natural gas production to Hilcorp Energy Company. During 2007, we sold approximately +23% of our natural gas production to Hilcorp Energy Company. During 2006, we sold 100% of our oil production to Shell and 96% of our natural gas production to Chevron. We may not continue to have ready access to suitable markets for our future oil +and natural gas production. +Our method of accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general +and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at +10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an +equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. +Companies that use +the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the +lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated +year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the +balance sheet, (b) the cost of +19 +Table of Contents +properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less +income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is +required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. For instance, as a +result of the drop in commodity prices on December 31, 2008, we recognized a ceiling test impairment of $272,722,000 for the year ended December 31, 2008. This impairment, however, reduces future depletion expense. If prices of oil, +natural gas and natural gas liquids continue to decrease, we may be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of operations. +Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the +results of our drilling operations. +Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are +only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and +other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. +We have entered into forward sales contracts and may in the future enter into additional contracts for a portion of our production, which may result in +our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. +To mitigate the effects +of commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500 barrels of WCBB production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered +approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel +before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at +a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We have also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted +average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. For the period January 2010 through February 2010, we have entered into forward sales contracts for the sale of 3,000 barrels of +WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB +production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these contracts, we have committed to deliver approximately 50% of our estimated 2009 production. Such arrangements may expose us to risk +of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. Since these contracts require physical delivery of production quantities, they normally would be exempted from the +provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008, we will not be able to apply this election on new contracts and they will be accounted for at fair value until we +re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +A terrorist attack or armed conflict could harm our business. +Terrorist activities, anti-terrorist +efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the +resulting political instability and societal +20 +Table of Contents +disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in +our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for +insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. +Conservation measures and technological advances could reduce demand for oil and natural gas. +Fuel conservation measures, +alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand +for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. +We +are subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If the costs related to such compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely +affected. +Commencing with our fiscal year ended December 31, 2007, we became subject to Section 404 of the Sarbanes-Oxley Act +of 2002, or Section 404, which requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our +independent registered public accounting firm audit our internal control over financial reporting. We are required to evaluate our existing controls against the criteria established in Internal Control-Integrated Framework issued by the Committee of +Sponsoring Organizations of the Treadway Commission, or COSO. The out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of +Section 404 have been significant. If the future time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected. If we fail to fully comply with the requirements of +Section 404 or if we determine that we have a material weakness or significant deficiencies, or if our auditors disagree with our assessment in connection with the presentation of our financial statements, the accuracy and timeliness of the +filing of our periodic reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a +material weakness or significant deficiency in our internal control over financial reporting could result in an increased chance of fraud, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, +each of which could have a material adverse effect on our business, results of operations and financial condition. +Our system of disclosure and +internal controls and procedures may not be successful in preventing all errors and fraud, or in making all material information known in a timely manner to management. +Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and internal controls will +prevent all errors and fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect +the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the limitations in all control systems, no evaluation of controls can provide absolute assurance that all control +issues and instances of fraud, if any, within our company have been detected. These limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, +controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. +The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions. Over time, a +control may become inadequate because of changes in conditions, or the degree of compliance with +21 +Table of Contents +the policies or procedures may deteriorate. Because of the limitations in a cost effective control system, misstatements due to error or fraud may occur and +not be detected that could have a material adverse effect on our business, results of operations and financial condition. +Risks Related to Our Common +Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our +stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: +• +changes in oil and natural gas prices; +• +changes in production levels; +• +changes in governmental regulations and taxes; +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the +future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some future quarters, our +operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +Our officers and directors together with our largest stockholder control a significant percentage of our common stock, and their interests may conflict with those of +our other stockholders. +As of December 31, 2008, our executive officers and directors, in the aggregate, beneficially owned +approximately 4% of our outstanding common stock and Charles E. Davidson, one of our major stockholders, beneficially owned approximately 36% of our outstanding common stock. As a result, these stockholders acting together are able to exercise +significant influence over most matters requiring approval by our stockholders, including the election of directors and the approval of significant corporate transactions. Such a concentration of ownership may have the effect of delaying or +preventing a change in control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices. +An active trading market for our common stock may not develop or be sustained. +Since July 14, +2006, our common stock has been listed on The NASDAQ Global Select Market under the symbol “GPOR.” From February 28, 2006 until that date, our common stock was listed on the NASDAQ National Market. Prior to that date, our common stock +was traded on the NASD OTC Bulletin Board under the symbol “GPOR.OB.” There is a limited market for our shares. An active trading market may not develop, or if it does, it may not be sustained. +We do not currently pay dividends on our common stock and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to retain any earnings +to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock. +22 +Table of Contents +A change of control could limit our use of net operating losses. +As of December 31, 2008, we had a net operating loss, or NOL, carry forward of approximately $60 million for federal income tax purposes. Transfers +of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax year after the date of +the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +Future +sales of our common stock may depress our stock price. +We and certain of our stockholders have registered a substantial number of +shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. +In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of March 1, 2009, there were 42,647,034 shares of our common stock issued and +outstanding, excluding 85,037 shares of restricted stock awarded under our 2005 Stock Incentive Plan. +We could issue preferred stock which could be +entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects. +We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution +or resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if +any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation +Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions +thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock. +In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a +third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders. +The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be +beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None +23 +Table of Contents +ITEM 2. +PROPERTIES +Proved Oil and Natural Gas Reserves +The oil and natural gas reserve information set forth below represents estimates of our proved oil and natural gas reserves as prepared by the +independent engineering firm of Netherland, Sewell & Associates, Inc., or NSAI, Pinnacle Energy Services, LLC, or Pinnacle, and by our personnel. Reserve engineering is a subjective process of estimating volumes of economically recoverable +oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers +often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of +economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. +See “Risk Factors” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. +The following table sets forth estimates of our proved oil and natural gas reserves at December 31, 2008, 2007 and 2006. Reserve +estimates at December 31, 2008 were prepared by NSAI with respect to our WCBB field (48% of proved reserves PV-10 value at December 31, 2008), by Pinnacle with respect to our assets in the Permian Basin in West Texas (28% of proved +reserves PV-10 value at December 31, 2008) and by our personnel with respect to our Hackberry fields and our overriding royalty and non-operated interests including Bakken (24% of proved reserves PV-10 value at December 31, 2008). Reserve +estimates at December 31, 2007 were prepared by NSAI with respect to our WCBB field (61% of proved reserves PV-10 value at December 31, 2007), by Pinnacle with respect to our assets in the Permian Basin in West Texas (18% of proved +reserves PV-10 value at December 31, 2007) and by our personnel with respect to our Hackberry fields and our overriding royalty and non-operated interests (21% of proved reserves PV-10 value at December 31, 2007). The reserve estimates at +December 31, 2006 were prepared by NSAI with respect to our WCBB field (82% of proved reserves PV-10 value at December 31, 2006) and by our personnel with respect to our Hackberry fields and our overriding royalty and non-operated +interests (18% of proved reserves PV-10 value at December 31, 2006). +December 31, 2008 +December 31, 2007 +December 31, 2006 +Developed +Undeveloped +Total +Developed +Undeveloped +Total +Developed +Undeveloped +Total +Oil (MBbls) +7,072 +14,699 +21,771 +7,116 +17,999 +25,115 +4,876 +14,816 +19,692 +Gas (MMcf) +7,187 +15,048 +22,235 +6,746 +17,513 +24,259 +4,077 +16,724 +20,801 +Mboe +8,269 +17,208 +25,477 +8,240 +20,918 +29,158 +5,556 +17,603 +23,159 +PV-10 (in millions) (1) +$ +91.6 +$ +34.6 +$ +126.2 +$ +294.7 +$ +526.5 +$ +821.2 +$ +120.0 +$ +279.4 +$ +399.4 +Standardized measure (in millions) (2) +$ +126.2 +$ +668.3 +$ +352.6 +(1) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set +forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on economic conditions prevailing at December 31, 2008. The estimated future production in +our WCBB and Hackberry fields is priced at December 31, 2008, 2007 and 2006, without escalation using $41.00 per barrel and $5.71 per MMBtu, $92.50 per barrel and $6.80 per MMBtu and $57.75 per barrel and $5.64 per MMBtu, respectively, adjusted +by lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income tax +effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas +companies. +24 +Table of Contents +PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as +defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure—standardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash +flows to the PV-10 value: +December 31, +2008 +2007 +2006 +Standardized measure of discounted future net cash flows +$ +126,240,000 +$ +668,295,000 +$ +352,648,000 +Add: Present value of future income tax discounted +at 10% +— +152,949,000 +46,804,000 +PV-10 value +$ +126,240,000 +$ +821,244,000 +$ +399,452,000 +(2) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, +and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes +the effect of future income taxes. +The above table does not include proved reserves net to our interest in Tatex of 3.5 Bcf +of gas and 19,000 barrels of oil at December 31, 2008. For further discussion of our interest in Tatex, see Item 1. “Description of Business—Additional Properties.” +Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data +demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e ., prices and costs as of the date the estimate is made. Prices include consideration of +changes in existing prices only by contractual arrangements, but not on escalations based on future conditions. Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating +methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable +certainty, or from existing wells on which a relatively major expenditure is required to establish production. +Total proved reserves were +25,477 Mboe at December 31, 2008, 29,158 Mboe at December 31, 2007 and 23,159 Mboe at December 31, 2006. The decrease in 2008 reserves, as compared to 2007 reserves, is primarily attributable to the decline in oil prices. The increase +in 2007 reserves, as compared to 2006 reserves, is mainly attributable to the acquisition of our Permian assets in December 2007. As of December 31, 2008, 36.7% of our total proved reserves were classified as proved developed non-producing. +The following table sets forth certain information with respect to the total proved undeveloped reserves that were converted to proved +developed status over the past five years. +YEAR +Beginning of +Year Proved +Undeveloped +Reserves +MBOE +PUD Reserves +Converted to +Proved +Developed +MBOE +% PUD Reserves +Converted to +Proved +Developed +% +Capital Related to +Development of +PUD +Reserves +MM$ +2004 +20,138 +493.0 +2.4 +% +6.2 +2005 +19,361 +1,300.0 +6.7 +% +18.9 +2006 +18,238 +1,435.0 +7.9 +% +33.0 +2007 +17,603 +2,804.0 +15.9 +% +55.6 +2008 +20,918 +(1) +2,586.0 +12.4 +% +61.8 +(1) +Includes 5,041 MBOE added from the acquisition of the Permian Basin in December 2007. +25 +Table of Contents +Our total proved oil and gas reserves of 25,477 Mboe at December 31, 2008 include reserves attributable +to 81 PUD wells at WCBB that we anticipate will be drilled by 2019. Of these total reserves, an aggregate of 2,839 Mboe of undeveloped reserves at WCBB are scheduled for development from 2014 through 2019 for aggregate estimated development costs of +$69.1 million. These proved undeveloped reserves with a development schedule beyond five years have been included in our reserve estimate based on the results of an extensive engineering and geological field analysis undertaken by us and our +independent third party petroleum engineer, our subsequent reprocessing and reinterpreting of our seismic data and an analysis of historical subsurface well data and data gathered from our drilling activities. Over the past 12 years, we have drilled +128 wells at WCBB, excluding exploratory wells drilled to preserve acreage, with a success rate in excess of 88%. We have included these PUD locations in our reserves based on our historical drilling experience and our belief that they will be +drilled within the ten-year period contemplated by our reserve report. +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2008 +2007 +2006 +Production Volumes: +Oil (MBbls) +1,584 +1,501 +870 +Gas (MMcf) +712 +816 +677 +Natural gas liquids (Gallons) +2,583 +— +— +Oil equivalents (Mboe) +1,764 +1,637 +983 +Average Prices: +Oil (per Bbl) +$ +83.23 +(1) +$ +66.71 +(1) +$ +64.43 +(1) +Gas (per Mcf) +$ +9.23 +$ +7.40 +$ +6.20 +Natural gas liquids (per Gallon) +$ +1.26 +$ +— +$ +— +Oil equivalents (per Mboe) +$ +80.30 +$ +64.86 +$ +61.30 +Production Costs: +Average production costs (per Boe) +$ +12.96 +(2) +$ +10.18 +(2) +$ +10.86 +(2) +Average production taxes (per Boe) +$ +8.96 +$ +7.74 +$ +7.50 +Total production costs (per Boe) +$ +21.92 +$ +17.92 +$ +18.36 +(1) +Includes fixed contract prices at a weighted average price of: +January – December 2006 +$ +64.05 +June – December 2007 +$ +66.10 +January – December 2008 +$ +78.56 +Excluding the net effect of the fixed price contracts, the average oil price for 2008 would have +been $118.63 per barrel and $112.08 per barrel of oil equivalent. The total volume hedged for 2008 represented approximately 73% of our total oil sales for the year. Excluding the net effect of the fixed price contracts, the average oil price for +2007 would have been $72.25 per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represented approximately 43% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the +average oil price for 2006 would have been $65.56 per barrel and $62.30 per barrel of oil equivalent. The total volume hedged for 2006 represented approximately 62% of our total oil sales volumes for the year. Also includes financial hedge contracts +with an average mark-to-market value of approximately $82,000 per month for the months of January-December 2006. +(2) +Does not include production taxes. +26 +Table of Contents +Productive Wells and Acreage +The following table presents our total gross and net productive wells, expressed separately for oil and gas, and the total gross and net developed acres as of December 31, 2008: +NRI/WI (1) +Producing +Wells (2) +Non-Producing +Wells +Developed +Acreage (3) +Undeveloped +Acreage +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +Gross +Net +West Cote Blanche Bay (4) +80.3/100 +107 +107 +158 +158 +5,668 +5,668 +— +— +E. Hackberry (5) +79.4/100 +18 +18 +80 +80 +3,291 +3,291 +3,942 +3,942 +W. Hackberry +87.5/100 +3 +3 +24 +24 +592 +592 +— +— +Permian +38.1/49.5 +61 +30.5 +— +— +8,075 +4,150 +480 +160 +Bakken (6) +2.3/2.2 +38 +0.8 +— +— +8,153 +891 +154,737 +16,910 +Overrides/Royalty Non-operated +Various +9 +0.5 +17 +0.8 +4,956 +586 +— +— +Total +236 +159.8 +279 +262.8 +30,735 +15,178 +159,159 +21,012 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes 30 gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 42% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.335% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a +40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +Completed and Present Drilling and Recompletion Activities +The following table sets forth +information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive +wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +2008 +2007 +2006 +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +58 +56.5 +62 +62 +18 +18 +Dry +— +— +— +— +1 +1 +Total +58 +56.5 +62 +62 +19 +19 +Development: +Productive +69 +27 +23 +23 +24 +24 +Dry +— +— +3 +3 +2 +2 +Total +69 +27 +26 +26 +26 +26 +Exploratory: +Productive +0 +0 +9 +9 +1 +1 +Dry +1 +1 +3 +3 +1 +1 +Total +1 +1 +12 +12 +2 +2 +27 +Table of Contents +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are +acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. +Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management’s opinion, will in the aggregate materially restrict our operations. +ITEM 3. +LEGAL PROCEEDINGS +The Louisiana Department of +Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR maintains that we paid approximately $1.8 million less in severance taxes +under fixed price terms than the severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any liability to the LDR for underpayment of severance taxes and have maintained +that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. We have maintained our right to contest any final assessment or suit for +collection if brought by the State. +In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us and Great White +Pressure Control LLC, an affiliate of ours, among others, in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The +lawsuit alleges RICO violations and several other causes of action relating to an affiliate company’s employment of several former Cudd employees and seeks unspecified monetary damages and injunctive relief. The defendants in the suit are +Ronnie Roles, Rocky Roles, Steve Winters, Bert Ballard, Nelson Britton, Michael Fields, Great White Pressure Control LLC, and us. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on +February 14, 2007. We filed a motion for summary judgment on October 5, 2007. The Court entered a final interlocutory judgment in favor of all defendants, including us, on April 8, 2008. On November 3, 2008, Cudd filed its appeal +with the U.S. Court of Appeals for the Fifth Circuit. The defendants filed their response appellate brief on December 19, 2008, and Cudd filed its reply brief on January 19, 2009. We are currently awaiting the Fifth Circuit’s ruling +on this matter. +On July 27, 2007, Robotti & Company, LLC filed a putative class action lawsuit in the Court of Chancery for +the State of Delaware in and for Kent County, Delaware. The original complaint alleged a breach of fiduciary duty by us and our then present directors in connection with the pricing of our 2004 rights offering. Plaintiff filed an amended complaint +on January 15, 2008, and we filed a motion to dismiss in early February 2008 and filed the brief in support of such motion on April 29, 2008. The court held a hearing on October 3, 2008, ultimately deciding to allow the plaintiff to +file a second amended complaint. Plaintiff filed its second amended complaint December 22, 2008, which sets forth class action and derivative claim allegations that our then present directors breached their fiduciary duty in connection with the +pricing of the 2004 rights offering. The defendants filed their motion to dismiss on January 19, 2009 and their brief in support of such motion on February 20, 2009. Briefing by the parties is scheduled to conclude April 6, 2009 and +we anticipate the court will rule on the defendants’ motion to dismiss thereafter. +Due to the current stages of the above litigation, +the outcomes are uncertain and management cannot determine the amount of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse affect on our financial +condition or results of operations. +In addition to the above, we have been named as a defendant in various other lawsuits related to our +business. The ultimate resolution of such other matters is not expected to have a material adverse effect on our financial condition or results of operations. +ITEM 4. +SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS +None. +28 +Table of Contents +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market under the symbol “GPOR.” The following table sets +forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2007 +First Quarter +$ +13.89 +$ +10.82 +Second Quarter +21.34 +12.86 +Third Quarter +23.70 +15.36 +Fourth Quarter +25.62 +16.60 +2008 +First Quarter +$ +19.41 +$ +10.16 +Second Quarter +$ +17.67 +$ +10.43 +Third Quarter +$ +17.07 +$ +9.00 +Fourth Quarter +$ +10.03 +$ +2.87 +2009 +First Quarter (through February 28, 2009) +$ +5.20 +$ +2.12 +On March 12, 2009, the last reported sale price of our common stock on The NASDAQ Global +Select Market was $2.59. +Unregistered Sales of Equity Securities and Use of Proceeds +None. +Holders of Record +At the close of business on March 3, 2009, there were 404 stockholders of record holding 42,647,034 shares of our outstanding common stock. There +were approximately 7,399 beneficial owners of our common stock as of March 3, 2009. +Dividend Policy +We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay +any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends to the holders of our common stock. +29 +Table of Contents +ITEM 6. +SELECTED FINANCIAL DATA +You should read the +following selected consolidated financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the related notes appearing +elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2008, December 31, 2007 and December 31, 2006 and the selected consolidated balance sheet data at +December 31, 2008 and December 31, 2007 are derived from our audited consolidated financial statements appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, +2005 and December 31, 2004 and the selected consolidated balance sheet data at December 31, 2006, December 31, 2005 and December 31, 2004 are derived from our audited consolidated financial statements that are not included +in this report. The historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during any of the periods set forth in the following table. +Fiscal Year Ended December 31, +2008 +2007 +2006 +2005 +2004 +Selected Consolidated Statements of Operations Data: +Revenues +$ +141,217,000 +$ +105,838,000 +$ +60,390,000 +$ +27,559,000 +$ +23,190,000 +Costs and expenses: +Lease operating expenses +22,856,000 +16,670,000 +10,670,000 +7,654,000 +6,586,000 +Production taxes +15,813,000 +12,667,000 +7,366,000 +3,622,000 +2,629,000 +Depreciation, depletion and amortization +42,472,000 +29,681,000 +12,652,000 +4,789,000 +4,952,000 +Impairment of oil and natural gas properties +272,722,000 +— +— +— +— +General and administrative +6,843,000 +5,802,000 +3,251,000 +1,561,000 +2,107,000 +Accretion expense +560,000 +554,000 +596,000 +516,000 +490,000 +361,266,000 +65,374,000 +34,535,000 +18,142,000 +16,764,000 +Income (Loss) from Operations +(220,049,000 +) +40,464,000 +25,855,000 +9,417,000 +6,426,000 +Other (Income) Expense: +Interest expense +4,762,000 +3,091,000 +1,956,000 +250,000 +246,000 +Interest expense—preferred stock +— +— +— +272,000 +1,949,000 +Insurance recoveries +(769,000 +) +— +(3,601,000 +) +(1,710,000 +) +— +Settlement of fixed price contracts +(39,000,000 +) +— +— +— +— +Interest income +(540,000 +) +(523,000 +) +(308,000 +) +(290,000 +) +(73,000 +) +(35,547,000 +) +2,568,000 +(1,953,000 +) +(1,478,000 +) +2,122,000 +Income (Loss) before Income Taxes +(184,502,000 +) +37,896,000 +27,808,000 +10,895,000 +4,304,000 +Income Tax Expense +— +121,000 +— +— +— +Net Income (Loss) +(184,502,000 +) +37,775,000 +27,808,000 +10,895,000 +4,304,000 +Net Income (Loss) Available to Common Stockholders +$ +(184,502,000 +) +$ +37,775,000 +$ +27,808,000 +$ +10,895,000 +4,304,000 +Net Income (Loss) Per Common Share—Basic: +$ +(4.33 +) +$ +1.03 +$ +0.85 +$ +0.36 +$ +0.31 +Net Income (Loss) Per Common Share—Diluted: +$ +(4.33 +) +$ +1.01 +$ +0.82 +$ +0.34 +$ +0.28 +30 +Table of Contents +At December 31, +2008 +2007 +2006 +2005 +2004 +Selected Consolidated Balance Sheet Data: +Total assets +$ +221,873,000 +$ +419,137,000 +$ +195,151,000 +$ +111,820,000 +$ +78,150,000 +Total debt, including current maturity +$ +70,731,000 +$ +66,533,000 +$ +37,691,000 +$ +10,200,000 +$ +3,404,000 +Total liabilities +$ +107,772,000 +$ +115,015,000 +$ +71,342,000 +$ +27,493,000 +$ +29,053,000 +Stockholders’ equity +$ +114,101,000 +$ +304,122,000 +$ +123,809,000 +$ +84,327,000 +$ +49,097,000 +31 +Table of Contents +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in +this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial +position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and +“Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. +Overview +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf +Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC and in the Bakken +Shale, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +2008 Highlights +• +Oil and natural gas revenues increased $35.6 million to $141.7 million for the year ended December 31, 2008 from $106.1 million for 2007. +• +Net loss including impairment of oil and gas assets of $272.7 million was $184.5 million for the year ended December 31, 2008. Before impairment of oil and +natural gas properties, net income increased 133% to $88.2 million for the year ended December 31, 2008 from $37.8 million for 2007. +• +Production increased 8% to 1,764,000 BOE for the year ended December 31, 2008 from 1,637,000 BOE for 2007. +• +During 2008, we drilled 81 wells and recompleted 58 wells. Of our 81 new wells drilled, 69 were completed as producing wells, one was non-productive and 11 are +waiting on completion. +Critical Accounting Policies and Estimates +Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been +prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of +assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment +by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions +that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and +estimates used in the preparation of our consolidated financial statements: +Oil and Natural Gas Properties . We use the full cost +method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas +properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to +amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, +32 +Table of Contents +if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or +loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to +amortization consist of the cost of undeveloped leaseholds and totaled $22.5 million at December 31, 2008 and $37.3 million at December 31, 2007. These costs are reviewed periodically by management for impairment, with the impairment +provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas +leases not held by production and available funds for exploration and development. +Ceiling Test . Companies that use the full cost +method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of +unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end +prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the +balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book +and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a +significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on +December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272,722,000 for the year ended December 31, 2008. If prices of oil, natural gas and natural gas liquids continue to decrease, we +may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. +Asset Retirement Obligations . We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning +wells and associated production facilities. +We account for abandonment and restoration liabilities under Statement of Financial Accounting +Standards No. 143, “ Accounting for Asset Retirement Obligations, “ SFAS No. 143, which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is +recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset +by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of +the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of +the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of +these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting +in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire +these assets may vary significantly from previous estimates. +33 +Table of Contents +Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil +and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, +Inc., Pinnacle Energy Services, LLC and to a lesser extent our personnel have prepared reserve reports of our reserve estimates on a well-by-well basis for our properties. +Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion +and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with SEC guidelines. The accuracy of our reserve +estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and +natural gas eventually recovered. +Income Taxes . We use the asset and liability method of accounting for income taxes, under which +deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss +and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on +deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its +taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management’s opinion, it +is more likely than not that some portion will not be realized. At December 31, 2008, a valuation allowance of $81.9 million had been provided for deferred tax assets based on the uncertainty of future taxable income. +Revenue Recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. +Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to +purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have +not significantly deviated from our accruals. +Commitments and Contingencies . Liabilities for loss contingencies arising from +claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the +certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities. +Derivative Instruments and Hedging Activities . We seek to reduce our exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of SFAS 133, +“ Accounting for Derivative Instruments and Hedging Activities ,” as amended. It requires that all derivative +34 +Table of Contents +instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments +using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial +statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting +for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as +cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly +based on the relative changes in fair value between the derivative contract and the hedged item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. +To mitigate the effects of commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500 barrels of WCBB +production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had entered into +agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. +Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We have +also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. For the period +January 2010 through February 2010 we have entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 +through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these 2009 contracts, we have +committed to deliver approximately 50% of our estimated 2009 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. Since +these contracts require physical delivery of production quantities, they normally would be exempted from the provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008, we +will not be able to apply this election on new contracts and they will be accounted for at fair value until we re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of +increases in the price of oil. +RESULTS OF OPERATIONS +Results of Operations +The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices +for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +35 +Table of Contents +The following table presents our production volumes, average prices received and average production costs +during the periods indicated: +2008 +2007 +2006 +Production Volumes: +Oil (MBbls) +1,584 +1,501 +870 +Gas (MMcf) +712 +816 +677 +Natural gas liquids (Gallons) +2,583 +— +— +Oil equivalents (Mboe) +1,764 +1,637 +983 +Average Prices: +Oil (per Bbl) +$ +83.23 +(1) +$ +66.71 +(1) +$ +64.43 +(1) +Gas (per Mcf) +$ +9.23 +$ +7.40 +$ +6.20 +Natural gas liquids (per Gallon) +$ +1.26 +$ +— +$ +— +Oil equivalents (per Mboe) +$ +80.30 +$ +64.86 +$ +61.30 +Production Costs: +Average production costs (per Boe) +$ +12.96 +(2) +$ +10.18 +(2) +$ +10.86 +(2) +Average production taxes (per Boe) +$ +8.96 +$ +7.74 +$ +7.50 +Total production costs (per Boe) +$ +21.92 +$ +17.92 +$ +18.36 +(1) +Includes fixed contract prices at a weighted average price of: +January – December 2006 +$ +64.05 +June – December 2007 +$ +66.10 +January – December 2008 +$ +78.56 +Excluding the net effect of the fixed price contracts, the average oil price for 2008 would have +been $118.63 per barrel and $112.08 per barrel of oil equivalent. The total volume hedged for 2008 represented approximately 73% of our total oil sales for the year. Excluding the net effect of the fixed price contracts, the average oil price for +2007 would have been $72.25 per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represented approximately 43% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the +average oil price for 2006 would have been $65.56 per barrel and $62.30 per barrel of oil equivalent. The total volume hedged for 2006 represented approximately 62% of our total oil sales volumes for the year. Also includes financial hedge contracts +with an average mark-to-market value of approximately $82,000 per month for the months of January-December 2006. +(2) +Does not include production taxes. +From 2007 to 2008, our +net oil equivalent production increased 8% from 1,637,000 barrels to 1,764,000 due primarily to continued drilling and recompletion activities. From 2006 to 2007, our net oil production increased 73% from 870,000 barrels to 1,501,000 barrels due to +our continued drilling activity. We currently estimate that our 2009 production will be between 1,600,000 and 1,800,000 BOE. However, such estimate may change based on the changing economic climate and unforeseen events, such as hurricanes. +Comparison of the Years Ended December 31, 2008 and December 31, 2007 +We reported a net loss of $184,502,000 for the year ended December 31, 2008, compared to net income of $37,775,000 for the year ended +December 31, 2007. This net loss was primarily attributable to an impairment charge of $272,722,000 related to the drastic decline in oil and gas prices, partially offset by a $39.0 million gain from the sale in December 2008 of all of our then +existing 2009 fixed price contracts. Excluding the effect of the impairment, our net income increased 133% due primarily to (1) a 8% increase in net production to 1,764,053 BOE for the year ended December 31, 2008 from 1,636,902 BOE for +2007, (2) a 25% increase in the average oil price received to $83.23 per barrel for the year ended December 31, 2008 from $66.71 per barrel for 2007 and (3) a $39.0 million gain from the sale in December 2008 of all of our then +existing fixed price contracts. +36 +Table of Contents +Oil and Gas Revenues . For the year ended December 31, 2008, we reported oil and gas revenues +of $141,650,000, compared to oil and gas revenues of $106,163,000 during 2007. This 33% increase in revenues is mainly attributable to an 8% increase in net production to 1,764,053 BOE for the year ended December 31, 2008 from 1,636,902 BOE for +2007 and a 25% increase in the average oil price received to $83.23 per barrel for the year ended December 31, 2008 from $66.71 per barrel for 2007. This increase in oil and natural gas production was the result of production from our 2008 +drilling programs and the acquisition of the Permian wells in December 2007. Production in 2008 was adversely affected by the damage caused by Hurricane Ike with production not fully restored until December, 2008. We estimate that approximately +170,000 barrels of oil equivalents production were deferred to other periods. +The following table summarizes our oil and natural gas +production and related pricing for the years ended December 31, 2008 and December 31, 2007: +Year Ended +December 31, +2008 +2007 +Oil production volumes (MBbls) +1,584 +1,501 +Gas production volumes (MMcf) +712 +816 +Natural gas liquids production volumes (Gallons) +2,583 +— +Oil equivalents (Mboe) +1,764 +1,637 +Average oil price (per Bbl) +$ +83.23 +$ +66.71 +Average gas price (per Mcf) +$ +9.23 +$ +7.40 +Average natural gas liquids (per gallon) +$ +1.26 +$ +— +Oil equivalents (per Boe) +$ +80.30 +$ +64.86 +Lease Operating Expenses . Lease operating expenses, or LOE, excluding the effects of +hurricane related costs and production taxes, increased to $19,448,000 for 2008 from $16,670,000 for 2007. The increase in ongoing LOE was mainly due to $2,700,000 of LOE related to the Permian properties acquired in December 2007. In addition, +there were also increases in personal property taxes and repairs to compressors and other equipment in our operating area along the Louisiana Gulf Coast. Included in total LOE of $22,856,000 before production taxes is $3,408,000 of hurricane related +LOE costs incurred during 2008. +Production Taxes . Production taxes increased to $15,813,000 for 2008 from $12,667,000 for 2007. +This increase was directly related to a 33% increase in oil and gas revenues as a result of the 24% improvement in the price received per barrel of oil equivalent and an 8% increase in production for 2008 as compared to 2007. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense increased to $42,472,000 for the year ended +December 31, 2008, and consisted of $42,194,000 in depletion on oil and natural gas properties and $278,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $29,681,000 +for the year ended December 31, 2007, which consisted of $29,220,000 in depreciation on oil and natural gas properties and $461,000 in depreciation of other property and equipment. This increase was due primarily to an increase in our oil and +natural gas property costs associated with our 2008 drilling program, an increase in our oil and gas production for the period and a decrease in our total oil and gas reserve volumes. +Impairment of Oil and Gas Properties. We use the full cost method of accounting for oil and gas properties and are required to perform a ceiling +test each quarter. The test determines a limit, or ceiling, on the book value of our oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center +ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, +that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on our balance sheet, (b) the cost of properties not being amortized, if any, and (c) the +lower of cost or market value of +37 +Table of Contents +unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and +natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash write-down is required. As a result of the drop in commodity prices on December 31, 2008, we +recognized a ceiling test impairment of $272,722,000 for the year ended December 31, 2008. This impairment however will reduce future depletion expense. There was no impairment charge for the year ended December 31, 2007. +General and Administrative Expenses . Net general and administrative expenses increased to $6,843,000 for 2008 from $5,802,000 for 2007. This +$1,041,000 increase was due primarily to an $832,000 increase in franchise taxes as a result of an increase in total assets and shares outstanding and slight increases in audit fees and insurance costs. +Accretion Expense . Accretion expense increased slightly to $560,000 for 2008 from $554,000 for 2007, due to a larger obligation at the beginning +of 2008 compared to the beginning of 2007, resulting from the addition of future abandonment obligations on new wells drilled during 2007. +Interest Expense . Interest expense increased to $4,762,000 for 2008 from $3,091,000 for 2007 due to an increase in average debt outstanding. Total weighted debt outstanding under our facilities with Bank of America was $84.2 million +for 2008 as compared to $33.2 million for 2007. +Settlement of Fixed Price Contracts. In December 2008, we terminated all of our +then existing 2009 fixed price contracts. Through the termination of these contracts, we received a $39.0 million payment during the fourth quarter of 2008, and in accordance with SFAS 133, these amounts were recognized into earnings during the +fourth quarter of 2008, the period in which the fixed price contracts were settled. There was not a termination of any fixed price contracts during the year ended December 31, 2007. +Income Taxes . As of December 31, 2008, we had a net operating loss carry forward of approximately $60 million, in addition to numerous +temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our future taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive +and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2008, a valuation allowance of $81.9 +million had been provided for our entire net deferred tax asset, with the exception of $653,000 related to alternative minimum taxes. +Comparison of the +Years Ended December 31, 2007 and December 31, 2006 +We reported net income of $37,775,000 for the year ended +December 31, 2007, compared to $27,808,000 for the year ended December 31, 2006. This 36% increase in net income was due primarily to (1) a 67% increase in net production to 1,636,902 BOE for the year ended December 31, 2007 from +982,531 BOE for 2006 as a result of our continued drilling activity and (2) a 6% increase in the average BOE oil price received to $64.86 per barrel for the year ended December 31, 2007 from $61.30 per barrel for 2006. Although we closed +the acquisition of the assets in the Permian Basin in West Texas on December 20, 2007, effective as of November 1, 2007, under GAAP only the oil and gas activities for the days subsequent to the closing date, which in this case were from +December 21 through December 31, 2007, can be included in our 2007 oil and gas activities. As a result, activities related to these new assets had little impact on our results of operations for the year ended December 31, 2007. +Oil and Gas Revenues . For the year ended December 31, 2007, we reported oil and gas revenues of $106,163,000, compared to oil +and gas revenues of $60,232,000 during 2006. This $45,931,000, or 76%, increase in revenues is primarily attributable to a 67% increase in net production to 1,636,902 BOE for the year ended December 31, 2007 from 982,531 BOE for the year ended +December 31, 2006. Production in the first half of 2006 was negatively impacted by the damage caused by Hurricane Rita, as production from our wells at WCBB was not fully restored until later in 2006. +38 +Table of Contents +The following table summarizes our oil and natural gas production and related pricing for the years ended +December 31, 2007 and 2006: +Year Ended +December 31, +2007 +2006 +Oil production volumes (MBbls) +1,501 +870 +Gas production volumes (MMcf) +816 +677 +Oil equivalents (Mboe) +1,637 +983 +Average oil price (per Bbl) +$ +66.71 +$ +64.43 +Average gas price (per Mcf) +$ +7.40 +$ +6.20 +Oil equivalents (per Boe) +$ +64.86 +$ +61.30 +Lease Operating Expenses . Lease operating expenses not including production taxes increased +to $16,670,000 for the year ended December 31, 2007 from $10,670,000 for 2006. Since our WCBB facilities continued to be shut in until late in the first quarter of 2006 due to the impact of Hurricane Rita some of the costs that would have +normally been associated with our lease operating expenses were instead spent on ongoing restoration and repair activities during the year ended December 31, 2006. In addition, lease operating expenses for the year ended December 31, 2007 +increased due to increased labor requirements associated with a ramp up in overall activity in both fields, increases in rates paid for labor and other services, increases in the cost of oil-based supplies, non-recurring repairs including repairs to +compressors, and increases in property taxes in both fields as a result of the on-going capital programs. These increases were partially offset by a reduction in lease operating expenses attributable to our interest in the Marquiss field which we +sold during February 2007. +Production Taxes . Production taxes increased to $12,667,000 for the year ended December 31, 2007 +from $7,366,000 for 2006. This increase was directly related to a 76% increase in oil and gas revenues as a result of the increase in production. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense increased to $29,681,000 for the year ended December 31, 2007, and consisted of $29,220,000 in depletion on oil and natural gas +properties and $461,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $12,652,000 for the year ended December 31, 2006. This increase was due primarily to an increase +in our production, an increase in our oil and natural gas property costs associated with our 2006 and 2007 drilling programs and an increase in our future development costs. +General and Administrative Expenses . Net general and administrative expenses increased to $5,802,000 for 2007 from $3,251,000 for 2006. This +increase was due primarily to increases in payroll costs and related benefits as a result of increases in the total number of employees. In addition, this increase also resulted from $310,000 of costs associated with the implementation of +Section 404 of the Sarbanes-Oxley Act, an increase of $300,000 in franchise taxes, an increase of $220,000 for the services provided by our external reserve engineers, an increase of $100,000 in our business and D&O insurance costs and an +increase of $95,000 for expenses associated with SFAS No. 123(R), “ Share Based Payment. “ These increases were partially offset by an increase in the amount of capitalized general and administrative expenses and a decrease in +legal expenses and corporate fees. +Accretion Expense . Accretion expense decreased to $554,000 for 2007 from $596,000 for 2006. +Although there was a larger obligation at the beginning of 2007 than there was at the beginning of 2006 resulting from the addition of future abandonment obligations on new wells drilled during 2006, the effect of the increase on the larger +obligations was more than offset by the effect of the sale of the Marquiss properties in February 2007. +Interest Expense . Interest +expense increased to $3,091,000 for 2007 from $1,956,000 for 2006 due to an increase in average debt outstanding. Total weighted debt outstanding under our facilities with Bank of America was $33.2 million for the year ended December 31, 2007, +as compared to $18.8 million for 2006. In addition, +39 +Table of Contents +during July 2006 we entered into a new $5.0 million term loan agreement with Bank of America. As a result, during the year ended December 31, 2007, we +recognized a full year of interest related to the term loan in the amount of $382,000 as compared to only $115,000 for 2006. +Income +Taxes . As of December 31, 2007, we had a net operating loss carry forward of approximately $93 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of +our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s +opinion, it is more likely than not that some portion will not be realized. At December 31, 2007, a valuation allowance of $9.8 million had been provided for deferred tax assets. We had only a slight income tax expense of $121,000 during the +year ended December 31, 2007 related to the payment of alternative minimum taxes due for 2006 and 2007. Although we have substantial net operating loss carryforwards, these cannot be used to offset alternative minimum tax liabilities. +Liquidity and Capital Resources +Overview . Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, the issuance of equity securities and borrowings under our bank and other credit facilities. Our ability to +access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and gas production. During the year ended December 31, 2006, recoveries under our insurance coverages also provided a +significant source of funds due to damage from Hurricane Rita in September 2005 and the resulting interruption of our business during the fourth quarter of 2005 and the six months ended June 2006. +Net cash flow provided by operating activities was $135,323,000 for 2008, as compared to $68,902,000 for 2007. The increase of $66,421,000 in 2008 was +primarily the result of the termination in December 2008 of our then existing 2009 fixed price contracts for $39,000,000, an increase in cash receipts from our oil and gas purchasers due to higher prices received for oil production and a 8% increase +in net production, partially offset by increase in cash paid for lease operating expenses and production taxes. +Net cash flow provided by +operating activities was $68,902,000 for 2007, as compared to net cash flow provided by operating activities of $39,523,000 for 2006. This increase was primarily the result of an increase in cash receipts from our oil and gas purchasers due to a 67% +increase in net production, partially offset by increases in cash paid for lease operating expenses and production taxes. +Net cash used in +investing activities for 2008 was $136,823,000, as compared to $240,733,000 for 2007. During the year ended December 31, 2008, we spent $126,030,000 in additions to oil and natural gas properties, of which $77,074,000 was spent on our 2008 +drilling and recompletion program, $27,131,000 was attributable to the wells drilled or recompleted during 2007, $4,665,000 was spent on compressors, $3,200,000 was spent on facilities, $1,148,000 was spent on plugging activities, $1,933,000 was +spent on lease related costs primarily in the Bakken, $1,128,000 was spent on our Belize activities, $841,000 was spent on a new storage barge with the remainder attributable mainly to capitalized general and administrative expenses. In addition, +during the year ended December 31, 2008, we received cash distributions of $862,000 from Tatex Thailand II and we made cash investments of $885,000 in Tatex Thailand III and $10,670,000 in Grizzly. We used cash from operations and borrowings +under our credit facility to fund our investing activities in 2008. +Net cash used in investing activities for 2007 was $240,733,000, as +compared to $73,876,000 for 2006. During the year ended December 31, 2007, we spent $220,044,000 in additions to oil and natural gas properties, of which $96,113,000 was spent on our 2007 drilling program, $85,230,000 was spent on our +acquisition of certain strategic assets in Upton County, Texas in the Permian Basin, $12,319,000 was spent on expenses attributable to the wells drilled during 2006, $9,467,000 was spent on our new Hackberry barge facilities, $2,834,000 was spent on +additions to oil and natural gas properties due to Hurricane Rita, with the remainder attributable mainly to facility enhancement and capitalized general and administrative expenses. During the year +40 +Table of Contents +ended December 31, 2007, we made investments of $17,316,000 in Grizzly. During the year ended December 31, 2007, we used cash from operations, +proceeds from the sale of 8,547,500 shares of our common stock and borrowings under our credit facility to fund our investing activities. +Net cash provided by financing activities for 2008 was $4,680,000, which amount is primarily attributable to $30,000,000 of borrowings under our line of credit, mostly offset by repayments on the line. +Net cash provided by financing activities for 2007 was $167,968,000, as compared to $38,861,000 for 2006. The 2007 amount provided by financing +activities is primarily attributable to borrowings of $76,000,000 under our credit facility with Bank of America and aggregate proceeds of approximately $138,258,000 from the sale of shares of our common stock in February 2007, May +2007, July 2007 and December 2007, after deducting the underwriting discount and offering expenses, and $868,000 from the exercise of stock options. Net proceeds were used to pay down $46,328,000 of outstanding existing debt under our credit +facility with Bank of America, fund substantially all of the purchase price for the acquisition of our interest in certain strategic assets in Upton County, Texas in the Permian Basin and for other general corporate purposes. The 2006 amount +provided by financing activities is attributable to draws of $33,300,000 on our credit facility with Bank of America and proceeds before offering costs of $10,451,000 from the issuance of common stock in our May 2006 underwritten public offering and +$1,276,000 from the exercise of stock options. +Issuance of Equity . In January 2007, we sold 1,150,000 shares of our common stock in +an underwritten offering at an offering price to the public of $11.92 per share. In connection with the offering, we granted the underwriter an option to purchase up to an additional 172,500 shares of our common stock to cover any over-allotments, +which the underwriter exercised in full. We received the net proceeds of approximately $15.3 million from the sale of these shares on February 5, 2007 after deducting the underwriting discount and before offering expenses. These net proceeds +were used to pay down outstanding debt under our credit facility. +In May 2007, we sold 1,500,000 shares of our common stock in an +underwritten offering at an offering price to the public of $16.00 per share. In connection with the offering, we granted the underwriter an option to purchase up to an additional 225,000 shares of our common stock to cover any over-allotments, +which the underwriter exercised in full. We received the net proceeds of approximately $26.8 million from the sale of these shares on May 22, 2007 after deducting the underwriting discount and before offering expenses. These net proceeds were +used to pay down outstanding debt under our credit facility. +In July 2007, we sold 1,000,000 shares of our common stock in an underwritten +offering at an offering price to the public of $22.00 per share. We received the net proceeds of approximately $21.2 million from our sale of these shares on July 25, 2007 after deducting the underwriting discount and before offering expenses. +In December 2007, we sold 4,500,000 shares of our common stock in an underwritten offering at an offering price to the public of $17.50 +per share. We received the net proceeds of approximately $75.6 million from our sale of these shares on December 12, 2007 after deducting underwriting discounts and commissions and before offering expenses. We used the net proceeds from this +offering to fund substantially all of the purchase price for our interest in the acquisition of certain strategic assets in Upton County, Texas in the Permian Basin. In connection with this offering, a selling stockholder granted the underwriters an +option to purchase an additional 675,000 shares of our common stock at a price of $16.80 per share solely to cover any over-allotments, which underwriters exercised in full. We did not receive any proceeds from the sale of shares of our common stock +by the selling stockholder. +Credit Facility . On March 11, 2005, we entered into a three-year secured reducing credit +agreement, as amended, providing for a revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. +On November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount available under the borrowing base +limitation was increased to $30.0 million. Effective July 19, 2007, the credit +41 +Table of Contents +facility increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0 million. In connection with our +acquisition of strategic assets in West Texas in the Permian Basin, effective as of December 20, 2007, our borrowing base under the revolving credit facility increased from $60.0 million to $90.0 million and the Eurodollar interest rate, which +we can elect to use at our option, was reduced by 0.75%. In addition, the maturity date was extended from March 31, 2009 to March 31, 2010. We agreed to pay a borrowing base increase fee of 0.50% of any increase of the borrowing base over +the highest borrowing base previously in effect, payable on the day such increased borrowing base becomes effective. The facility is subject to annual and semi annual redeterminations. We are currently in the process of a redetermination based on +our year-end reserve information and bank pricing decks among other considerations. Preliminary indications from the bank indicate that our borrowing base may be reset at approximately $60.0 million but the exact outcome cannot be predicted at this +time. We make quarterly interest payments on amounts borrowed under the facility, which amounts bear interest at Bank of America prime plus 0.5% (3.75% at December 31, 2008). Our obligations under the credit facility are collateralized by a +lien on substantially all of our Louisiana and West Texas oil and gas assets. +The credit facility contains certain affirmative and +negative covenants, including, but not limited to the following financial covenants: (a) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding unrealized gains and losses related to trading securities and +commodity hedges, plus depreciation, depletion, amortization and interest expense, plus exploration costs deducted in determining net income under full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the +ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with all covenants at December 31, 2008. As of December 31, 2008, approximately $64.5 million was outstanding under +this facility, which is included in long-term debt, net of current maturities on the accompanying consolidated balance sheet. As of February 28, 2009, approximately $59.0 million was outstanding under this facility. We have used the proceeds of +our borrowings under the credit facility for the exploration of our oil and natural gas properties and other capital expenditures, acquisition opportunities, replacement of facilities and equipment due to Hurricanes Rita and for other general +corporate purposes. +On July 10, 2006, we entered into a $5.0 million term loan agreement with Bank of America, N.A. related to the +purchase of new gas compressor units. The loan began amortizing quarterly on March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. Amounts borrowed bear interest at Bank +of America prime (3.25% at December 31, 2008). We make quarterly interest payments on amounts borrowed under the agreement. Our obligations under the agreement are collateralized by a lien on the compressor units. As of December 31, 2008, +approximately $3.6 million was outstanding under this agreement, of which $714,000 and $2,874,000 are included in current maturities of long-term debt and long-term debt, net of current maturities, respectively, on our accompanying consolidated +balance sheet. +Building Loans . We had three loans associated with two of our buildings. One loan, in the original principal amount +of $115,000, related to a building in Lafayette, Louisiana, that we purchased in 1996 to be used as our Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. We repaid this loan in full during the third quarter of +2007. In addition, in June 2004 we purchased the office building we occupy in Oklahoma City, Oklahoma for $3.7 million. One of the two loans associated with this building, with an original principal amount of $389,000, matured in March 2006 and bore +interest at a rate of 6% per annum. The other loan associated with this building, with an original principal amount of $3.0 million, matures in June 2011 and bears interest at a rate of 6.5% per annum. As of December 31, 2008, +approximately $2.6 million was outstanding on this loan. The remaining building loan requires monthly interest and principal payments and is collateralized by the respective land and buildings. +Capital Expenditures . Our recent capital commitments have been primarily for the development of our proved reserves, to increase our net acreage +position in Grizzly and fund Grizzly’s delineation drilling program and for acquisitions, primarily our acquisition in the Permian Basin in December 2007. Our strategy, subject to economic and industry conditions, is to continue to +(1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, +42 +Table of Contents +subject to economic and industry conditions, and (2) explore acquisition and disposition opportunities. We have upgraded our infrastructure and our +existing facilities in Southern Louisiana with the goal of increasing operating efficiencies and volume capacities and lowering lease operating expenses. These upgrades were also intended to better enable our facilities to withstand future +hurricanes with less damage. Additionally, we completed the reprocessing of 3-D seismic data in one of our principal properties, WCBB. The reprocessed data enables our geophysicists to continue to generate new prospects and enhance existing +prospects in the intermediate zones in the field, thus creating a portfolio of new drilling opportunities. In addition, with our acquisition of strategic assets in the Permian Basin in West Texas, we are required to pay 50% of all drilling costs for +drilling activity on such properties. To combat significant declines in the commodity prices during the second half of 2008, management undertook a series of actions aimed at reducing capital spending and operating costs. As a result, we reduced our +drilling and other capital activities to a minimum in the fourth quarter of 2008, releasing all rigs in Southern Louisiana and the Permian and only selectively participating in wells in the Bakken. During 2009, we are not bound by lease obligations +and long term capital commitments relating to the exploration or development of our oil and gas properties. In addition, we have reduced our estimated capital activities and aggressively sought price concessions from our service providers and have +recently received indications of 20% to 25% in cost reductions and believe an additional 10% to 20% in reduction may be possible. +In our +December 31, 2008 reserve reports, 67.5% of our net reserves were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development +activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those +activities. +Our inventory of prospects includes approximately 81 drilling locations at WCBB. The drilling schedule used in our +December 31, 2008 reserve report anticipates that all of those wells will be drilled by 2019. From January 1, 2009 through March 1, 2009, we recompleted seven existing wells at our WCBB field. We currently intend to spend a total of +approximately $7.5 to $8.5 million to drill four wells and recomplete 20 wells in our WCBB field during 2009. +In our East Hackberry field, +from January 1, 2009 through March 1, 2009, we recompleted three wells. We intend to drill four additional land wells during 2009. Total capital expenditures for our East Hackberry field during 2009 are estimated at $4.5 to $5.5 million. +We currently anticipate that our capital requirements for our properties in the Permian Basin in West Texas will be approximately $2.0 to +$2.5 million during 2009. We have identified 147 gross (73.5 net) future development drilling locations. We currently expect that approximately 1.5 net wells will be drilled on this acreage in 2009 at estimated average gross completed gross well +cost of $1.34 million. +During the third quarter of 2006, we purchased a 24.9999% interest in Grizzly. As of December 31, 2008, our +net investment in Grizzly was approximately $21.9 million. Capital requirements in 2009 for this project are estimated to be approximately $4.3 million, primarily for the expenses associated with the drilling of 15 well core holes during +Grizzly’s 2008/2009 drilling program. +Capital expenditures in 2009 relating to our interest in Thailand are expected to be +approximately $1.0 million, which we believe will be mostly offset from our share of production from the Phu Horm field. +Capital +expenditures in 2009 relating to our interest in the Bakken Shale in the Williston Basin are expected to be approximately $2.5 million, which we believe will be partially offset from our share of production from the field. +Our total capital expenditures for 2009 are currently estimated to be $22 million. This is down significantly from $95 million in 2008 due to the current +commodity pricing and cost environment. In response to the +43 +Table of Contents +challenging economic conditions, we have for now reduced drilling and other capital activities to a minimum in 2009 and released all rigs in Southern +Louisiana and the Permian and intend to participate selectively in wells in the Bakken. In addition, through our cost reduction initiative, we have already received indications of 20% to 25% in cost reductions and we are targeting an additional 10% +to 20% reduction. We intend to monitor pricing and cost developments and make adjustments to our capital expenditure program as warranted. +We believe that our cash on hand, cash flow from operations and availability under our credit facility, if any, will be sufficient to meet our normal recurring operating needs, debt service obligations, and our WCBB, Hackberry, Bakken, +Permian Basin and Grizzly capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling programs, pursue acquisitions or accelerate our Canadian oil sands project, we may be required to obtain +additional funds which we may do so through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. Needed capital may not be available to us on acceptable terms or at all. If we are unable to +obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. +Commodity Price Risk +To mitigate the effects of +commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500 barrels of WCBB production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered +approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel +before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at +a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We have also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted +average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. For the period January 2010 through February 2010 we have entered into forward sales contracts for the sale of 3,000 barrels of +WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB +production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these contracts, we have committed to deliver approximately 50% of our estimated 2009 production. Such arrangements may expose us to risk +of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. Since these contracts require physical delivery of production quantities, they normally would be exempted from the +provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008, we will not be able to apply this election on new contracts and they will be accounted for at fair value until we +re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +Commitments +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB +properties, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing +March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges +associated with the property. As of December 31, 2008, the plugging and abandonment trust totaled approximately $3,144,000 including interest received during 2008 of approximately $45,000. At December 31, 2008, we had plugged 273 wells at +WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. +44 +Table of Contents +Contractual and Commercial Obligations +Payment due by period (1) +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +Short-term and long-term debt +$ +70,731,000 +$ +815,000 +$ +69,185,000 +$ +731,000 +$ +— +Asset retirement obligations +9,269,000 +635,000 +1,200,000 +816,000 +6,618,000 +Total +$ +80,000,000 +$ +1,450,000 +$ +70,385,000 +$ +1,547,000 +$ +6,618,000 +(1) +Does not include estimated interest of $2,496,000 less than one year, $7,052,000 1-3 years, and $2,223,000 3-5 years. +New Accounting Pronouncements +Effective +January 1, 2008, we implemented FASB SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We +elected to implement this Statement with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring +basis. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties; plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations +and restructuring costs for which fair value is used. We are currently assessing the impact, if any, of FSP No. FAS 157-2 in relation to nonfinancial assets and nonfinancial liabilities. The adoption of the provisions of SFAS No. 157 did not +have a material impact on our consolidated financial statements. +In February 2007, the FASB issued SFAS No. 159, “ The Fair +Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair +value. The objective is to improve financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge +accounting provisions. Unrealized gains and losses on any items for which we elect the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We adopted +SFAS No. 159 effective January 1, 2008. The adoption did not have a material impact on our consolidated financial statements. +In +December 2007, the FASB issued SFAS No. 141 (revised 2007), “ Business Combinations ” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer +recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS 141(R) also establishes disclosure requirements that will +enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. We are currently assessing the +impact, if any; the adoption of SFAS 141(R) may have on any future acquisitions. +In December 2007, the FASB issued SFAS No. 160, +“ Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51 .” SFAS No. 160 requires that accounting and reporting for minority interest will be recharacterized as noncontrolling interest and +classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling +owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries +or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. We are currently assessing the impact, if any, of the adoption of SFAS No. 160. +45 +Table of Contents +In March 2008, the FASB issued SFAS No. 161, “ Disclosures about Derivative Instruments and +Hedging Activities—an amendment of FASB Statement No. 133 .” SFAS No. 161 requires enhanced disclosures for derivative and hedging activities, including (a) how and why an entity uses derivative instruments, (b) how +derivative instruments and related hedged items are accounted for under SFAS No. 133 and related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of +operations, and cash flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently assessing the impact, if any, of the adoption of SFAS No. 161. +In May 2008, the FASB issued SFAS No. 162, “ The Hierarchy of Generally Accepted Accounting Principles .” SFAS +No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted +accounting principles (GAAP) in the United States of America (the GAAP hierarchy). This statement was effective November 15, 2008 (60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU +Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles) . The adoption of SFAS No. 162 did not have a material impact to our financial statements. +In December 2008, the Securities and Exchange Commission published a Final Rule, “ Modernization of Oil and Gas Reporting .” The new rule +permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and +possible reserves. In addition, the new disclosure requirements require companies to (a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or +conducts a reserve audit, and (c) report oil and gas reserves using an average price based upon the prior 12 month period rather than year end prices. The use of average prices will impact future impairment and depletion calculations. The new +requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted in quarterly reports prior to the first annual report in which the revised disclosures are +required. We are currently assessing the impact of this Final Rule. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices +have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and +expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can +affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability +of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production +controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +These +factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate posted price for crude oil has ranged from a low of +$30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $3.53 per million British thermal units, or MMBtu, in September 2006 to a high of $15.52 +per MMBtu in January 2006. On December 31, 2008, the West Texas Intermediate posted price for crude oil was $44.60 per bbl and the Henry Hub spot market price +46 +Table of Contents +of natural gas was $5.63 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, +financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500 barrels of WCBB +production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had entered into +agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. +Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We have +also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. For the period +January 2010 through February 2010 we have entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 +through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these contracts, we have +committed to deliver approximately 50% of our estimated 2009 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. Since +these contracts require physical delivery of production quantities, they normally would be exempted from the provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008, we +will not be able to apply this election on new contracts and they will be accounted for at fair value until we re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of +increases in the price of oil. +Our credit facility and term loan with Bank of America are structured under floating rate terms and, as +such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. Borrowings under our revolving credit facility with Bank of America bear interest at Bank of America prime plus 0.5% (3.75% at December 31, 2008). Borrowings +under our term loan with Bank of America bear interest at Bank of America prime (3.25% at December 31, 2008). Based on the current debt structure, a 1% increase in interest rates would increase interest expense by approximately $681,000 per +year, based on an aggregate of $68.1 million outstanding under our credit facilities as of December 31, 2008. As of December 31, 2008, we did not have any interest rate swaps to hedge our interest risks. +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The +information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +47 +Table of Contents +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of +Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to +be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and +procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding +required disclosures. +As of December 31, 2008, an evaluation was performed under the supervision and with the participation of +management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act +of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2008, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that +occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation +of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the +Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the +preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal +control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted +an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its +evaluation under the framework in Internal Control—Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was +effective as of December 31, 2008. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial +statements for the year ended December 31, 2008 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2008, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +48 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of +December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is +responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over +Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control +over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and +operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the +preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation +of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and +(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of +effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of +December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We have also audited, in +accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2008 and 2007, and the related consolidated +statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 16, 2009 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 16, 2009 +ITEM 9B. +OTHER INFORMATION +None. +49 +Table of Contents +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our +previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning +Item 11—Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference +(with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our +definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that +are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange +Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For +information concerning Item 14—Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is +incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +50 +Table of Contents +PART IV +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +List +the following documents filed as part of this report: +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian +(incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor +Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the +SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on +July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited +partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party +thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other +affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +51 +Table of Contents +Exhibit +Number +Description +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Registrant and Mike Liddell (incorporated by reference to Exhibit 10.5 of Amendment No. 1 +to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5 +Credit Agreement, dated as of March 11, 2005, by and among the Company, each lender from time to time party thereto and Bank of America, N.A., as agent (incorporated by reference to Exhibit +10.9 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +10.6 +Second Amendment to Credit Agreement, dated as of July 19, 2007, between the Company and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, +filed by the Company with the SEC on July 19, 2007). +10.7 +Note dated July 19, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company with +the SEC on July 19, 2007). +10.8 +Third Amendment to Credit Agreement, dated as of December 20, 2007, between the Company, Bank of America, N.A., as a lender and administrative agent and such other lenders from time to time +party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2007). +10.9 +Note dated December 20, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company +with the SEC on December 26, 2007). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +52 +Table of Contents +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, +thereunto duly authorized. +Date: March 16, 2009 +G ULFPORT E NERGY C ORPORATION +By: +/ S / J AMES D. +P ALM +James D. Palm +Chief Executive Officer +In accordance with the Exchange Act, this report has been signed below by the following +persons on behalf of the registrant and in the capacities and on the dates indicated. +Date: March 16, 2009 +By: +/ S / J AMES D. +P ALM +James D. Palm +Chief Executive Officer and Director +(Principal Executive Officer) +Date: March 16, 2009 +By: +/ S / M IKE +L IDDELL +Mike Liddell +Chairman of the Board and Director +Date: March 16, 2009 +By: +/ S / M ICHAEL G. +M OORE +Michael G. Moore +Vice President and Chief Financial Officer +(Principal Financial and Accounting +Officer) +Date: March 16, 2009 +By: +/ S / D ONALD +D ILLINGHAM +Donald Dillingham +Director +Date: March 16, 2009 +By: +/ S / D AVID L. +H OUSTON +David L. Houston +Director +Date: March 16, 2009 +By: +/ S / S COTT E. +S TRELLER +Scott E. Streller +Director +S-1 +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +I NDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets, December 31, 2008 and December 31, 2007 +F-3 +Consolidated Statements of Operations, Years Ended December 31, 2008, 2007 and 2006 +F-4 +Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss), Years Ended December +31, 2008, 2007 and 2006 +F-5 +Consolidated Statements of Cash Flows, Years Ended December 31, 2008, 2007 and 2006 +F-6 +Notes to Financial Statements +F-7 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of +December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008. These financial +statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the +financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles +used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation +and Subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in +the United States of America. +We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), +Gulfport Energy Corporation and Subsidiaries’ internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring +Organizations of the Treadway Commission (COSO) and our report dated March 16, 2009 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 16, 2009 +F-2 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +(Amounts +rounded to nearest thousand) +December 31, +2008 +December 31, +2007 +Assets +Current assets: +Cash and cash equivalents +$ +5,944,000 +$ +2,764,000 +Accounts receivable—oil and gas +12,543,000 +10,510,000 +Accounts receivable—related parties +1,101,000 +2,208,000 +Prepaid expenses and other current assets +1,045,000 +1,346,000 +Total current assets +20,633,000 +16,828,000 +Property and equipment: +Oil and natural gas properties, full-cost accounting, $22,543,000 and $37,278,000 excluded from amortization in 2008 and 2007, respectively +599,761,000 +484,487,000 +Other property and equipment +7,168,000 +7,108,000 +Accumulated depletion, depreciation, amortization and impairment +(444,690,000 +) +(129,496,000 +) +Property and equipment, net +162,239,000 +362,099,000 +Other assets: +Equity investments +25,440,000 +33,822,000 +Other assets +3,755,000 +6,388,000 +Note receivable—related party +9,153,000 +— +Total other assets +38,348,000 +40,210,000 +Deferred tax asset +653,000 +— +Total assets +$ +221,873,000 +$ +419,137,000 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +27,772,000 +$ +39,848,000 +Asset retirement obligation—current +635,000 +480,000 +Current maturities of long-term debt +815,000 +808,000 +Total current liabilities +29,222,000 +41,136,000 +Asset retirement obligation—long-term +8,634,000 +8,154,000 +Long-term debt, net of current maturities +69,916,000 +65,725,000 +Total liabilities +107,772,000 +115,015,000 +Commitments and contingencies (Notes 18 and 19) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and +outstanding +— +— +Stockholders’ equity: +Common stock—$.01 par value, 55,000,000 authorized, 42,639,201 issued and outstanding in 2008 and 42,453,587 in 2007 +426,000 +424,000 +Paid-in capital +273,343,000 +271,807,000 +Accumulated other comprehensive income (loss) +(4,803,000 +) +2,254,000 +Retained earnings (accumulated deficit) +(154,865,000 +) +29,637,000 +Total stockholders’ equity +114,101,000 +304,122,000 +Total liabilities and stockholders’ equity +$ +221,873,000 +$ +419,137,000 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2008 +2007 +2006 +Revenues: +Oil and condensate sales +$ +131,825,000 +$ +100,120,000 +$ +56,038,000 +Gas sales +6,570,000 +6,043,000 +4,194,000 +Natural gas liquid sales +3,255,000 +— +— +Other income (expense) +(433,000 +) +(325,000 +) +158,000 +141,217,000 +105,838,000 +60,390,000 +Costs and expenses: +Lease operating expenses +22,856,000 +16,670,000 +10,670,000 +Production taxes +15,813,000 +12,667,000 +7,366,000 +Depreciation, depletion, and amortization +42,472,000 +29,681,000 +12,652,000 +Impairment of oil and gas properties +272,722,000 +— +— +General and administrative +6,843,000 +5,802,000 +3,251,000 +Accretion expense +560,000 +554,000 +596,000 +361,266,000 +65,374,000 +34,535,000 +INCOME (LOSS) FROM OPERATIONS +(220,049,000 +) +40,464,000 +25,855,000 +OTHER (INCOME) EXPENSE: +Interest expense +4,762,000 +3,091,000 +1,956,000 +Settlement of fixed price contracts +(39,000,000 +) +— +— +Business interruption insurance recoveries +— +— +(3,601,000 +) +Insurance proceeds +(769,000 +) +— +— +Interest income +(540,000 +) +(523,000 +) +(308,000 +) +(35,547,000 +) +2,568,000 +(1,953,000 +) +INCOME (LOSS) BEFORE INCOME TAXES +(184,502,000 +) +37,896,000 +27,808,000 +INCOME TAX EXPENSE +— +121,000 +— +NET INCOME (LOSS) +$ +(184,502,000 +) +$ +37,775,000 +$ +27,808,000 +NET INCOME (LOSS) PER COMMON SHARE: +Basic +$ +(4.33 +) +$ +1.03 +$ +0.85 +Diluted +$ +(4.33 +) +$ +1.01 +$ +0.82 +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND +COMPREHENSIVE INCOME (LOSS) +(Amounts rounded to nearest thousand) +Common Stock +Additional +Paid-in +Capital +Accumulated +Other +Comprehensive +Income (Loss) +Retained +Earnings +(Accumulated +Deficit) +Total +Stockholders’ +Equity +Shares +Amount +Balance at January 1, 2006 +32,168,203 +$ +322,000 +$ +119,192,000 +$ +759,000 +$ +(35,946,000 +) +$ +84,327,000 +Net income +— +— +— +— +27,808,000 +27,808,000 +Other Comprehensive Income: +Deferred gain on settled contracts +— +— +— +(114,000 +) +— +(114,000 +) +Gain on hedging ineffectiveness +— +— +— +(24,000 +) +— +(24,000 +) +Reclassification adjustment on settled hedges +— +— +— +(621,000 +) +— +(621,000 +) +Total Comprehensive Income +27,049,000 +Stock Compensation +— +— +1,063,000 +— +— +1,063,000 +Issuance of Common Stock in public offering, net of related expenses of $479,000 +790,000 +8,000 +9,965,000 +— +— +9,973,000 +Issuance of Restricted Stock +21,981 +— +— +— +— +— +Issuance of Common Stock through exercise of Warrants +113,852 +1,000 +120,000 +— +— +121,000 +Issuance of Common Stock through exercise of Options +565,723 +6,000 +1,270,000 +— +— +1,276,000 +Balance at December 31, 2006 +33,659,759 +337,000 +131,610,000 +— +(8,138,000 +) +123,809,000 +Net income +— +— +— +— +37,775,000 +37,775,000 +Other Comprehensive Income: +Foreign currency translation adjustment +— +— +— +2,254,000 +— +2,254,000 +Total Comprehensive Income +40,029,000 +Stock Compensation +— +— +1,158,000 +— +— +1,158,000 +Issuance of Common Stock in public offerings, net of related expenses of $740,000 +8,547,500 +85,000 +138,173,000 +— +— +138,258,000 +Issuance of Restricted Stock +35,930 +— +— +— +— +— +Issuance of Common Stock through exercise of options +210,398 +2,000 +866,000 +— +— +868,000 +Balance at December 31, 2007 +42,453,587 +424,000 +271,807,000 +2,254,000 +29,637,000 +304,122,000 +Net loss +— +— +— +— +(184,502,000 +) +(184,502,000 +) +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +(7,057,000 +) +— +(7,057,000 +) +Total Comprehensive Income (Loss) +(191,559,000 +) +Stock Compensation +— +— +1,056,000 +— +— +1,056,000 +Issuance of Restricted Stock +41,493 +— +— +— +— +— +Issuance of Common Stock through exercise of options +144,121 +2,000 +480,000 +— +— +482,000 +Balance at December 31, 2008 +42,639,201 +$ +426,000 +$ +273,343,000 +$ +(4,803,000 +) +$ +(154,865,000 +) +$ +114,101,000 +See accompanying notes to consolidated financial statements. +F-5 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2008 +2007 +2006 +Cash flows from operating activities: +Net income (loss) +$ +(184,502,000 +) +$ +37,775,000 +$ +27,808,000 +Adjustments to reconcile net income to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +560,000 +554,000 +596,000 +Depletion, depreciation and amortization +42,472,000 +29,681,000 +12,652,000 +Impairment of oil and gas properties +272,722,000 +— +— +Stock-based compensation expense +634,000 +845,000 +787,000 +Loss from equity investments +656,000 +477,000 +76,000 +Interest income—note receivable +(410,000 +) +— +— +Deferred income tax benefit +(653,000 +) +— +— +Unrealized gain on hedge ineffectiveness +— +— +(24,000 +) +Changes in operating assets and liabilities: +Increase in accounts receivable +(2,033,000 +) +(2,925,000 +) +(6,609,000 +) +Decrease in business interruption insurance settlement receivable +— +— +1,710,000 +Decrease (increase) in accounts receivable—related party +1,107,000 +1,994,000 +(832,000 +) +Decrease (increase) in prepaid expenses +301,000 +(374,000 +) +(490,000 +) +Decrease in deposits +— +— +107,000 +Increase in accounts payable and accrued liabilities +5,328,000 +2,153,000 +4,608,000 +Increase in deferred hedge gains +— +— +(114,000 +) +Settlement of asset retirement obligation +(859,000 +) +(1,278,000 +) +(752,000 +) +Net cash provided by operating activities +135,323,000 +68,902,000 +39,523,000 +Cash flows from investing activities: +Additions to cash held in escrow +(40,000 +) +(121,000 +) +(105,000 +) +Additions to deposits for oil and gas properties +— +(3,080,000 +) +— +Additions to other property, plant and equipment +(60,000 +) +(457,000 +) +(495,000 +) +Additions to oil and gas properties +(126,030,000 +) +(220,044,000 +) +(62,403,000 +) +Proceeds from sale of oil and gas properties +— +500,000 +— +Note receivable—related party +(10,519,000 +) +— +— +Investment in Grizzly Oil Sands ULC +(151,000 +) +(17,316,000 +) +(8,493,000 +) +Investment in Tatex Thailand II, LLC +862,000 +(88,000 +) +(964,000 +) +Investment in Tatex Thailand III, LLC +(885,000 +) +— +— +Investment in Windsor Bakken, LLC +— +(127,000 +) +(1,416,000 +) +Net cash used in investing activities +(136,823,000 +) +(240,733,000 +) +(73,876,000 +) +Cash flows from financing activities: +Principal payments on borrowings +(25,802,000 +) +(47,158,000 +) +(10,809,000 +) +Borrowings on line of credit +30,000,000 +76,000,000 +38,300,000 +Proceeds from issuance of common stock, net of offering costs of $740,000 and $479,000 for 2007 and 2006, respectively, and exercise of stock +options +482,000 +139,126,000 +11,370,000 +Net cash provided by financing activities +4,680,000 +167,968,000 +38,861,000 +Net increase (decrease) in cash and cash equivalents +3,180,000 +(3,863,000 +) +4,508,000 +Cash and cash equivalents at beginning of period +2,764,000 +6,627,000 +2,119,000 +Cash and cash equivalents at end of period +$ +5,944,000 +$ +2,764,000 +$ +6,627,000 +Supplemental disclosure of cash flow information: +Interest payments +$ +4,898,000 +$ +3,341,000 +$ +1,956,000 +Income tax payments +$ +135,000 +$ +121,000 +$ +— +Supplemental disclosure of non-cash transactions: +Investment subscription payable +$ +— +$ +151,000 +$ +— +Capitalized stock based compensation +$ +422,000 +$ +313,000 +$ +276,000 +Asset retirement obligation capitalized +$ +934,000 +$ +500,000 +$ +405,000 +Dissolution of interest in Windsor Bakken, LLC +$ +2,468,000 +— +— +Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC +$ +(5,281,000 +) +$ +2,254,000 +— +Foreign currency translation gain (loss) on note receivable—related party +$ +(1,776,000 +) +— +— +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development +and production company with its principal properties located in the Louisiana Gulf Coast and in West Texas in the Permian Basin and has investments in companies operating in Canada and Thailand. +Cash and Cash Equivalents +The Company considers all +highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries, +Grizzly Holdings Inc. and Jaguar Resources LLC. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its +receivables are from two purchasers of the Company’s oil and gas and one operator of certain of the Company’s properties. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not +required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment +terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to +pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when +they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2008 and December 31, 2007. +Oil and Gas Properties +The Company uses the full +cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are +capitalized. Net capitalized costs are limited to the estimated future net revenues, based on year-end prices and costs as adjusted for the Company’s cash flow hedge positions and net of tax effects, discounted at 10% per year, from proven +oil and gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent +units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship +between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $22,543,000 and $37,278,000 at December 31, 2008 and December 31, 2007, +respectively. These costs are reviewed quarterly by management for impairment. If an impairment has +F-7 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered +by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. +The Company accounts for its abandonment and restoration liabilities under Statement of Financial Accounting Standards No. 143, “ Accounting +for Asset Retirement Obligations ” (“SFAS No. 143”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period +in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount +equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the +liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment is provided on a +straight-line basis over estimated useful lives of the related assets, which range from 3 to 30 years. +Foreign Currency +The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity +whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are +translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. +Net Income per Common Share +Basic net income per +common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or +other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in +Note 14. +Income Taxes +Gulfport uses +the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the +tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are +expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which +realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. +F-8 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +Revenue Recognition +Gas +revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If +less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. There is no such liability or asset recorded at December 31, 2008 and 2007 because the Company has no imbalances. Oil revenues are recognized +when ownership transfers, which occurs in the month produced. +Investments—Equity Method +Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, the Company’s share of +investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company +recognizes an impairment provision. There was no impairment of equity method investments at December 31, 2008 or 2007. +Accounting for Stock-Based +Compensation +Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123(R), +“ Share-Based Payment ” (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires share-based payments to employees, including grants of employee stock options, to be +recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, +2006, are recognized as compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No +retroactive or cumulative effect adjustments were required upon the Company’s adoption of SFAS No. 123(R) (see Note 10). The shares of stock issued once the options are exercised will be from authorized but unissued common stock. +Accounting for Derivative Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy swaps and collars (collectively “price swap contracts”). The Company follows the provisions of SFAS 133, +“ Accounting for Derivative Instruments and Hedging Activities,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. +The Company estimates the fair value of all derivative instruments using established index prices and other sources. These values are +based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values reported in the consolidated financial statements change as these estimates are +revised to reflect actual results, changes in market conditions or other factors. +Accounting for changes in the fair value of a derivative +depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness +guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between +F-9 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The +Company had no derivative contracts at December 31, 2008 and 2007. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to +make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those +estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset +retirement obligations and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and +impairment of oil and gas properties. +Recent Accounting Pronouncements +Effective January 1, 2008, the Company implemented FASB SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines +fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. The Company elected to implement this Statement with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial +assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis. The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired +properties; plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which fair value is used. The Company is currently assessing the impact, if any, of FSP No. FAS +157-2 in relation to nonfinancial assets and nonfinancial liabilities. The adoption of the provisions of SFAS No. 157 did not have a material impact on the Company’s consolidated financial statements. +In February 2007, the FASB issued SFAS No. 159, “ The Fair Value Option for Financial Assets and Financial Liabilities—Including an +Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing companies +with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which the +Company elects the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company adopted SFAS No. 159 effective January 1, 2008. The +adoption did not have a material impact on the Company’s consolidated financial statements. +In December 2007, the FASB issued SFAS +No. 141 (revised 2007), “ Business Combinations ” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its +financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS 141(R) also establishes disclosure requirements that will enable users to evaluate the +nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. The Company is currently assessing the impact, if any, the +adoption of SFAS 141(R) may have on any future acquisitions. +F-10 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +In December 2007, the FASB issued SFAS No. 160, “ Noncontrolling Interests in Consolidated Financial +Statements-an amendment of ARB No. 51 .” SFAS No. 160 requires that accounting and reporting for minority interest will be recharacterized as noncontrolling interest and classified as a component of equity. SFAS No. 160 also +establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare +consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective +as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company is currently assessing the impact, if any, of the adoption of SFAS No. 160. +In March 2008, the FASB issued SFAS No. 161, “ Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB +Statement No. 133 .” SFAS No. 161 requires enhanced disclosures for derivative and hedging activities, including (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged +items are accounted for under SFAS No. 133 and related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. This statement is +effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently assessing the impact, if any, of the adoption of SFAS No. 161. +In May 2008, the FASB issued SFAS No. 162, “ The Hierarchy of Generally Accepted Accounting Principles .” SFAS No. 162 +identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting +principles (GAAP) in the United States of America (the GAAP hierarchy). This statement was effective November 15, 2008 (60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU +Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles) . The adoption of SFAS No. 162 did not have a material impact to the Company’s financial statements. +In December 2008, the Securities and Exchange Commission published a Final Rule, “ Modernization of Oil and Gas Reporting .” The new rule +permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and +possible reserves. In addition, the new disclosure requirements require companies to (a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or +conducts a reserve audit, and (c) report oil and gas reserves using an average price based upon the prior 12 month period rather than year end prices. The use of average prices will impact future impairment and depletion calculations. The new +requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted in quarterly reports prior to the first annual report in which the revised disclosures are +required. The Company is currently assessing the impact of this Final Rule. +2. +ACQUISITIONS +On December 20, 2007, Gulfport +closed on the acquisition of an ownership interest in certain oil and gas properties located in the Permian Basin of West Texas, consisting of approximately 4,100 net acres with 32 gross producing wells from ExL Petroleum, LP and 12 other sellers. +The effective date of the acquisition was November 1, 2007. The total purchase price for the assets, as adjusted at the original closing on December 20, 2007, was $85.2 million, which was recorded as oil and natural gas properties on the +accompanying balance +F-11 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +sheet. This amount includes an adjustment for the results of operations of the assets between the November 1, 2007 effective date and the +December 20, 2007 closing date. The final post closing adjustments occurred 90 days from the original closing date of December 20, 2007, or March 20, 2008, and the purchase price was adjusted accordingly. The total adjusted purchase +price for the assets was $83.8 million. +Gulfport funded this transaction predominately through a 4.5 million common share offering, +which closed on December 12, 2007. The Company received net proceeds of approximately $75.6 million from the equity offering, as discussed in Note 9. The Company funded the remainder of the purchase price from borrowings under its line of +credit. +The following unaudited pro forma results for the year ended December 31, 2006 show the effect on the Company’s +consolidated results of operations as if the acquisition had occurred on January 1, 2006. The unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company’s consolidated results of operations as if +the acquisition had occurred on January 1, 2007. The pro forma results for the 2006 and 2007 periods presented are the result of combining the Company’s consolidated statements of operations with the revenues and direct operating expenses +of the acquired properties adjusted for (1) incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the acquisition, amortized on a unit-of-production basis over the remaining life of total proved +reserves, as applicable, (2) incremental accretion of discount on asset retirement obligation associated with the acquired properties, (3) estimated incremental interest expenses associated with borrowings under Gulfport’s revolving +credit facility to fund the acquisitions, and (4) the issuance of 4.5 million shares of common stock in the offering at January 1, 2006 and January 1, 2007 rather than December 12, 2007. The pro forma information is based +upon numerous assumptions, and is not necessarily indicative of what the Company’s actual results would have been or the Company’s future results of operations. +Unaudited +Year Ended December 31, +2007 +2006 +Total revenue +$ +121,903,000 +$ +64,458,000 +Net income +46,799,000 +29,029,000 +Net income per common share: +Basic +$ +1.14 +$ +0.78 +Diluted +$ +1.12 +$ +0.76 +3. +HURRICANE INSURANCE +The Company sustained damage +to both its Hackberry fields located in Cameron Parish, Louisiana and its West Cote Blanche Bay (“WCBB”) field located in St. Mary Parish, Louisiana as a result of Hurricane Rita in September 2005. The Company maintained business +interruption insurance to cover lost production revenue in the event of shut-in production. The business interruption insurance began 60 days after the occurrence of the insurable event, subject to a daily limit of $45,000 and had a maximum coverage +of 180 days. Coverage began on November 24, 2005 for shut-in production caused by Hurricane Rita. For the year ended December 31, 2006, the Company recognized $3,601,000 of business interruption insurance proceeds in other income in the +consolidated statements of operations. As of December 31, 2006, the Company had received proceeds of $5,311,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period of November 24, 2005 to May 1, +2006. Such recoveries are presented as operating cash flows in the consolidated statements of cash flows. All business interruption recoveries were collected in 2006. +F-12 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +4. +ACCOUNTS RECEIVABLE—RELATED PARTIES +Included +in the accompanying December 31, 2008 and December 31, 2007 consolidated balance sheets are amounts receivable from affiliates of the Company. These receivables represent amounts billed by the Company for general and administrative +functions, such as accounting, human resources, legal, and technical support, performed by Gulfport’s personnel on behalf of the affiliates. These services are solely administrative in nature and for entities in which the Company has no +property interests. The amounts reimbursed to the Company for these services are for the purpose of Gulfport recovering costs associated with the services and do not include the assessment of any fees or other amounts beyond the estimated costs of +performing such services. At December 31, 2008 and December 31, 2007, these receivables totaled $1,101,000 and $2,208,000, respectively. The Company was reimbursed $1,363,000, $11,153,000 and $12,738,000 for the years ended +December 31, 2008, 2007 and 2006, respectively, for general and administrative functions which are reflected as a reduction of general and administrative expenses in the consolidated statements of operations and include the amounts under +service contracts discussed below. +The Company is or has been a party to administrative service agreements with Caliber Development +Company, LLC, Bronco Drilling Company, Inc., Great White Energy Services LLC, and Diamondback Energy Services LLC. Under these agreements, the Company’s services include accounting, human resources, legal and technical support. The services +provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a three-year term, and upon expiration of that term the agreements will continue on a month-to-month basis +until cancelled by either party with at least 30 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to the Company and (2) by either +party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. +The Company is also a party to administrative service agreements with Stampede Farms LLC, Grizzly Oil Sands ULC, Everest Operations Management LLC and Tatex Thailand III, LLC. Under these agreements, the Company’s services include +professional and technical support and office space. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a two-year term, and upon expiration of +that term such agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at least 60 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any +time with at least 30 days prior written notice to the Company and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. +F-13 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +The Company was reimbursed the following amounts by the specified entities in consideration for its administrative services +for the years ended December 31, 2008, 2007 and 2006. These amounts are reflected as a reduction of general and administrative expenses in the consolidated statements of operations. Wexford Capital LLC (“Wexford”) controls and/or owns +a greater than 10% interest in each of these entities. Affiliates of Wexford own approximately 36% of Gulfport’s outstanding stock. +Agreement +Effective Date +Entity +December 31, +2008 +2007 +2006 +2/9/2005 +Caliber Development Company, LLC** +$ +60,000 +$ +1,249,000 +$ +431,000 +4/1/2005 +Bronco Drilling Company, Inc. * +— +— +49,000 +7/22/2006 +Great White Energy Services LLC +83,000 +754,000 +2,222,000 +9/26/2006 +Diamondback Energy Services LLC** +10,000 +17,000 +823,000 +3/1/2008 +Stampede Farms LLC +159,000 +123,000 +— +3/1/2008 +Grizzly Oil Sands ULC +368,000 +953,000 +198,000 +3/1/2008 +Everest Operations Management LLC +154,000 +— +— +3/1/2008 +Tatex Thailand III, LLC +— +— +— +* +Agreement was terminated effective April 1, 2006. +** +Agreement was terminated effective December 10, 2008. +For the year ended December 31, 2008, the Company was also reimbursed approximately $20,000 and $26,000 by Stampede Farms LLC and Everest Operations Management LLC, respectively, for office space under the administrative service +agreements, which is included in other income (expense) in the consolidated statements on operations. +Effective July 1, 2008, the +Company is party to an acquisition team agreement with Everest Operations Management LLC (“Everest”) to identify and evaluate potential oil and gas properties in which the Company and Everest may wish to invest. Upon a successful closing +of an acquisition or divestiture, each party participating in the successful closing shall pay a fee equal to 1% of its proportionate share of the acquisition or divestiture consideration to the party that identified the acquisition or divestiture. +The agreement has a one year term unless earlier terminated by either party upon 30 days notice. +5. +PROPERTY AND EQUIPMENT +The major categories of +property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2008 and 2007 are as follows: +December 31, +2008 +2007 +Oil and gas properties +$ +599,761,000 +$ +484,487,000 +Office furniture and fixtures +2,982,000 +2,922,000 +Building +3,926,000 +3,926,000 +Land +260,000 +260,000 +Total property and equipment +606,929,000 +491,595,000 +Accumulated depletion, depreciation, amortization and impairment +(444,690,000 +) +(129,496,000 +) +Property and equipment, net +$ +162,239,000 +$ +362,099,000 +F-14 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +At December 31, 2008, the net book value of the Company’s oil and gas properties, less related deferred income +taxes, was above the calculated ceiling as a result of reduced commodity prices at December 31, 2008. As a result, the Company was required to record an impairment of its oil and gas properties under the full cost method of accounting in the +amount of $272.7 million for the year ended December 31, 2008. +Included in oil and gas properties at December 31, 2008 and +December 31, 2007 is the cumulative capitalization of $10,614,000 and $5,969,000, respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost +pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All +general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $4,645,000, $2,041,000 and $976,000 +for the years ended December 31, 2008, 2007 and 2006, respectively. +The following is a summary of Gulfport’s oil and gas +properties not subject to amortization as of December 31, 2008: +Costs Incurred in +2008 +2007 +2006 +Prior to +2006 +Total +Acquisition costs +$ +6,261,000 +$ +13,766,000 +$ +1,342,000 +$ +— +$ +21,369,000 +Exploration costs +1,069,000 +105,000 +— +— +1,174,000 +Development costs +— +— +— +— +— +Total oil and gas properties not subject to amortization +$ +7,330,000 +$ +13,871,000 +$ +1,342,000 +$ +— +$ +22,543,000 +At December 31, 2008, approximately $2,175,000 of oil and gas properties related to the +Company’s Belize properties is excluded from amortization as it relates to non-producing properties. In addition, approximately $12,592,000 of non-producing leasehold costs resulting from the Company’s acquisition of West Texas Permian +properties and $6,255,000 of non-producing leasehold costs related to the Company’s Bakken properties are excluded from amortization at December 31, 2008. Approximately $1,521,000 of non-producing leasehold costs related to the +Company’s Southern Louisiana assets was also excluded from amortization. At December 31, 2007, approximately $37,278,000 of non-producing leasehold costs was not subject to amortization. +The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the +Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to occur within three to five years. +F-15 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +A reconciliation of the asset retirement obligation for the years ended December 31, 2008 and 2007 is as follows: +December 31, +2008 +2007 +Asset retirement obligation, beginning of period +$ +8,634,000 +$ +8,858,000 +Liabilities incurred +934,000 +500,000 +Liabilities settled +(859,000 +) +(1,278,000 +) +Accretion expense +560,000 +554,000 +Asset retirement obligation as of end of period +9,269,000 +8,634,000 +Less current portion +635,000 +480,000 +Asset retirement obligation, long-term +$ +8,634,000 +$ +8,154,000 +6. +EQUITY INVESTMENTS +Investments accounted for by +the equity method consist of the following as of December 31, 2008 and 2007: +December 31, +2008 +2007 +Investment in Tatex Thailand II, LLC +$ +2,683,000 +$ +3,553,000 +Investment in Tatex Thailand III, LLC +876,000 +— +Investment in Windsor Bakken, LLC +— +2,468,000 +Investment in Grizzly Oil Sands ULC +21,881,000 +27,801,000 +$ +25,440,000 +$ +33,822,000 +Tatex Thailand II, LLC +During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford Capital +LLC, an affiliate of Gulfport. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia +through its ownership of concessions covering three million acres which includes the Phu Horm Field. During 2008, Gulfport paid $50,000 in cash calls and received $912,000 in distributions, bringing its total investment in Tatex (including previous +investments) to $2,683,000. The Company recognized a loss on equity investment of $8,000 for the year ended December 31, 2008, which is included in other income (expense) in the consolidated statements of operations. The loss on equity +investment related to Tatex was immaterial for the years ended December 31, 2007 and 2006. +Tatex Thailand III, LLC +During the first quarter of 2008, the Company purchased a 5% ownership interest in Tatex Thailand III, LLC (“Tatex III”) at a cost of $850,000. +Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford, an affiliate of Gulfport. During the year ended December 31, 2008, Gulfport paid $35,000 in cash calls, bringing its total investment in +Tatex III to $876,000. The Company recognized a loss +F-16 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +on equity investment of $9,000 for the year ended December 31, 2008 which is included in other income (expense) in the consolidated statements of +operations. +Windsor Bakken, LLC +During 2005, the Company purchased a 20% ownership interest in Windsor Bakken, LLC (“Bakken”). The remaining interests in Bakken are owned by entities controlled by Wexford, an affiliate of Gulfport. Beginning in 2005, Bakken +acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana. As of December 31, 2007, Gulfport’s net investment in Bakken was $2,468,000. As of December 31, 2007, Bakken had +commenced drilling of some of its undeveloped acreage. The Company recognized losses on equity investment of $92,000 and $48,000 for the years ended December 31, 2007 and 2006, respectively, which are included in other income (expense) in the +consolidated statements of operations. +Effective January 1, 2008, the Company acquired a direct, undivided 20% interest in +Bakken’s assets in redemption of its 20% interest in Bakken. As a result, the Company recognized $2,468,000 of oil and natural gas assets which was included in oil and natural gas properties on the accompanying consolidated balance sheets. +Grizzly Oil Sands ULC +During the +third quarter of 2006, the Company, through its wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company, for approximately $8.2 million. The +remaining interests in Grizzly are owned by entities controlled by Wexford, an affiliate of Gulfport. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands +development projects. Grizzly has commenced drilling of core holes for feasibility of oil production in five separate lease blocks but has not commenced development of operations. As of December 31, 2008 and 2007, Gulfport’s net investment +in Grizzly was $21,881,000 and $27,801,000, respectively. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was decreased by $5,281,000 as a result of a currency translation loss for the year ended +December 31, 2008 and increased by $2,254,000 as a result of a currency translation gain for the year ended December 31, 2007. The Company recognized a loss on equity investment of $639,000, $385,000 and $28,000 for the years ended +December 31, 2008, 2007 and 2006, respectively, which is included in other income (expense) in the consolidated statements of operations. +The Company, through its wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow funds from the Company. Borrowed funds bear interest at LIBOR +plus 400 basis points. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan matures on December 31, 2012. The Company loaned Grizzly approximately $10,519,000 during the year ended +December 31, 2008. The Company recognized interest income of approximately $410,000 for the year ended December 31, 2008, which is included in interest income in the consolidated statements of operations. The note balance was decreased by +approximately $1,776,000 as a result of a currency translation loss for the year ended December 31, 2008. The total $9,153,000 due from Grizzly is included in note receivable—related party on the accompanying consolidated balance sheets. +F-17 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +7. +OTHER ASSETS +Other assets consist of the following +as of December 31, 2008 and 2007: +December 31, +2008 +2007 +Plugging and abandonment escrow account on the WCBB properties (Note 18) +$ +3,144,000 +$ +3,104,000 +Certificates of Deposit securing letter of credit +200,000 +200,000 +Prepaid drilling costs +407,000 +— +Deposits +4,000 +3,084,000 +$ +3,755,000 +$ +6,388,000 +8. +LONG-TERM DEBT +A break-down of long-term debt as +of December 31, 2008 and 2007 is as follows: +December 31, +2008 +2007 +Reducing credit agreement (1) +$ +64,521,000 +$ +59,521,000 +Term loan (1) +3,588,000 +4,294,000 +Building loans (2) +2,622,000 +2,718,000 +Less: current maturities of long term debt +(815,000 +) +(808,000 +) +Debt reflected as long term +$ +69,916,000 +$ +65,725,000 +Maturities of long-term debt as of December 31, 2008 are as follows: +2009 +$ +815,000 +2010 +65,343,000 +2011 +3,128,000 +2012 +714,000 +2013 +714,000 +Thereafter +17,000 +Total +$ +70,731,000 +(1) On March 11, 2005, Gulfport entered into a three-year secured reducing credit agreement +providing for a $30.0 million revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. On +November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount available under the borrowing base +limitation was increased to $30.0 million. Effective July 19, 2007, the credit facility was increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0 million. On December 20, 2007, the +amount available under the borrowing base limitation was increased to $90.0 million and the Eurodollar interest rate, which the Company can elect to use at its option, was reduced by 0.75%. In addition, the maturity date was extended from +March 31, 2009 to March 31, 2010. The facility is subject to +F-18 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +annual and semi-annual redeterminations. The Company is currently in the process of a redetermination based on year-end reserve information and bank pricing +decks, among other considerations. Preliminary indications from the bank indicate that the Company’s borrowing base under this facility may be reset at approximately $60.0 million, but the exact outcome cannot be predicted at this time. The +Company makes quarterly interest payments on amounts borrowed under the facility. Amounts borrowed under the credit facility bear interest at Bank of America Prime plus 0.5% (3.75% at December 31, 2008). The Company’s obligations under the +credit facility are collateralized by a lien on substantially all of the Company’s Louisiana and West Texas assets. The credit facility contains certain affirmative and negative covenants, including, but not limited to the following financial +covenants: (a) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest +expense, plus exploration costs deducted in determining net income under full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period may not be +less than 3.00 to 1.00. The Company was in compliance with all covenants at December 31, 2008. As of December 31, 2008, approximately $64.5 million was outstanding under this facility, which is included in long-term debt, net of current +maturities on the accompanying consolidated balance sheet. +On July 10, 2006, Gulfport entered into a $5 million term loan agreement +with Bank of America, N.A. related to the purchase of new gas compressor units. The loan began amortizing quarterly on March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, +2006. The Company makes quarterly principal payments of approximately $176,000. Amounts borrowed bear interest at Bank of America Prime (3.25% at December 31, 2008). The Company makes quarterly interest payments on amounts borrowed under the +agreement. The Company’s obligations under the agreement are collateralized by a lien on the compressor units. As of December 31, 2008, approximately $3.6 million was outstanding under this agreement, of which $714,000 and $2.9 million are +included in current maturities of long-term debt and long-term debt, net of current maturities, respectively, on the accompanying consolidated balance sheet. +(2) In June 2004, the Company purchased the office building it occupies in Oklahoma City, Oklahoma, for $3.7 million. One loan associated with this building matured in March 2006 and bore interest at the rate of +6% per annum, while the other loan matures in June 2011 and bears interest at the rate of 6.5% per annum. In addition, the building loans included a loan related to a building in Lafayette, Louisiana, purchased in 1996 to be used as the +Company’s Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. The Company paid this loan in full during the third quarter of 2007, in advance of its February 2008 maturity date. The remaining building loan +requires monthly interest and principal payments of approximately $23,000 and is collateralized by the Oklahoma City office building and associated land . +9. +COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is +administered by the Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be granted, the number of +shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are defined as all directors of the Company, all officers of +the Company and all key employees of the Company with a customary work week of at +F-19 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted under the Plan, as adjusted for changes in +capitalization which have taken place since the Plan’s adoption, was 883,000. The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, 2008. No additional +securities will be issued under the Plan other than upon exercise of options that are outstanding. +The Company replaced the Plan in +January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible participants options +shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, +consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include +(a) Incentive Stock Options, (b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights and (ii) increase the maximum +aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of +December 31, 2008, the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. +During the first quarter of 2006, the Company granted a total of 40,000 options for the purchase of shares of the Company’s common stock. The exercise price per share of these options is $12.17. The options vest in equal monthly +installments over a three-year period and expire ten years after the date of grant. During August 2006, these options were cancelled and 6,666 restricted shares of the Company’s common stock were issued to the option holder. These shares were +fully vested on the date of grant. +Restricted Stock +On May 16, 2006, the Company issued 57,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three year period. During August and September 2006, 29,666 +shares of restricted common stock were issued. These shares vest in equal monthly installments over a three year period. On August 17, 2006, the Company issued an additional 6,666 shares of fully vested restricted common stock in connection +with the cancellation of 40,000 options to purchase the Company’s common stock. +On April 1, 2007, the Company granted 16,389 +shares of restricted common stock of the Company. These shares vest monthly over a three year period. On May 15, 2007, the Company granted 10,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments +over a three year period. On August 14, 2007, the Company granted 8,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three year period. On November 9, 2007, the Company granted +3,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three year period. +On +March 13, 2008, the Company granted 6,666 shares of restricted common stock of the Company, of which 740 shares vested on April 1, 2008 with the remaining shares vesting over 36 equal monthly installments beginning on May 1, 2008. On +August 6, 2008, the Company granted 2,000 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments beginning on September 17, 2008. On +F-20 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +September 15, 2008, the Company granted 10,000 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly +installments beginning on September 17, 2008. On December 5, 2008, the Company granted 66,667 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments beginning on December 17, 2008. +All shares of restricted common stock of the Company were granted under the amended and restated 2005 Plan. +Exercise of Warrants +During the first quarter of 2006, holders of warrants issued by the Company in 2002 in conjunction with a private placement offering exercised their +warrants resulting in 12,171 shares of the Company’s common stock being issued. No proceeds were received by the Company related to the exercise of these warrants. During the third quarter of 2006, holders of warrants exercised their warrants +resulting in 101,681 shares of the Company’s common stock being issued. The Company had 60,550 warrants outstanding at December 31, 2008 which can be converted into 203,529 shares of common stock at an exercise price of $1.19 per share. +The warrants expire in 2012. +Sale of Common Stock +In May of 2006, the Company closed a public offering of 6,050,000 shares of common stock at a price of $14.00 per share. All shares were sold by certain of the Company’s stockholders and the Company did not +receive any proceeds. In connection with the offering, the Company granted the underwriters a 30-day option to purchase additional shares of the Company’s common stock to cover over-allotments, if any. On May 8, 2006, the underwriters +exercised their option with respect to 790,000 shares. The Company received net proceeds of approximately $10.5 million from the sale of these shares on May 10, 2006 after deducting the underwriting discount and before offering expenses. +On January 30, 2007, the Company sold 1,150,000 shares of common stock in an underwritten offering at an offering price to the public +of $11.92 per share. In connection with the offering, the Company granted the underwriter an option to purchase up to an additional 172,500 shares of common stock to cover any over-allotments, which the underwriter exercised in full on +February 1, 2007. The Company received the net proceeds of approximately $15.3 million from the sale of these shares on February 5, 2007 after deducting the underwriting discount and before offering expenses. +In May 2007, the Company sold 1,500,000 shares of common stock in an underwritten offering at an offering price to the public of $16.00 per share. In +connection with the offering, the Company granted the underwriter an option to purchase up to an additional 225,000 shares of common stock to cover any over-allotments, which the underwriter exercised in full. The Company received the net proceeds +of approximately $26.8 million from the sale of these shares on May 22, 2007 after deducting the underwriting discount and before offering expenses. +In July 2007, the Company sold 1,000,000 share of common stock in an underwritten offering at an offering price to the public of $22.00 per share. The Company received the net proceeds of approximately $21.2 million +from the sale of these shares on July 25, 2007 after deducting the underwriting discount and before offering expenses. +In December +2007, the Company sold 4,500,000 shares of common stock in an underwritten offering at an offering price to the public of $17.50 per share. The Company received the net proceeds of approximately $75.6 million from the sale of these shares on +December 12, 2007 after deducting underwriting discounts and before +F-21 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +offering expenses. In connection with the offering, a selling stockholder granted the underwriter an option to purchase an additional 675,000 shares of +common stock to cover any over-allotments, which the underwriter exercised in full. The Company did not receive any proceeds from the sale of shares of the common stock by the selling stockholder. +Private Placement Offering +In March 2002, the +Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred Stock, Series A, of the Company (the “Preferred”) and (ii) a warrant to purchase up to 250 shares of +common stock, par value $0.01 per share, of the Company (the “Warrants”). Holders of the Preferred were entitled to receive dividends at the rate of 12% of the liquidation preference per annum payable quarterly in cash or, at the option of +the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of Preferred at the rate of 15% of the liquidation preference per annum. All Preferred shares were redeemed in 2005. +The 2,322,962 Warrants issued have a term of ten years and a current exercise price of $1.19 per share of common stock subject to adjustment. The +Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the Warrants. The Company considered the valuation of the Warrants and did not consider them +materially significant. At December 31, 2008 and 2007, 60,550 Warrants were outstanding. +10. +STOCK-BASED COMPENSATION +During the years ended +December 31, 2008, 2007 and 2006, the Company’s stock-based compensation cost was $1,056,000, $1,158,000 and $1,063,000, respectively, of which the Company capitalized $422,000, $313,000 and $276,000, respectively, relating to its +exploration and development efforts, which reduced basic and diluted earnings per share by $0.01 and $0.02 for the years ended December 31, 2008 and December 31, 2007, respectively. +The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model that uses the assumptions noted in +the following table. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon historical experience of the Company, the expected term +of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all +options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant. +No stock +options were issued during the year ended December 31, 2008 and 2007. The following table provides information relating to stock options granted for the year ended December 31, 2006: +December 31, +2006 +Expected volatility +40.9 +% +Expected life in years +4.0 +Weighted average risk free interest rate +4.0 +% +The Company has not declared dividends and does not intend to do so in the foreseeable future, and +thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future +F-22 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near +the value estimated using the Black-Scholes model. +A summary of the status of stock options and related activity for the years ended +December 31, 2008, 2007 and 2006 are presented below: +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value +Options outstanding at December 31, 2005 +1,558,773 +$ +4.31 +7.33 +$ +12,061,000 +Granted +40,000 +12.17 +Cancelled +(40,000 +) +12.17 +Exercised +(565,723 +) +2.26 +5,770,000 +Forfeited/expired +(25,817 +) +3.26 +Options outstanding at December 31, 2006 +967,233 +5.54 +7.76 +7,782,000 +Granted +— +— +Exercised +(210,398 +) +4.13 +2,284,000 +Forfeited/expired +(82,445 +) +3.66 +Options outstanding at December 31, 2007 +674,390 +6.22 +6.97 +$ +8,098,000 +Granted +— +— +Exercised +(144,121 +) +3.34 +1,694,000 +Forfeited/expired +(7,889 +) +6.17 +Options outstanding at December 31, 2008 +522,380 +$ +7.01 +6.24 +$ +(1,599,000 +) +Options exercisable at December 31, 2008 +314,140 +$ +9.43 +6.35 +$ +(1,722,000 +) +The 40,000 options granted in 2006 and subsequently cancelled had a fair value of $4.40 per share, +or $176,000. +Unrecognized compensation expense as of December 31, 2008 related to outstanding stock options and restricted shares was +$847,000. The expense is expected to be recognized over a weighted average period of 1.47 years. +The following table summarizes +information about the stock options outstanding at December 31, 2008: +Exercise +Price +Number +Outstanding +Weighted Average +Remaining Life +(in years) +Number +Exercisable +$ 2.00 +23,250 +0.85 +23,250 +$ 3.36 +234,241 +6.06 +26,001 +$ 9.07 +64,889 +6.69 +64,889 +$11.20 +200,000 +6.92 +200,000 +522,380 +314,140 +F-23 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +The following table summarizes restricted stock activity for the twelve months ended December 31, 2008, 2007 and 2006: +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2005 +— +$ +— +Granted +93,332 +12.78 +Vested +(21,981 +) +12.64 +Forfeited +(1,833 +) +13.27 +Unvested shares as of December 31, 2006 +69,518 +$ +12.81 +Granted +37,389 +$ +15.66 +Vested +(35,930 +) +13.13 +Forfeited +(11,944 +) +15.24 +Unvested shares as of December 31, 2007 +59,033 +$ +13.94 +Granted +85,333 +$ +5.64 +Vested +(41,493 +) +11.97 +Forfeited +(9,417 +) +15.84 +Unvested shares as of December 31, 2008 +93,456 +$ +7.04 +11. +INSURANCE PROCEEDS +In May 2008, the Company +received insurance proceeds of approximately $769,000 related to damages incurred resulting from a 2006 barge accident in its WCBB field. The costs associated with repairing the field were expensed to lease operating expenses as incurred in 2006 and +2007. The Company recognized the insurance proceeds in other (income) expense in the accompanying consolidated statements of operations. +12. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying +amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current and long-term debt are carried at cost, which approximates market value. +The fair value of the derivative instruments is computed based on the difference between the prices provided by the fixed-price contracts and forward +market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and are subject to significant volatility. +F-24 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +13. +INCOME TAXES +The income tax provision consists of +the following: +2008 +2007 +2006 +Current—federal +$ +653,000 +$ +121,000 +$ +— +Deferred—federal +(653,000 +) +— +— +Total income tax expense (benefit) provision +$ +— +$ +121,000 +$ +— +A reconciliation of the statutory federal income tax amount to the recorded expense follows: +2008 +2007 +2006 +Income (loss) before federal income taxes +$ +(184,502,000 +) +$ +37,775,000 +$ +27,808,000 +Expected income tax at statutory rate +(64,576,000 +) +13,221,000 +9,455,000 +State income taxes +(7,033,000 +) +2,131,000 +1,668,000 +Other differences +(527,000 +) +528,000 +1,034,000 +Changes in valuation allowance +72,136,000 +(15,759,000 +) +(12,157,000 +) +Income tax expense recorded +$ +— +$ +121,000 +$ +— +The tax effects of temporary differences and net operating loss carryforwards, which give rise to +deferred tax assets and liabilities at December 31, 2008, 2007 and 2006 are estimated as follows: +2008 +2007 +2006 +Deferred tax assets: +Net operating loss carryforward +$ +23,810,000 +$ +37,197,000 +$ +38,373,000 +Oil and gas property basis difference +57,789,000 +— +— +SFAS 123(R) compensation expense +238,000 +216,000 +319,000 +Investment in pass through entities +— +72,000 +— +AMT credit +718,000 +64,000 +— +Non-oil and gas property basis difference +118,000 +148,000 +99,000 +Total deferred tax assets +82,673,000 +37,697,000 +38,791,000 +Deferred tax liabilities: +Oil and gas property basis difference +— +27,947,000 +13,273,000 +Investment in pass through entities +134,000 +— +— +Unrealized gain on hedging activities +— +— +9,000 +Total deferred tax liabilities +134,000 +27,947,000 +13,282,000 +Total deferred tax asset +82,539,000 +9,750,000 +25,509,000 +Valuation allowance +(81,886,000 +) +(9,750,000 +) +(25,509,000 +) +Net deferred tax asset (liability) +$ +653,000 +$ +— +$ +— +F-25 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +The Company has an available tax net operating loss carryforward estimated at approximately $59,526,000 as of +December 31, 2008. This carryforward will begin to expire in the year 2018. A valuation allowance has been provided at December 31, 2008, 2007 and 2006 because it is management’s belief, based upon the Company’s past history of +no taxable income, it is more likely than not the net deferred tax assets will not be realized. +The Company had income tax expense of +$121,000 during the year ended December 31, 2007 related to the payment of alternative minimum taxes due for 2006 and 2007. Although the Company has substantial net operating loss carryforwards, these cannot be used to offset alternative +minimum tax liabilities. +14. +EARNINGS PER SHARE +A reconciliation of the +components of basic and diluted net income per common share is presented in the table below: +2008 +2007 +2006 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per +Share +Basic: +Net income (loss) +$ +(184,502,000 +) +42,599,611 +$ +(4.33 +) +$ +37,775,000 +36,774,163 +$ +1.03 +$ +27,808,000 +32,789,280 +$ +0.85 +Effect of dilutive securities: +Stock options and awards +— +— +— +676,935 +— +1,146,794 +Diluted: +Net income +$ +(184,502,000 +) +42,599,611 +$ +(4.33 +) +$ +37,775,000 +37,451,098 +$ +1.01 +$ +27,808,000 +33,936,074 +$ +0.82 +For the year ended December 31, 2008, all options were excluded from the calculation of +dilutive earnings per share because the Company had a net loss and, therefore, the effect would have been anti-dilutive. Options to purchase 200,000 shares at $11.20 per share were excluded from the calculation of dilutive earnings per share for the +year ended December 31, 2006 because they were anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive for the year ended December 31, 2007. +15. +FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES +Oil Price Hedging +Activities +The Company established an oil price-hedging program in August 2005. The Company may seek to reduce its exposure to +unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by taking receive-fixed positions in price swap contracts. The Company pays the counterparty the excess of the oil market price over the fixed price +and will receive the excess of the fixed price over the market price as defined in each contract. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating +cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. For the year +ended December 31, 2006, price swap contracts hedged 62% of the Company’s oil production. There were no price swap contracts in place as of December 31, 2008, 2007 and 2006. +F-26 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +The Company’s 2006 price swap contracts were tied to commodity prices on the New York Mercantile Exchange +(“NYMEX”). The Company received the fixed price amount stated in the contract and paid to its counterparty the current market price for oil as listed on the NYMEX West Texas Index (“WTI”). However, due to the geographic location +of the Company’s assets and the cost of transporting oil to another market, the amount that the Company received when it actually sold its oil differed from the index price. The difference between oil prices on the NYMEX WTI and average price +received by the Company during the month for its oil is referred to as a basis differential. +All price swap contracts have been executed +in connection with the Company’s oil price hedging program. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For +price swap contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil sales in the period for which the underlying production was hedged. For the year ended December 31, 2006, there +were net realized losses of $1,008,000 under price swap contracts, which are included in oil sales on the consolidated statements of operations. The losses for the year ended December 31, 2006 included $191,000 of gains that had previously been +deferred within other comprehensive income and are further discussed in the subsequent paragraph. +The Company’s oil production was +shut-in during the fourth quarter of 2005 and for a portion of the first quarter of 2006 due to Hurricane Rita’s impact on the Company’s facilities. In accordance with SFAS 133 Derivative Implementation Group Issue Number G3, certain +extenuating circumstances that impact the timing of the forecasted transaction and are outside the control or influence of the Company permit the gain or loss related to the cash flow hedge being reported in accumulated other comprehensive income +until the forecasted transaction is recognized in earnings. As a result, all fourth quarter 2005 and first quarter 2006 contract profits and losses (net gain of $114,000 and $77,000, respectively) remained in accumulated other comprehensive income +at March 31, 2006. During the second quarter of 2006, production was restored and the Company recognized gains of $47,000 in the second quarter of 2006. The remaining deferred gain of $144,000 was recognized during the third quarter of 2006. +For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized +in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. +Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. During the year ended December 31, 2006, a gain of $24,000 was recognized into earnings resulting from hedge ineffectiveness. +In October 2006, the Company terminated the remaining three months of its hedging contracts. Through the termination of these remaining contracts the +Company received a total of $566,000 of proceeds during the fourth quarter of 2006 resulting from the differential in the fixed hedged price of $64.05 per barrel and the market prices of the associated futures contracts at the date of the +termination of these contracts. In accordance with SFAS 133, these amounts were recognized into earnings during the fourth quarter of 2006, the period in which the hedged forecasted transactions occurred. The Company had no derivative contracts at +December 31, 2008 and 2007. +16. +OPERATING LEASES +In October 2006, the Company +began leasing the Louisiana building that it owns to an unrelated party. The cost of the building totaled approximately $217,000 and accumulated depreciation amounted to approximately +F-27 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +$82,000 as of December 31, 2008. The lease commenced on October 15, 2006 and expires October 14, 2009, with equal monthly installments of +$10,500. The future minimum lease payments to be received are as follows: +Fiscal year ending December 31, 2009 +$ +94,500 +17. +RELATED PARTY TRANSACTIONS +In the ordinary course +of business, the Company conducts business activities with certain entities affiliated with its largest stockholder. +Windsor Energy Group +(“WEG”), an affiliate of Gulfport, operates the Permian Basin wells in West Texas. At December 31, 2008, the Company owed WEG approximately $3,724,000 related to reimbursement for services provided. WEG operated the Marquiss wells in +Wyoming. At December 31, 2007, the Company owed WEG approximately $440,000 related to reimbursement for services provided. Approximately $2,711,000 and $125,000 were included in lease operating expenses in the consolidated statements of +operations for the years ended December 31, 2008 and 2007, respectively. Approximately $37,693,000 related to services performed by WEG is included in oil and natural gas properties at December 31, 2008. +Athena Construction LLC (“Athena”), an affiliate of Gulfport, performs services for the Company at its WCBB and Hackberry fields. At +December 31, 2008 and December 31, 2007, the Company owed Athena approximately $759,000 and $1,561,000, respectively, related to these services. Approximately $1,303,000 and $989,000 of services provided by Athena are included in lease +operating expenses in the consolidated statements of operations for the years ended December 31, 2008 and 2007, respectively. Approximately $1,783,000 and $4,784,000 related to services performed by Athena are included in oil and natural gas +properties at December 31, 2008 and 2007, respectively. +Packers & Service Tools, Inc. (“Packers”), an affiliate of +Gulfport, performs services for the Company at its WCBB and Hackberry fields. At December 31, 2008 and December 31, 2007, the Company owed Packers approximately $465,000 and $425,000, respectively, related to these services. Approximately +$11,000 and $41,000 of services provided by Packers are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2008 and 2007, respectively. Approximately $1,995,000 and $1,439,000 +relating to services performed by Packers are included in oil and natural gas properties at December 31, 2008 and 2007, respectively. +Diamondback Completions LLC (“Completions”), an affiliate of Gulfport, performs services for the Company at its WCBB and Hackberry fields. At December 31, 2008 and December 31, 2007, the Company owed Completions +approximately $24,000 and $241,000, respectively, related to these services. Approximately $227,000 and $519,000 relating to services performed by Completions are included in oil and natural gas properties on the accompanying consolidated balance +sheets at December 31, 2008 and 2007, respectively. Completions ceased to be an affiliate of the Company in December 2008. +Great +White Towing LLC (“Towing”), an affiliate of Gulfport, performs services for the Company at its WCBB field. At December 31, 2008 and December 31, 2007, the Company owed Towing approximately $222,000 and $50,000, respectively, +related to these services. Approximately $102,000 and $13,000 of services performed by Towing are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2008 and 2007, respectively. +Approximately $339,000 and $133,000 relating to +F-28 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +services performed by Towing are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2008 and +2007, respectively. +Bronco Drilling Company, Inc. (“Bronco”), an affiliate of Gulfport, performed services for the Company at +its Hackberry and Bakken fields. Approximately $2,258,000 relating to services performed by Bronco is included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2008. There were no amounts owed to +Bronco at December 31, 2008 or 2007. +At December 31, 2007, the Company’s wholly owned subsidiary, Grizzly Holdings Inc., +owed Grizzly Oil Sands ULC approximately $151,000 for shares issued in 2007. No amounts were owed at December 31, 2008. Additional related party transactions with Grizzly Oil Sands ULC are discussed in Note 6. +18. +COMMITMENTS +Plugging and Abandonment Funds +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed the seller’s (Chevron) +obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security +interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company can access the trust for use in plugging and abandonment charges associated with the property. As of +December 31, 2008, the plugging and abandonment trust totaled approximately $3,144,000 including interest received during 2008 of approximately $45,000. At December 31, 2008, the Company has plugged 273 wells at WCBB since it began its +plugging program in 1997, which management believes fulfills its current minimum plugging obligation. +Texaco Global Settlement +Pursuant to the terms of a global settlement between Texaco and the State of Louisiana which includes the State Lease No. 50 portion of +Gulfport’s East Hackberry field, Gulfport was obligated to commence drilling a well or other qualifying development operation on certain non-producing acreage in the field prior to March 1998. Because of prevailing market conditions during +1998, the Company believed it was commercially impractical to shoot seismic or commence drilling operations on the subject property. As a result, Gulfport agreed to surrender approximately 440 non-producing acres in this field to the State of +Louisiana. At December 31, 2008, Gulfport was in the process of releasing these properties to the State of Louisiana. +Contributions to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 15% of their total compensation +through salary deferrals. Also under these plans, the Company will make a contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals. +During the years ended December 31, 2008, 2007 and 2006, Gulfport incurred $651,000, $640,000 and $308,000, respectively, in contributions expense related to this plan. +Employment Agreement +In May 1999, Gulfport entered into an employment agreement with its Chairman of +the Board. The original term of the agreement expired on May 31, 2004, but automatically renews for successive terms of one year +F-29 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +unless Gulfport or the Chairman elects otherwise. The employment agreement calls for an annual salary of $200,000, subject to adjustment for cost of living +increases. +19. +CONTINGENCIES +The Louisiana State Mineral +Board (“LSMB”) disputed Gulfport’s royalty payments to the State of Louisiana resulting from the sale of oil under fixed price contracts. The LSMB maintains that Gulfport paid approximately $1,400,000 less in royalties under the +fixed price contracts than the royalties Gulfport would have had to pay had it sold the oil at prevailing market rates. Gulfport has denied any liability to the LSMB for underpayment of royalties and maintained that it was entitled to enter into the +fixed price contracts with unrelated third parties and pay royalties based upon the sales proceeds from those contracts. Gulfport met with the Louisiana Attorney General on several occasions and reached a mutual settlement. In accordance with the +settlement, Gulfport paid $250,000 during the second quarter of 2008, all of which was previously accrued in accounts payable and accrued liabilities in the accompanying consolidated balance sheets. Under the settlement, all future royalties will be +paid at market price, regardless of the presence of fixed price contracts. The settlement was approved by the LSMB during its February 2008 session and executed on April 1, 2008, effectively closing this matter. +The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale of oil +under fixed price contracts during the years 2005 through 2007. The LDR maintains that Gulfport paid approximately $1,799,000 less in severance taxes under fixed price terms than the severance taxes Gulfport would have had to pay had it paid +severance taxes on the oil at the contracted market rates only. Gulfport has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts with unrelated third +parties and pay severance taxes based upon the proceeds received under those contracts. Gulfport has maintained its right to contest any final assessment or suit for collection if brought by the State. +Other Litigation +In November 2006, Cudd Pressure +Control, Inc. (“Cudd”) filed a lawsuit against Gulfport and Great White Pressure Control LLC, an affiliate of the Company, among others, in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the +United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleges RICO violations and several other causes of action relating to an affiliate company’s employment of several former Cudd employees. The +defendants in the suit are Ronnie Roles, Rocky Roles, Steve Winters, Bert Ballard, Nelson Britton, Michael Fields, Great White Pressure Control LLC and Gulfport. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without +prejudice by order of the court on February 14, 2007. The Company filed a motion for summary judgment on October 5, 2007. The Court entered a final interlocutory judgment in favor of all defendants, including Gulfport, on April 8, +2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Firth Circuit. The defendants filed their response appellate brief on December 19, 2008, and Cudd filed its reply brief on January 19, 2009. +Gulfport is currently awaiting the Fifth Circuit’s ruling on this matter. +On July 27, 2007, Robotti & Company, LLC +filed a putative class action lawsuit in the Court of Chancery for the State of Delaware in and for Kent County, Delaware. The original complaint alleged a breach of fiduciary duty by Gulfport and its then present directors in connection with the +pricing of the Company’s 2004 rights offering. Plaintiff filed an amended complaint on January 15, 2008, and the defendants filed a motion to dismiss in early February 2008 and filed the brief in support of such motion on April 29, +2008. The court held a hearing +F-30 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +on October 3, 2008, ultimately deciding to allow the plaintiff to file a second amended complaint. Plaintiff filed its second amended complaint +December 22, 2008, which sets forth class action and derivative claim allegations that Gulfport’s then present directors breached their fiduciary duty in connection with the pricing of the 2004 rights offering. The defendants filed their +motion to dismiss on January 19, 2009 and their brief in support of such motion on February 20, 2009. Briefing by the parties is scheduled to conclude April 6, 2009 and Gulfport anticipates the Court will rule on the defendants’ +motion to dismiss thereafter. +Due to the current early stages of the above litigation, the outcome is uncertain and management cannot +determine the amount of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations. +The Company has been named as a defendant on various other litigation matters. The ultimate resolution of these matters is not expected to +have a material adverse effect on the Company’s financial condition or results of operations for the periods presented in the consolidated financial statements. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry principally in the state +of Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and +gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to +$250,000. At December 31, 2008, Gulfport held cash in excess of insured limits in these banks totaling $5,424,000. +During the year +ended December 31, 2008, Gulfport sold approximately 87% and 11% of its oil production to Shell and Windsor, respectively, 100% of its natural gas liquids production to Windsor, and 60%, 22%, and 16% of its natural gas production to Chevron, +Windsor, and Hilcorp, respectively. During the year ended December 31, 2007, approximately 99% of Gulfport’s oil sales and 69% and 23% of Gulfport’s natural gas sales were attributable to three purchasers: Shell, Chevron, and Hilcorp, +respectively. During the year ended December 31, 2006, Gulfport sold approximately 100% of its oil production to Shell and approximately 96% of its natural gas production to Chevron. +Forward Sales Contracts +The Company was a party to +forward sales contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, the Company +entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In addition, the Company entered into forward sales contracts for the sale +of 3,500 barrels of production per day for the months of January 2008 through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For June 2008, the Company had agreements to sell 3,500 barrels of production +per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, the Company had agreements to sell 3,500 barrels of production per day at a weighted average daily price +F-31 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +of $85.89 per barrel before transportation costs. For August 2008, Gulfport had agreements to sell 3,500 barrels of production per day at a weighted average +daily price of $86.81 per barrel before transportation costs. For the periods September 2008 through December 2008, the Company entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average daily +price of $86.60 per barrel before transportation costs. For the period of January 2009 through December 2009, the Company entered into agreements to sell 3,000 barrels of production per day at a weighted average daily price of $89.06 per barrel +before transportation costs. These contracts were originally designated as normal sales of production under SFAS 133, based on the Company’s intent to physically deliver the production quantities under the contract terms, and exempted from the +provisions of SFAS 133. +In December 2008, the Company terminated the 2009 forward sales contracts in exchange for $39.0 million cash, +which is included in other (income) expense on the accompanying consolidated statements of operations. As a result of this cash settlement, the Company will be required to account for similar contracts in the future under the provisions of SFAS 133 +until a reasonable period passes and the Company redevelops a past history of physical delivery under fixed price contracts without net cash settlement. +20. +LITIGATION TRUST ENTITY +Pursuant to the +Company’s 1997 plan of reorganization, all of Gulfport’s possible causes of action against third parties (with the exception of certain litigation related to recovery of marine and rig equipment assets and claims against Tri-Deck), +existing as of the effective date of that plan, were transferred into a “Litigation Trust” controlled by an independent party for the benefit of most of the Company’s existing unsecured creditors. The litigation related to recovery of +marine and rig equipment and the Tri-Deck claims were subsequently transferred to the Litigation Trust as described below. +The Litigation +Trust was funded by a $3,000,000 cash payment from the Company, which was made on the effective date of reorganization. Gulfport owns a 12% interest in the Litigation Trust with the other 88% being owned by the former general unsecured creditors of +Gulfport. For financial statement reporting purposes, Gulfport has not recognized the potential value of recoveries which may ultimately be obtained, if any, as a result of the actions of the Litigation Trust, treating the entire $3,000,000 payment +as a reorganization cost at the time of Gulfport’s reorganization. +On January 20, 1998, Gulfport and the Litigation Trust +entered into a Clarification Agreement whereby the rights to pursue various claims reserved by Gulfport under the plan of reorganization were assigned to the Litigation Trust. In connection with this agreement, the Litigation Trust agreed to +reimburse the Company $100,000 for legal fees Gulfport had incurred in connection with these claims. As additional consideration for the contribution of this claim to the Litigation Trust, Gulfport is entitled to 20% to 80% of the net proceeds from +these claims. +No proceeds were received from the Litigation Trust for the years ended December 31, 2008, 2007 and 2006. The Company +does not have knowledge of the amount or timing of any future proceeds. +21. +SUBSEQUENT EVENTS (unaudited) +Subsequent to +December 31, 2008, the Company entered into forward sales contracts for the sale of 3,000 barrels of production per day at a weighted average daily price of $55.17 per barrel before transportation costs +F-32 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +for the period April 2009 to August 2009. For the period of September 2009 to December 2009, the Company has entered into forward sales contracts for the +sale of 3,000 barrels of production per day at a weighted average daily price of $54.81 per barrel before transportation costs. For the period of January 2010 to February 2010, the Company has entered into forward sales contracts for the sale of +3,000 barrels of production per day at a weighted average daily price of $54.81 per barrel before transportation costs. For the period March 2010 through December 2010, the Company has entered into forward sales contracts for the sale of 2,000 +barrels of production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. +22. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES +The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the southeastern United States: +Capitalized Costs Related to Oil and Gas Producing Activities +2008 +2007 +Proven properties +$ +577,218,000 +$ +447,209,000 +Unproven properties +20,368,000 +36,172,000 +597,586,000 +483,381,000 +Accumulated depreciation, depletion amortization and impairment reserve +(441,709,000 +) +(126,793,000 +) +Net capitalized costs +$ +155,877,000 +$ +356,588,000 +Equity investment in Windsor Bakken LLC +$ +— +$ +4,292,000 +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +2008 +2007 +2006 +Acquisition +$ +2,468,000 +$ +85,247,000 +$ +— +Development of proved undeveloped properties +64,643,000 +55,930,000 +41,770,000 +Exploratory +9,764,000 +57,668,000 +8,607,000 +Recompletions +16,877,000 +9,875,000 +4,235,000 +Capitalized asset retirement obligation +934,000 +500,000 +405,000 +Total +$ +94,686,000 +$ +209,220,000 +$ +55,017,000 +Equity investment in Windsor Bakken LLC +$ +— +$ +2,297,000 +$ +1,995,000 +F-33 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after +deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas +production. +2008 +2007 +2006 +Revenues +$ +141,650,000 +$ +106,163,000 +$ +60,232,000 +Production costs +(38,669,000 +) +(29,337,000 +) +(18,036,000 +) +Impairment of oil and gas assets +(272,722,000 +) +— +— +Depletion +(42,194,000 +) +(29,220,000 +) +(12,259,000 +) +(211,935,000 +) +47,606,000 +29,937,000 +Income tax expense +Current +— +121,000 +— +Deferred +— +— +— +— +121,000 +— +Results of operations from producing activities +$ +(211,935,000 +) +$ +47,485,000 +$ +29,937,000 +Depletion per barrel of oil equivalent (BOE) +$ +23.92 +$ +17.85 +$ +12.48 +Net earnings from equity method investment in Winsor Bakken LLC +$ +— +$ +20,000 +$ +— +Oil and Gas Reserves (Unaudited) +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2008, 2007 and 2006 and +changes in proved reserves during the last three years, assuming continuation of economic conditions prevailing at the end of each year. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic +feet (MMcf). The weighted average prices at December 31, 2008 used for reserve report purposes are $41.00 per barrel and $5.71 per MMbtu, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, +respectively. The weighted average prices at December 31, 2007 and 2006 used for reserve report purposes are $92.50 per barrel and $6.80 per MMbtu and $57.75 per barrel and $5.64 per MMbtu, respectively. +F-34 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. +The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. +2008 +2007 +2006 +Oil +Gas +Oil +Gas +Oil +Gas +Proved Reserves +Beginning of the period +25,115 +24,259 +19,692 +20,801 +19,542 +21,781 +Purchases in oil and gas reserves in place +77 +26 +5,699 +5,587 +— +— +Extensions and discoveries +1,315 +1,965 +— +— +— +— +Revisions of prior reserve estimates +(3,091 +) +(3,303 +) +1,225 +(1,313 +) +1,020 +(303 +) +Current production +(1,645 +) +(712 +) +(1,501 +) +(816 +) +(870 +) +(677 +) +End of period +21,771 +22,235 +25,115 +24,259 +19,692 +20,801 +Proved developed reserves +7,072 +7,187 +7,116 +6,746 +4,876 +4,077 +Equity Investment in Windsor Bakken LLC +Net proved developed and undeveloped reserves +— +— +77 +26 +— +— +Net proved developed reserves +— +— +18 +8 +— +— +The Company experienced downward reserve revisions in estimated proved reserves in 2008. These +downward revisions were primarily a result of year end commodity prices utilized for the reserve estimate decreasing from $92.50 per barrel and $6.80 per MMbtu at December 31, 2007 to $41.00 per barrel and $5.71 per MMbtu at December 31, +2008. +Discounted Future Net Cash Flows (Unaudited) +Estimates of future net cash flows from proven oil and gas reserves were made in accordance with SFAS No. 69, “ Disclosures about Oil and Gas Producing activities .” The following tables present +the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2008, 2007 and 2006 assuming continuation of economic conditions prevailing at the end of each year. +Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2008 +2007 +2006 +Future cash flows +$ +1,023,056,000 +$ +2,405,458,000 +$ +1,296,729,000 +Future development and abandonment costs +(299,362,000 +) +(326,229,000 +) +(193,543,000 +) +Future production costs +(376,176,000 +) +(420,646,000 +) +(261,955,000 +) +Future production taxes +(109,478,000 +) +(275,977,000 +) +(155,566,000 +) +Future income taxes +— +(280,538,000 +) +(93,569,000 +) +Future net cash flows +238,040,000 +1,102,068,000 +592,096,000 +10% discount to reflect timing of cash flows +(111,800,000 +) +(433,773,000 +) +(239,448,000 +) +Standardized measure of discounted future net cash flows +$ +126,240,000 +$ +668,295,000 +$ +352,648,000 +Equity investment in Windsor Bakken Standardized measure of discounted cash flows +$ +— +$ +1,753,000 +$ +— +F-35 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers in +Gulfport’s reserve report, the Company will need to spend $31,449,000, $51,171,000 and $46,876,000 during years 2009, 2010 and 2011, respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2008 +2007 +2006 +Sales and transfers of oil and gas produced, net of production costs +$ +(102,981,000 +) +$ +(76,826,000 +) +$ +(42,196,000 +) +Net changes in prices, production costs, and development costs +(662,004,000 +) +246,657,000 +(67,273,000 +) +Acquisition of oil and gas reserves in place +376,000 +121,267,000 +— +Extensions and discoveries +7,801,000 +— +— +Revisions of previous quantity estimates, less related production costs +(13,480,000 +) +27,970,000 +14,419,000 +Accretion of discount +66,830,000 +35,265,000 +36,982,000 +Net changes in income taxes +152,949,000 +(106,145,000 +) +40,282,000 +Change in production rates and other +8,454,000 +67,459,000 +610,000 +Total change in standardized measure of discounted future net cash flows +$ +(542,055,000 +) +$ +315,647,000 +$ +(17,176,000 +) +F-36 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, +2008, 2007 AND 2006 +(Amounts rounded to nearest thousand) +23. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The +following table summarizes quarterly financial data for the years ended December 31, 2008 and 2007: +2008 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter (1) +Revenues +$ +31,118,000 +$ +35,802,000 +$ +36,731,000 +$ +37,566,000 +Income from operations +12,660,000 +14,969,000 +15,119,000 +(262,797,000 +) +Income tax expense +— +— +20,000 +(20,000 +) +Net income +11,506,000 +14,886,000 +14,107,000 +(225,001,000 +) +Income per share: +Basic +$ +0.27 +$ +0.35 +$ +0.33 +$ +(5.28 +) +Diluted +$ +0.27 +$ +0.35 +$ +0.33 +$ +(5.28 +) +2007 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +20,381,000 +$ +25,009,000 +$ +29,975,000 +$ +30,473,000 +Income from operations +7,870,000 +10,136,000 +13,245,000 +9,213,000 +Income tax expense +53,000 +— +4,000 +64,000 +Net income +7,287,000 +9,570,000 +12,701,000 +8,217,000 +Income per share: +Basic +$ +0.21 +$ +0.27 +$ +0.34 +$ +0.21 +Diluted +$ +0.21 +$ +0.26 +$ +0.33 +$ +0.21 +(1) +Includes $272,772,000 impairment of oil and gas properties and income of $39,000,000 from the settlement of fixed price contracts. +F-37 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian +(incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor +Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the +SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on +July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited +partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party +thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other +affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Registrant and Mike Liddell (incorporated by reference to Exhibit 10.5 of Amendment No. 1 +to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +E-1 +Table of Contents +Exhibit +Number +Description +10.5 +Credit Agreement, dated as of March 11, 2005, by and among the Company, each lender from time to time party thereto and Bank of America, N.A., as agent (incorporated by reference to Exhibit +10.9 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +10.6 +Second Amendment to Credit Agreement, dated as of July 19, 2007, between the Company and Bank of America, N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, +filed by the Company with the SEC on July 19, 2007). +10.7 +Note dated July 19, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company with +the SEC on July 19, 2007). +10.8 +Third Amendment to Credit Agreement, dated as of December 20, 2007, between the Company, Bank of America, N.A., as a lender and administrative agent and such other lenders from time to +time party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2007). +10.9 +Note dated December 20, 2007 issued by the Company for the benefit of Bank of America, N.A. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company +with the SEC on December 26, 2007). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1 +* +Consent of Grant Thornton LLP. +23.2 +* +Consent of Netherland, Sewell & Associates, Inc. +23.3 +* +Consent of Pinnacle Energy Services, LLC +31.1 +* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2 +* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1 +* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +32.2 +* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of +Title 18 of the United States Code. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +E-2 \ No newline at end of file diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/filing_metadata.csv b/raw/filings/0000874499/2008/0001193125-09-055183/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..b7caf42ead6029c25e6461f46560c718d2954809 --- /dev/null +++ b/raw/filings/0000874499/2008/0001193125-09-055183/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2009-03-16,2008-12-31,2009-03-16T18:20:33.000Z,0001193125-09-055183,d10k.htm,FORM 10-K,1217108,0,0,https://www.sec.gov/Archives/edgar/data/874499/000119312509055183/d10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000119312509055183/,2008,2008,1 diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/item1.txt b/raw/filings/0000874499/2008/0001193125-09-055183/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c7f00275b9729265b0b6c51dab0b076a296d6511 --- /dev/null +++ b/raw/filings/0000874499/2008/0001193125-09-055183/item1.txt @@ -0,0 +1,479 @@ +ITEM 1. +DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf +Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and +in the Bakken Shale, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2008, at our WCBB field, we drilled eight wells and recompleted 48 existing wells for a total cost of approximately $31.0 million as of +December 31, 2008. Of our eight new wells drilled at WCBB in 2008, seven were completed as producing wells and one was non-productive. During 2009, we currently anticipate drilling four wells and recompleting 20 wells at our WCBB field for an +estimated aggregate cost of $7.5 to $8.5 million. In December 2008, production at WCBB was 109,292 net barrels of oil equivalent, or BOE, or an average of 3,526 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From +January 1, 2009 through March 9, 2009, our average net daily production at WCBB was 3,037 BOE, 99% of which was from oil and 1% of which was from natural gas. +In 2008, at our East Hackberry field, we drilled five wells and recompleted seven existing wells for a total cost of approximately $18.0 million as of December 31, 2008. All five wells drilled during 2008 were +completed as producing wells. During 2009, we currently anticipate drilling four land wells and recompleting three wells for an aggregate estimated cost of $4.5 to $5.5 million. In December 2008, net production at East Hackberry was 12,243 BOE, or +an average of 395 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2009 through March 9, 2009, our average net daily production at East Hackberry was 439 BOE, 95% of which was from oil and 5% of +which was from natural gas. +On December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin +for approximately $83.8 million, with an effective date of November 1, 2007. Through this transaction, we acquired 4,100 net acres with production at the time of acquisition of approximately 800 net BOE a day from 32 gross wells, predominately +from the Wolfcamp formation. In 2008, 31 gross (15.5 net) wells were drilled on this acreage, including one gross well spud in 2007 and completed in 2008 and one Henry Petroleum operated well for a total cost of approximately $33.9 million. As of +March 1, 2009, 29 of the 31 wells had been completed and the other two wells were awaiting completion. We currently anticipate drilling three gross (1.5 net) wells on this acreage in 2009 for an estimated average completed gross well cost of +$1.34 million. In December 2008, net production from our Permian acreage was 26,943 BOE, or an average of 869 BOE per day, 84% of which was from oil and natural gas liquids and 16% of which was from natural gas. From January 1, 2009 through +March 9, 2009, our average daily net production from our Permian acreage was 725 BOE per day, 83% of which was from oil and natural gas liquids and 17% of which was from natural gas. +During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining +interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development +projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9 million at December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate +of 117 core holes, tested five separate lease blocks using up to four different rigs and undertook a seismic program. Grizzly’s 2009 plans currently include drilling 15 additional core holes, which were completed in the first quarter of 2009 +for approximately $4.3 million. +2 +Table of Contents +During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining +interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base +located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +During +2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2006, Bakken acquired leases for undeveloped acreage in the Williston Basin area of +western North Dakota and eastern Montana. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. As of December 31, 2008, we had participated, or +committed to participate, in 53 gross wells in the Williston Basin with an average working interest of 2.52%. In December 2008, net production from this acreage was 8,692 BOE, or an average of 280 BOE per day. From January 1, 2009 through +March 9, 2009, our average net daily production from this acreage was 271 BOE and was 100% oil. Plans for 2009 currently include drilling approximately 0.5 net wells for an estimated net cost of $2.5 million. +As of December 31, 2008, we had 25.5 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future +net revenues, discounted at 10%, or PV-10, of approximately $126.2 million and associated standardized measure of discounted future net cash flows of approximately $126.2 million. See Item 2. “Properties—Proved Oil and Natural Gas +Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Principal Oil and Natural Gas Properties +The following table presents certain information as of +December 31, 2008 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas and in the Williston Basin. +Proved Reserves +Field +NRI/WI (1) +Producing +Wells (2) +Non-Producing +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay (4) +80.335/100 +107 +107 +158 +158 +5,668 +5,668 +2,009 +11,391 +13,400 +E. Hackberry (5) +79.424/100 +18 +18 +80 +80 +3,291 +3,291 +282 +2,441 +2,723 +W. Hackberry +87.5/100 +3 +3 +24 +24 +592 +592 +— +132 +132 +Permian +38.075/49.48 +61 +30.5 +— +— +8,075 +4,150 +1,367 +7,028 +8,395 +Bakken (6) +2.285/2.181 +38 +0.8 +— +— +8,153 +891 +47 +776 +823 +Overrides/Royalty Non-operated +Various +9 +.5 +17 +.8 +4,956 +586 +1 +3 +4 +Total +236 +159.8 +279 +262.8 +30,735 +15,178 +3,706 +21,771 +25,477 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes 30 gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 42% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.335% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a +40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +3 +Table of Contents +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water +depths averaging eight to ten feet. We own a 100% working interest (80.335% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated +working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this +field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells +were drilled in the field. Of the 908 wells drilled as of December 31, 2008, 816 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in +1997 through December 31, 2008, we drilled 128 new wells, 15 of which were non-productive, for an 88% success rate. As of December 31, 2008, estimated field cumulative gross production was 188.6 MMBOE and 235.9 billion cubic feet, or Bcf, +of gas. Of the 908 wells drilled in WCBB as of December 31, 2008, 77 were producing, 158 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 638 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an +undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The +reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome +structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The +compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) +was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor +discrete intervals have been tested. Within the 908 wellbores that had been drilled in the field as of December 31, 2008, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a +strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB +are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, +and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of +crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the +mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to +wells +4 +Table of Contents +that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2008 included 81 PUD wells. +The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, six natural gas compressors, a dehydration unit and a salt +water disposal system. +Recent and Future Activity +In 2008, we drilled eight wells and recompleted 48 existing wells at WCBB. Of these eight new wells, seven were completed as producers, and one was non-productive. As of March 1, 2009, we had recompleted seven +wells during 2009. Of the eight wells drilled in 2008, all eight were considered deep wells. The seven productive wells, with total depths ranging from 6,900 to 9,600 feet, have approximately 824 feet of aggregate apparent net pay. We currently +anticipate drilling four wells and recompleting 20 wells at WCBB during 2009. +Production Status +In December 2008, production at WCBB was 109,292 net BOE, or an average of 3,526 BOE per day, 98% of which was from oil and 2% of which was from natural +gas. From January 1, 2009 through March 9, 2009, our average net daily production at WCBB was 3,037 BOE, 99% of which was from oil and 1% of which was from natural gas. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. +We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 7,233 acres, including the Erwin Heirs Block, +which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. +Area History and +Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly +survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through +2008 was over 409,701 barrels of oil and 330 Bcf of casinghead gas production. A total of 187 wells have been drilled on our portion of the field. As of December 31, 2008, 18 wells had daily production, 80 were shut-in and two had been +converted to salt water disposal wells. The remaining 86 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field +entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault +blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +5 +Table of Contents +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the +ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey +at East Hackberry. Given that drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken without the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our +probability of drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2008 at East Hackberry, we drilled four land wells and one well on water and recompleted seven existing wells. All of the +five wells drilled during 2008 were completed as producing wells. As of March 1, 2009, we had recompleted three wells during 2009. We currently intend to drill four land wells and have recompleted three wells at East Hackberry during 2009. +Production Status +In December 2008, +net production at East Hackberry was 12,243 BOE, or an average of 395 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2009 through March 9, 2009, our average net daily production at East +Hackberry was 439 BOE, 95% of which was from oil and 5% of which was from natural gas. Production has increased since year end as a result of mechanical well enhancements. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of +Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States +Department of Energy’s Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between +1938 and 1988. The estimated cumulative oil and condensate production through 2008 was 242 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and +one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West +Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production +of almost 700 MBOE. +Production Status +In December 2008, net production at West Hackberry was 763 BOE, or 25 BOE per day. From January 1, 2009 through March 9, 2009, our average net daily production at West Hackberry was 34 BOE and was 100% oil. +6 +Table of Contents +Facilities +We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, effective date as of +November 1, 2007, from ExL Petroleum, LP and certain other sellers. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The +terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy is the operator of this field. +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a +long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was +not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 +feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill +completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry +Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize +approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. Currently, we hold +interests in 61 gross producing wells. +Geology +The Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The +Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin +Platform. +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Pinnacle +Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2008, proved reserves net to our interest in these assets were approximately 8.4 million BOE, of which 25% were classified as proved +developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 115 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally +characterized as long-lived, with predictable production profiles. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is expected to average gross 145,000 BOE per well or approximately 55,000 BOE net to our +interest. +7 +Table of Contents +Production Status +In December 2008, net production from the Permian field was 26,943 BOE or an average of 869 BOE per day, 59% of which was oil, 25% was natural gas liquids and 16% was natural gas. From January 1, 2009 through +March 9, 2009, our average daily net production from our Permian acreage was 725 BOE per day, 83% of which was from oil and natural gas liquids and 17% of which was from natural gas. As a result of the cessation of drilling, fracing and +recompletion activities, production has decreased since year end due to normal production declines. +Facilities +There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, +oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2008, 31 gross (15.5 net) wells were drilled in our Permian acreage, including one gross well spud in 2007 and completed in 2008 and one Henry +Petroleum operated well. We have identified 147 gross future development drilling locations. We currently expect an estimated three gross (1.5 net) wells to be drilled on our acreage in 2009. The wells are expected to be drilled to approximately +10,200 feet at an estimated average completed gross well cost of $1.34 million. +Bakken +Location and Land +Bakken is located in the Williston +Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. Beginning in 2005, Bakken +acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% +interest in Bakken’s assets in redemption of our 20% interest in Bakken. As a result, we currently hold interests in approximately 17,801 net acres, which includes approximately 4,600 acres in Mountrail Country, in the Bakken play. +As of December 31, 2008, we had participated, or committed to participate, in 53 gross wells in the Williston Basin with an average working +interest of 2.52%. Windsor Energy, the operator of our acreage, drilled and completed the first two Windsor operated wells in 2008. We own working interests of approximately 15.5% and 3.9%, respectively, in these two wells. +Production Status +In December 2008, net production +from the Bakken field was 8,692 BOE, or an average of 280 BOE per day, 100% of which was oil. From January 1, 2009 through March 9, 2009, our average net daily production from this acreage was 271 BOE and was 100% oil. +Facilities +There are typical land oil and gas +processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +8 +Table of Contents +Recent and future activities +In 2008, 37 gross (0.95 net) wells were drilled in our Bakken acreage including both those operated by Windsor and other non-operated wells. We have identified 31 gross future development drilling locations. We +currently expect an estimated 0.5 net wells to be drilled on our Bakken acreage in 2009. The wells are expected to be drilled to approximately 14,500 total measured depth, or TMD, feet at an estimated average gross completed well cost of $4.7 +million. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +2 +5 +Bayou Pigeon +Iberia +6.250 +% +0 +% +4 +5 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +6 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +1 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, +or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During the year ended December 31, 2008, we paid $50,000 in cash calls +and received $912,000 in distributions, bringing our total investment in Tatex (including previous investments) to $2.7 million. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method. +In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. Current net production is approximately 90 Mcf per +day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm +field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2007, net to our interest, are 3.5 BCF of gas and 19,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s +investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +Grizzly +Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and +2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9 +million at December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate of 117 core holes, tested five separate lease blocks and undertook a seismic program. Grizzly’s 2009 plans +currently include drilling approximately 15 additional core holes, which were completed in the first quarter 2009. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of +these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or +9 +Table of Contents +worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such +as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports +of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. +The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil +storage barge. Our production from WCBB, other than the production sold under forward sales contracts, is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month +average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $3.45 per barrel for transportation. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group LLC, or Windsor, the operator +of the Permian wells, 100% of our natural gas liquids production to Windsor, and 60%, 22%, and 16% of our natural gas production to Chevron, Windsor, and Hilcorp Energy Company, respectively. During 2007, we sold 99% of our oil production to Shell +and 69% of our natural gas production to Chevron and 23% of our natural gas production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96% of our natural gas production to Chevron. There can be no +assurance, however, that we will continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and +natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market +conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500 +barrels of WCBB production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had +entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 +million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August +2009. We have also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. For +the period January 2010 through February 2010, we have entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period +March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these contracts, we +have committed to deliver approximately 50% of our estimated 2009 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. +Since these contracts require physical delivery of production quantities, they normally would be exempted from the provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008, +we will not be able to apply this election on new contracts and they will be accounted for at fair value until we re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of +increases in the price of oil. +10 +Table of Contents +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of +legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements +carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, West Texas and the Williston Basin. +These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation +matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas +exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the +U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to +comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and +production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or +former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict liability nature of such laws and +regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, +disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable +environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect +oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the +individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas +are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or +the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to +re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” +Administrative, +civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste +11 +Table of Contents +handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under +such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production +wastes could increase our costs to manage and dispose of such wastes. +Comprehensive Environmental Response, Compensation and Liability +Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or legality of conduct, on classes of +persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the +time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several liability for the costs of cleaning up +the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims +for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. +Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Oil Pollution +Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state waters or waters of the United +States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws and regulations also prohibit certain activity in wetlands unless authorized by a +permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the +treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all permits required under the Clean Water Act. Sanctions for +failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. +Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and +continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations, +and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose +administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air +emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Our air emissions may +also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +Our operations are +subject to all of the risks normally incident to the production of oil and natural gas, including, but not limited to, blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which +12 +Table of Contents +could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury or death to persons and +wildlife. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental +damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully insured against could have a +material adverse effect on our financial position. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of +this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of finished office +area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2008, we had 37 +employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the estimated time they spent working for +those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2008 and 2007, expenses reimbursed to us under these arrangements were +$1.4 million and $11.2 million, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. +Available Information +Our annual +report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor +Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on +other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +13 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/item13.txt b/raw/filings/0000874499/2008/0001193125-09-055183/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..d59469ea08b30410bcc003641e2b3600b2a853b1 --- /dev/null +++ b/raw/filings/0000874499/2008/0001193125-09-055183/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange +Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/item9a.txt b/raw/filings/0000874499/2008/0001193125-09-055183/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..698e291f954d3a667ef6d88742ef7f5a54335e2c --- /dev/null +++ b/raw/filings/0000874499/2008/0001193125-09-055183/item9a.txt @@ -0,0 +1,62 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of +Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to +be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and +procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding +required disclosures. +As of December 31, 2008, an evaluation was performed under the supervision and with the participation of +management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act +of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2008, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that +occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation +of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the +Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the +preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal +control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted +an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its +evaluation under the framework in Internal Control—Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was +effective as of December 31, 2008. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial +statements for the year ended December 31, 2008 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2008, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +48 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of +December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is +responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over +Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We +conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control +over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and +operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the +preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the +maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation +of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and +(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of +effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of +December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We have also audited, in +accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2008 and 2007, and the related consolidated +statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 16, 2009 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 16, 2009 \ No newline at end of file diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/rp_note.txt b/raw/filings/0000874499/2008/0001193125-09-055183/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2008/0001193125-09-055183/rpt_disclosure.txt b/raw/filings/0000874499/2008/0001193125-09-055183/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..0f183afa0a257b027435867e6317d1082bdf10f8 --- /dev/null +++ b/raw/filings/0000874499/2008/0001193125-09-055183/rpt_disclosure.txt @@ -0,0 +1,103 @@ +Certain Relationships and Related Transactions +Administrative Services Agreements +We are or have been a party to administrative service +agreements with Caliber Development Company, LLC, which we refer to as Caliber, Great White Energy Services LLC, which we refer to as Great White, Diamondback Energy Services LLC, which we refer to as Diamondback, and Stampede Investments LLC, which +we refer to as Stampede Investments, which agreements were entered into effective as of February 9, 2005, July 22, 2006, September 26, 2006 and November 1, 2007, respectively. Under these agreements, our services +include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a three-year term, and upon +expiration of that term the agreements will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time +with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. Each of Caliber, Great White, +Diamondback and Stampede Investments reimbursed us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing services for such entity. We were reimbursed +approximately $60,000, $83,000, $10,000 and $0 by Caliber, Great White, Diamondback and Stampede Investments, respectively, for services provided under these agreements during the year ended December 31, 2008. Our administrative services +agreements with Caliber and Diamondback were each terminated effective December 10, 2008. Each of Caliber, Great White and Stampede Investments is, and Diamondback was, controlled by Wexford Capital LLC. Charles Davidson, who beneficially owned +approximately 36% of our outstanding common stock as of April 1, 2009, is the Chairman and Chief Investment Officer of Wexford Capital LLC. Our Chairman of the Board, Mike Liddell, served as the Chairman of the Board of Diamondback Energy +Services, Inc., a subsidiary of Diamondback until December 2008. As of December 2008, Diamondback is no longer controlled by Wexford Capital LLC and is no longer an affiliate of ours. +We are also a party to administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Grizzly Oil Sands ULC, which we refer to as Grizzly, and Everest Operations Management LLC, which +we refer to as Everest, which agreements were each entered into effective March 1, 2008. Under these agreements, our services include professional and technical support. Under our agreements with Stampede Farms and Everest, we also provided +office space during 2008. The services provided under these agreements and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a two-year term, and upon expiration of that +term such agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at least 60 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time +with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We were reimbursed approximately +$159,000, $368,000 and $154,000 by Stampede Farms, Grizzly and Everest, respectively, for services provided under these agreements during the year ended December 31, 2008. We were also reimbursed approximately $20,000 and 26,000 by Stampede +Farms and Everest, respectively, for office space under these agreements for the year ended December 31, 2008. Each of Stampede Farms, Grizzly and Everest is controlled by Wexford Capital LLC. +28 +Table of Contents +Effective July 1, 2008, we entered into an acquisition team agreement with Everest to identify and evaluate +potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, the +party whose acquisition team identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share +of the acquisition or divestiture consideration. The agreement has a one year term unless earlier terminated by either party upon 30 days notice. +We +provide professional support, office space, furniture, telecommunications and computer and other information technology support to Windsor Energy Resources LLC, or Windsor, and Everest. Both Windsor and Everest have agreed to reimburse us for such +services based on the number of employees we office and nature of services provided by us to each respective company, which can vary from time to time. We were reimbursed an aggregate of approximately $469,000 for the above services provided to +Windsor and Everest for the year ended December 31, 2008. Both Windsor and Everest are controlled by Wexford Capital LLC. +From time to time, various +members of our scientific staff provide services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to Tatex Thailand II, LLC, or Tatex II, and Tatex Thailand III +LLC, or Tatex III. Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our staff to such entities. Tatex II and Tatex III are controlled by Wexford +Capital LLC. +We provide certain general and administrative services to Floran Technologies LLC, or Floran. We are reimbursed for our dedicated employee +time and related general and administrative costs based on the proportionate amount of time our employees spent performing such services. For the year ended December 31, 2008, we were reimbursed approximately $46,000 by Floran and were owed an +additional $16,000 for such services at that date. +Services Provided to Us by Our Affiliates +We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge services in our West Cote Blanche Bay, or WCBB, and Hackberry fields located +along the Louisiana Gulf Coast. For the year ended December 31, 2008, we paid Athena $3,888,000 and owed an additional $759,000 for such services at that date. Athena is controlled by Wexford Capital LLC. +Windsor Energy Group operates our Permian Basin wells in West Texas. For the year ended December 31, 2008, we paid Windsor Energy Group $39,137,000 and owed an +additional $3,724,000 for such services at that date. Windsor Energy Group is controlled by Wexford Capital LLC. +Packers & Service Tools, Inc., +which we refer to as Packers, performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2008, we paid Packers $1,966,000 owed an additional $465,000 related to these services at that date. Packers was controlled +by Wexford Capital LLC until November 18, 2008. On that date, Packers ceased to be an affiliate of ours. +Diamondback Completions LLC, which we refer +to as Completions, performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2008, we paid Completions $444,000 and owed an additional $24,000 related to these services at that date. Completions were controlled +by Wexford Capital LLC until November 18, 2008. On that date, Completions ceased to be an affiliate of ours. +Great White Towing LLC, which we refer +to as Towing, performs services for us at our WCBB field. For the year ended December 31, 2008, we paid Towing $269,000 and owed an additional $222,000 related to these services at that date. Towing is an entity controlled by Wexford Capital +LLC. +29 +Table of Contents +Effective March 1, 2008, Windsor provides tax planning, preparation of supporting tax schedules and consultation +services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of the parties. Windsor is controlled by Wexford Capital LLC. +Caliber provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. For the year ended December 31, 2008, we paid Caliber $20,000 and owed an additional $2,000 at that date. Caliber is +an entity controlled by Wexford Capital LLC. +Our Investments in Affiliates and Related Agreements +During 2005, we purchased a 23.5% ownership interest in Tatex II at a cost of $2,400,000. The remaining interests in Tatex II are owned by other entities controlled by +Wexford Capital LLC. Tatex II, a privately-owned entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its +ownership of concessions covering three million acres which includes the Phu Horm Field. During 2008, we paid $50,000 and received $912,000 in distributions in respect of our investment in Tatex II. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. Approximately 68.7% of the remaining interests in Tatex III +are owned by other entities and individuals affiliated with Wexford Capital LLC. During 2008, we paid $35,000 in cash calls in respect of our investment in Tatex III. +During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken, with the remaining interests in Bakken owned by other entities controlled by Wexford Capital LLC. In 2006, Bakken acquired leases +on undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana, which we refer to as the contract area. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in +redemption of our 20% interest in Bakken. +Effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor +Dakota LLC, or Windsor Dakota, to jointly acquire oil and gas leases on certain lands located in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each +party must offer the other party the right to participate in such acquisition in proportion to its participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain +exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy +Group, L.L.C., as the operator, also entered into an exploration agreement, effective as of January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and Windsor +Energy Group, L.L.C. agreed to act as the operator under the terms of a joint operating agreement. In the event Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport +as the operator. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. +During the third quarter of 2006, we purchased, through our wholly owned subsidiary Grizzly Holdings, Inc., a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for approximately $8,200,000. The +remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LLC. During 2006, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. +Grizzly has commenced drilling of core holes for feasability of oil production in five separate lease blocks but has not commenced development of operations. As of December 31, 2008, our net investment in Grizzly was $21,881,000. +We, through our wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow +funds from us. Borrowed funds bear interest at +30 +Table of Contents +LIBOR plus 4%. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan matures on December 31, 2012. We +loaned Grizzly approximately $10,519,000 during the year ended December 31, 2008. The Company recognized interest income of approximately $410,000 for the year ended December 31, 2008 under this loan agreement. The note balance was +decreased by approximately $1,776,000 as a result of a currency translation loss for the year ended December 31, 2008. +Option and Purchase Agreement and Related Agreements +On November 30, 2007, we entered into an option +agreement with Windsor Permian LLC, an entity controlled by Wexford Capital LLC, which we refer to as Windsor Permian. Under the option agreement, we were granted the right to participate on a 50/50 basis with Windsor Permian in the acquisition of +certain strategic assets in Upton County, Texas in the Permian Basin. On December 12, 2007, we exercised the option and on December 18, 2007, the purchase agreement was amended to, among other things, add Gulfport as a buyer under the +purchase agreement. On December 20, 2007, the acquisition was closed, effective as of November 1, 2007. We and Windsor Permian also agreed to share equally all third-party costs and expenses incurred by each of us in connection with the +transaction. +In addition, effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly +acquire oil and gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party +costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. On March 20, 2008, in connection with this agreement, we received a six-month option to acquire a direct, +undivided interest of up to 25% in Windsor Permian’s oil and gas interests acquired on February 29, 2008 in Midland County, Texas. The option price is the sum of (i) the option percentage of the acquisition consideration paid by +Windsor Permian to a third party in connection with the acquisitions of these assets, subject to certain exceptions, (ii) a fee equal to 1% of our purchase price, (iii) the option percentage of the sum of all third-party costs and expenses +incurred by Windsor Permian in connection with the acquisition of these assets, subject to certain exceptions, (iv) the option percentage of all capital costs and lease operating expenses incurred subsequent to Windsor Permian’s +acquisition of these assets and prior to the date of the option exercise by Gulfport, subject to certain exceptions, and (v) interest, at 8% per annum, on the amounts set forth in items (i), (iii) and (iv) calculated from the +time of accrual to the closing date of the option. +In connection with the area of mutual interest agreement, we, Windsor Permian and Windsor Energy Group, +L.L.C., as the operator, entered into the joint development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy +Group, L.L.C. agreed to act as the operator under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either party has greater than a 50% interest in a prospect, as defined in the development agreement, +the majority party may designate the operator of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. +31 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/filing.txt b/raw/filings/0000874499/2009/0001193125-10-055121/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..dfff317882cfe9d40336a7db710130ff04883d0c --- /dev/null +++ b/raw/filings/0000874499/2009/0001193125-10-055121/filing.txt @@ -0,0 +1,5648 @@ +10-K +1 +d10k.htm +FORM 10-K +Form 10-K +Table of Contents +Index to Financial Statements +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +x +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2009 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission File Number: 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant as Specified in +Its Charter) +Delaware +73-1521290 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip code) +(405) +848-8807 +(Registrant’s Telephone Number, Including Area Code) +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ +No x +Indicate by check mark if the +registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports +required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing +requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such +files). Yes ¨ No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is +not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an +accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check +one): +Large Accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, 2009, based on the closing price of the common stock on the NASDAQ Global Select Market on +June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter ($6.85 per share) was $182,710,913. +As of March 1, 2010, 42,697,402 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy +Corporation’s Proxy Statement for the 2010 Annual Meeting of Stockholders are incorporated by reference in Items 9, 10, 11, 12 and 13 of Part III of this Form 10-K. +Table of Contents +Index to Financial Statements +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +DESCRIPTION OF BUSINESS +2 +ITEM 1A. +RISK FACTORS +14 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +25 +ITEM 2. +PROPERTIES +25 +ITEM 3. +LEGAL PROCEEDINGS +30 +ITEM 4. +RESERVED +31 +PART II +32 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +32 +ITEM 6. +SELECTED FINANCIAL DATA +33 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +35 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +50 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +51 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL +DISCLOSURE +51 +ITEM 9A. +CONTROLS AND PROCEDURES +51 +ITEM 9B. +OTHER INFORMATION +53 +PART III +54 +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +54 +ITEM 11. +EXECUTIVE COMPENSATION +54 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER +MATTERS +54 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +54 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +54 +PART IV +55 +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +55 +Signatures +S-1 +Index to Consolidated Financial Statements +F-1 +Exhibit Index +E-1 +i +Table of Contents +Index to Financial Statements +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the +Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and +uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed +or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” +“plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. +All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net +revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our +business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions +reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and +uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees +of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking +statements due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements +speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all +forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +Index to Financial Statements +PART I +ITEM 1. +DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located +along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil +Sands ULC, or Grizzly, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2009, at our WCBB field, we recompleted 56 wells and drilled 11 wells for a total cost of approximately $19.6 million as of +December 31, 2009. Of our 11 new wells drilled at WCBB in 2009, 10 were completed as producing wells and one was non-productive. During 2010, we currently anticipate drilling 20 wells and recompleting 40 wells at our WCBB field for an estimated +aggregate cost of $33.0 to $36.0 million. In December 2009, production at WCBB was 116,637 net barrels of oil equivalent, or BOE, or an average of 3,762 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From +January 1, 2010 through February 28, 2010, our average net daily production at WCBB was 3,432 BOE, 98% of which was from oil and 2% of which was from natural gas. +In 2009, at our East Hackberry field, we recompleted five wells and drilled six wells for a total cost of approximately $11.0 million as of +December 31, 2009. All wells drilled during 2009 were completed as producing wells. During 2010, we currently anticipate drilling three wells and recompleting five wells for an aggregate estimated cost of $6.0 to $7.0 million. In December 2009, +net production at East Hackberry was 13,284 BOE, or an average of 429 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production at East +Hackberry was 814 BOE, 96% of which was from oil and 4% of which was from natural gas. +In December 2009, net production at +West Hackberry was 1,202 BOE, or an average of 39 BOE per day, 100% of which was from oil. From January 1, 2010 through February 28, 2010, our average net daily production at West Hackberry was 44 BOE, 100% of which was from oil. +Effective November 1, 2007, we acquired approximately 4,100 net acres in West Texas in the Permian Basin with production +at the time of acquisition from 32 gross wells, predominately from the Wolfcamp formation. In 2008, 31 gross (15.5 net) wells were drilled on this acreage. In 2009, we acquired an additional 4,095 net acres, bringing our total net acreage position +in the Permian Basin to approximately 8,200 net acres. During the year ended December 31, 2009, we drilled four gross wells and recompleted three gross wells on this acreage. As of March 1, 2010, three of the four wells had been completed +and the other well was awaiting completion. We currently anticipate drilling 24 to 26 gross (12 to 13 net) wells on this acreage in 2010 for an estimated aggregate cost of $15.0 to $17.0 million. In December 2009, net production from our Permian +acreage was 17,030 BOE, or an average of 549 BOE per day, 82% of which was from oil and natural gas liquids and 18% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net production from our +Permian acreage was 507 BOE per day, 82% of which was from oil and natural gas liquids and 18% of which was from natural gas. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, +Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our total net investment in Grizzly was +approximately $41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one +water supply test well, tested five +2 +Table of Contents +Index to Financial Statements +separate lease blocks and conducted a seismic program. Grizzly recently filed an application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and +its currently contemplated 2010 activities relate primarily to initial preparations for this facility. +During 2005, we +purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford Capital, LP, or Wexford. Affiliates of Wexford beneficially own approximately 36% of our +outstanding common stock. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its +ownership of concessions covering three million acres which includes the Phu Horm Field. +We also own a 17.9% ownership +interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering one million acres. During 2009, the operator conducted a +3-D seismic survey on this concession. During 2010, we expect to participate in the drilling of two wells. +During 2005, we +purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. In 2006, Bakken acquired leases for undeveloped acreage in the Williston Basin area of western North Dakota and eastern Montana. Effective January 1, 2008, we acquired a +direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an +effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for $5.8 million with an effective date of July 1, 2009. As of December 31, 2009, we held approximately 900 net acres and +interests in 28 wells, as well as certain wells that might be drilled in the future. +In December 2009, net production from +our remaining Bakken acreage was 2,092 BOE, or an average of 67 BOE per day, 97% of which was from oil and natural gas liquids and 3% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net +production from our Bakken acreage was 66 BOE per day, 95% of which was from oil and 5% of which was from natural gas. +As of +December 31, 2009, we had 19.9 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $263 million and associated standardized +measure of discounted future net cash flows of approximately $240.8 million. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our +standardized measure of discounted future net cash flows to PV-10. +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2009 reflecting our net interest in our principal producing oil and +natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas and in the Williston Basin. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay Field (4) +80.108/100 +95 +95 +181 +181 +5,668 +5,668 +262 +5,028 +5,290 +E. Hackberry Field (5) +79.424/100 +18 +18 +86 +86 +3,291 +3,291 +308 +2,490 +2,798 +W. Hackberry Field +87.5/100 +3 +3 +24 +24 +592 +592 +— +172 +172 +Permian Basin +38.075/49.48 +64 +32 +— +— +8,157 +4,078 +1,816 +9,763 +11,579 +Williston Basin (6) +3.08/4.10 +4 +1 +— +— +2,560 +127 +2 +32 +34 +Overrides/Royalty Non-operated +Various +32 +1 +17 +2 +— +— +1 +3 +4 +Total +216 +150 +308 +293 +20,268 +13,756 +2,389 +17,488 +19,877 +3 +Table of Contents +Index to Financial Statements +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes nine gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 68% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. +We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in +depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 +based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in +the field. Of the 919 wells drilled as of December 31, 2009, 826 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through +December 31, 2009, we drilled 139 new wells, 16 of which were non-productive, for an 88% success rate. As of December 31, 2009, estimated field cumulative gross production was 190.1 MMBOE and 236.1 billion cubic feet, or Bcf, of gas. Of +the 919 wells drilled in WCBB as of December 31, 2009, 86 were producing, 181 were shut-in, nine were producing intermittently and five were being used as salt water disposal wells. The other 638 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In +1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the +data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected +deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large +graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs +recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 919 wellbores that had been drilled in the field as of December 31, 2009, over 4,000 potential zones have been penetrated. +These sands are highly porous and permeable reservoirs primarily with a strong water drive. +4 +Table of Contents +Index to Financial Statements +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, +or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of +these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does +introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new +wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets +are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2009 included 21 PUD wells. The drilling schedule used in the reserve report anticipates that +all of those wells will be drilled by 2012. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, six natural gas compressors, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2009, we recompleted 56 wells and drilled 11 wells at WCBB. Of these 11 new wells, 10 were completed as producers, and one was non-productive. As of February 28, 2010, we had recompleted eight wells during 2010. Of the 11 wells +drilled in 2009, none were considered deep wells. The ten productive wells, with total depths ranging from 2,500 to 10,325 feet, have approximately 1,077 feet of aggregate apparent net pay. We currently anticipate drilling 20 wells and recompleting +40 wells at WCBB during 2010. +Production Status +In December 2009, production at WCBB was 116,637 net BOE, or an average of 3,762 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2010 through +February 28, 2010, our average net daily production at WCBB was 3,432 BOE, 98% of which was from oil and 2% of which was from natural gas. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately +79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 7,738 acres, including the Erwin Heirs Block, which is located on land, and the adjacent +State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive +shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2009 was over +597,172 barrels of oil and 330 Bcf of casinghead gas production. A total of 193 wells have been drilled on our portion of the field. As of December 31, 2009, 18 wells had daily production, 86 were shut-in and two had been converted to salt +water disposal wells. The remaining 87 wells had been plugged and abandoned. +5 +Table of Contents +Index to Financial Statements +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry +acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. +These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we +completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure +natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at +this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2009 at East Hackberry, we recompleted five wells and +drilled four land wells and two wells on water. All of the six wells drilled during 2009 were completed as producing wells. As of February 28, 2010, we had not recompleted or drilled any wells during 2010. We currently intend to drill three +land wells and recomplete five wells at East Hackberry during 2010. +Production Status +In December 2009, net production at East Hackberry was 13,284 BOE, or an average of 429 BOE per day, 96% of which was from oil and 4% of +which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production at East Hackberry was 814 BOE, 96% of which was from oil and 4% of which was from natural gas. Production has increased as a +result of the successful drilling and completion of four wells during the fourth quarter of 2009. +West Hackberry Field +Location and Land +The West +Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) +in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves. +Area History +The first +discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2009 was 261 MBOE and 140 Bcf +of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and +abandoned. +6 +Table of Contents +Index to Financial Statements +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in +the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In +December 2009, net production at West Hackberry was 1,202 BOE, or 39 BOE per day. From January 1, 2010 through February 28, 2010, our average net daily production at West Hackberry was 44 BOE and was 100% oil. +Facilities +We have +land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, effective date as of +November 1, 2007, from ExL Petroleum, LP and certain other sellers. Subsequently, we acquired an additional 4,095 net acres, bringing our total acreage position to approximately 8,200 net acres as of December 31, 2009. The Permian Basin +area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy is +the operator of this field. +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found +in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the +greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp +formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian +wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private +company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to +participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2009, we hold interests in 64 gross producing wells. +Geology +The +Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is +characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +7 +Table of Contents +Index to Financial Statements +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% +from the Spraberry section. Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2009, proved reserves net to our interest in these assets were approximately 11.6 million BOE, of +which 12% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 191 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry +formations, which are generally characterized as long-lived, with predictable production profiles. +Production Status +In December 2009, net production from the Permian field was 17,030 BOE, or an average of 549 BOE per day, 82% of which was from oil and +natural gas liquids, and 18% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net production from our Permian acreage was 507 BOE per day, 82% of which was from oil and natural gas liquids +and 18% of which was from natural gas. As a result of the reduction of drilling, fracing and recompletion activities, production has decreased since year end due to normal production declines. +Facilities +There are +typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2009, four gross (two net) wells were drilled in our Permian acreage. We have identified 191 gross future development drilling locations. We currently expect an estimated 24 to 26 gross (12 to 13 net) wells to be drilled on our acreage +in 2010. The wells are expected to be drilled to approximately 10,200 feet. +Bakken +Location and Land +The +Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities +controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective +January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for +approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2009, we held +approximately 900 net acres and interests in 28 wells, as well as interests in certain wells that might be drilled in the future. +Production Status +In December 2009, net production from our Bakken acreage was 2,092 BOE, or an average of 67 +BOE per day, 97% of which was from oil and natural gas liquids and 3% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production from this acreage was 66 BOE, of which 95% was from oil +and 5% was from natural gas liquids. +8 +Table of Contents +Index to Financial Statements +Facilities +There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping +units. +Recent and future activities +As a result of the sale transactions described above, we have no activities currently scheduled for 2010 in the Williston Basin. +Additional Properties +Louisiana . In addition to our interests in +the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +1 +6 +Bayou Pigeon +Iberia +6.250 +% +0 +% +4 +5 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +6 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +1 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . During +2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 +outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +During the year ended December 31, 2009 we paid $320,000 in cash calls and received $517,000 in distributions, bringing our total investment in Tatex (including previous investments) to $2.5 million. Our investment is accounted for on the +equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately +60 million cubic feet per day. For December 2009, net gas production was approximately 83 MMcf per day and condensate production was 452 Bbl’s per day. Hess Corporation operates the field with a 35% interest. Other interest owners include +APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2008, +net to our interest, are 2.739 BCF of gas. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve +information. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, +at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2009, we paid $428,000 in cash calls, bringing our total investment in Tatex III to $4,482,000. Currently, we plan to participate in the +drilling of two wells during 2010. +Grizzly Oil Sands . During the third quarter of 2006, we, through our wholly-owned +subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the +9 +Table of Contents +Index to Financial Statements +Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our total net investment in Grizzly was approximately +$41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one water supply +test well, tested five separate lease blocks and conducted a seismic program. Grizzly recently filed an application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and its currently contemplated +2010 activities relate primarily to initial preparations for the facility. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these +companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to +take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control +of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the +effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are +located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB, other than the production sold under forward sales contracts, is being +sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $3.45 per barrel for +transportation. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor Energy Group, Chevron and +Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and 16% of our natural gas production to +Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. During 2007, we sold 99% of our oil production to Shell and 69% and 23% of our natural gas production to Chevron and Hilcorp, respectively. We may not continue to have ready +access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely +volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil +and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000 +barrels of WCBB production at a weighted average price of $55.01 per barrel before transportation costs. We delivered approximately 49% of our 2009 production under these agreements. Initially, for the period January through December 2009, we had +entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 +million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August +2009. We also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September +10 +Table of Contents +Index to Financial Statements +2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and May 2009 for an aggregate of approximately $2.0 million. For the period January 2010 through +February 2010 we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 through December 2010, we +have entered into forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before transportation costs. Under these contracts, we have committed to deliver approximately +45% of our estimated 2010 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit +the benefit to us of increases in the price of oil. These forward sales contacts are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements. +Regulation +Regulation of +Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation +and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties +for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, West Texas and the Williston Basin. These states regulate the production and sale of oil +and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and +natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development +and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental +Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws +and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production +activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former +operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict liability nature of such laws and regulations +could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup +requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and +regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated +thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and +11 +Table of Contents +Index to Financial Statements +cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more +stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that +are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes +or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous +wastes.” +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling +requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations +require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas +exploration and production wastes could increase our costs to manage and dispose of such wastes. +Comprehensive +Environmental Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without +regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated +facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to +strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for +neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, +would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such +“hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of +1972, as amended, also known as the Clean Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and +other gas and oil wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws and regulations +also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits +for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all +permits required under the Clean Water Act. Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. +Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants +through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required +to obtain permits before work can begin, permits may be required for our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of +compliance for some facilities we own or +12 +Table of Contents +Index to Financial Statements +operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act +and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or +renewing permits has the potential to delay the development of oil and natural gas projects. Our air emissions may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are +emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including, but not limited to, +blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury or death to persons and +wildlife. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental +damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully insured against could have a +material adverse effect on our financial position. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a +portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of +finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At +December 31, 2009, we had 40 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the +estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2009 and 2008, expenses reimbursed +to us under these arrangements were $0.6 million and $1.4 million, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate +the WCBB and the Hackberry fields. +Available Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange +Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange +Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other +filing that we make with the SEC. +13 +Table of Contents +Index to Financial Statements +ITEM 1A. +RISK FACTORS +Risks Related to Our +Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas +properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety +of additional factors that are beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +• +weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +political instability or armed conflict in oil and natural gas producing regions; and +• +the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate posted +price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.73 per million British thermal units, or +MMBtu, in September 2009 to a high of $15.52 per MMBtu in December 2005. On December 31, 2009, the West Texas Intermediate posted price for crude oil was $79.39 per bbl and the Henry Hub spot market price of natural gas was $5.83 per MMBtu. Any +substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write +downs of oil and natural gas properties due to ceiling test limitations. +Declining general economic, business or industry conditions may +have a material adverse effect on our results of operations, liquidity and financial condition. +Recently, concerns over +inflation, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished +expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a +recession. Concerns about global +14 +Table of Contents +Index to Financial Statements +economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for +petroleum products could continue to diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect our vendors, suppliers and customers ability to continue operations, and ultimately adversely +impact our results of operations, liquidity and financial condition. +Our success depends on finding, developing or acquiring additional +reserves. +Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves +that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. +To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect in the future to make substantial capital expenditures in our +business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity securities and +borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the level of oil and natural gas we are able to produce from existing wells; +• +the prices at which oil and natural gas are sold; and +• +our ability to acquire, locate and produce new reserves. +We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and +natural gas reserves, our exploratory projects or other replacement activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our +revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to +complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and management +information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in +turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +Our Canadian oil sands project is a complex undertaking and may not be completed at our estimated cost or at all. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The +remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly +has approximately 527,000 acres under lease and our total net investment in Grizzly was approximately $41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter +delineation +15 +Table of Contents +Index to Financial Statements +drilling seasons, Grizzly drilled an aggregate of 131 core holes and one water supply test well, tested five separate lease blocks and conducted a seismic program. Grizzly recently filed an +application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and its currently contemplated 2010 activities relate primarily to initial preparations for the facility. This is a complex project and +financing has not been secured. This project may not be completed at our estimated cost or at all. +Shortage of rigs, equipment, supplies +or personnel may restrict our operations. +The oil and natural gas industry is cyclical, which can result in a shortage of +drilling rigs, equipment, supplies and personnel. As a result, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in the number of active +rigs in service. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, supplies, personnel, trucking +services, tubulars, fracing and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations. +We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues. +Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the +loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists, Stuart Maier and Randy Wilson, could disrupt our operations resulting in a loss of +revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Liddell, and our executives are not restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, +any employment agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses +resulting from the death of our key employees. +Our proved reserves and related PV-10 as of December 31, 2009 have been reported under +new SEC rules that went into effect on January 1, 2010. The estimates provided in accordance with the new SEC rules may change materially as a result of interpretive guidance that may be released by the SEC. +We have included in this report certain estimates of our proved reserves and related PV-10 at December 31, 2009 as prepared consistent +with our and our independent reserve engineers’ interpretations of the new SEC rules relating to disclosures of estimated natural gas and oil reserves. These new rules are effective for fiscal years ending on or after December 31, 2009. +These newly adopted rules will require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The SEC has not reviewed our +reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules. Accordingly, while the estimates of our proved reserves and related PV-10 at December 31, +2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare +applying more specific SEC interpretive guidance. +We may be limited in our ability to book additional proved undeveloped reserves under +the new SEC rules. +Another impact of the new SEC reserve rules is a general requirement that, subject to limited +exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue +our drilling program. +16 +Table of Contents +Index to Financial Statements +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual +production. +There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting +future rates of production and timing of expenditures. The reserve information included in this report represents only estimates based on reports prepared by Netherland, Sewell & Associates, Inc., or NSAI, as of December 31, 2009 with +respect to our WCBB field, by Pinnacle Energy Services, LLC, or Pinnacle, with respect to our assets in the Permian Basin in West Texas and by our personnel with respect to our Hackberry fields and our overrides and non-operated interests. Petroleum +engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily +depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by +governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual +results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net +cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such +variances may be material. +Estimates of reserves as of year-end 2009 were prepared using an average price +equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2009, in accordance with revised guidelines of the SEC applicable +to reserves estimates as of year-end 2009. Estimates of reserves as of year-end 2007 and 2008 were prepared using constant prices and costs in accordance with previous guidelines of the SEC based on hydrocarbon prices received on a field-by-field +basis as of December 31 st of each year. Reserve +estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. +The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated +oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves on average price equal to the unweighted average of prices received on a field-by-field basis on the first day of each month within the +12-month period ended December 31, 2009, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009. Estimated discounted future net revenue from reserves as of year-end 2008 and 2007 were prepared using +constant prices and costs in accordance with previous guidelines of the SEC as of December 31st of the applicable year. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from +proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time +and risks associated with us or the oil and natural gas industry in general. +As of December 31, 2009, approximately 65% +of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures and +conduct these operations successfully, but these assumptions may not be accurate, and this may not occur. +17 +Table of Contents +Index to Financial Statements +There are numerous uncertainties in estimating quantities of bitumen reserves and resources and the +indicated level of reserves or recovery of bitumen may not be realized. +There are numerous uncertainties in estimating +quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are +based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental +agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree +of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or +by the same engineers at different times, may vary substantially. +Estimates with respect to reserves and resources that may +be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those +based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production +experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or +quality of bitumen to be produced from Grizzly’s lands cannot be determined at this time. +The marketability of our production is +dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced. +The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines +and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our +compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and +natural gas produced at our WCBB field, which is our largest field. In October 2006, for example, a natural gas line in this field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for +approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. If, in the future, we are unable, for any sustained +period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we will be required to again shut in or curtail production from the field. Any such shut in or curtailment, or +an inability to obtain favorable terms for delivery of the oil and natural gas produced from the field, would adversely affect our financial condition and results of operations. +A substantial portion of our producing properties is located in Louisiana, making us vulnerable to risks associated with operating in this region. +Our operations are concentrated in Louisiana and our largest field, WCBB, is located approximately five miles off the coast of Louisiana in a +shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions such as fog or rain, hurricanes or +other natural disasters, or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable +or that any particular types of coverage will be available. +18 +Table of Contents +Index to Financial Statements +Our identified drilling locations, which are part of our anticipated future drilling plans, are +susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified +over 350 drilling locations on our Louisiana and West Texas properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including +the availability of capital, oil and natural gas prices, inclement weather, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will +be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. +Operating hazards and uninsured risks may result in substantial losses. +Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, pipe failure, +abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe +damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. For example, in October 2006, an accident +occurred north of our production facilities in the WCBB field in southern Louisiana involving two contracted vessels that were performing work on our behalf in the field. A tugboat and two barges laden with construction materials ruptured an +underwater natural gas pipeline and a subsequent fire damaged the vessels. Six fatalities resulted from the accident. Several lawsuits relating to this incident were filed against us, among other parties. These lawsuits against us have all been +settled. +In accordance with customary industry practice, we historically have maintained insurance against some, but not all, +of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. In +addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may also be liable for environmental damage caused by +previous owners of properties purchased by us, which liabilities may not be covered by insurance. +Our operations are subject to various +governmental regulations which require compliance that can be burdensome and expensive. +Our oil and natural gas operations +are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, +drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow +of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, emission and disposal of oil and gas, by-products thereof and other substances and +materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations relating to protection of human health and the environment. These laws and regulations have +continually imposed increasingly strict requirements for water and air pollution control and waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more +expansive and stricter environmental legislation and regulations will continue. +19 +Table of Contents +Index to Financial Statements +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in +increased costs and additional operating restrictions or delays. +Congress is currently considering legislation to amend +the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock +formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The +proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on +allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays +or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. +The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we +produce . +On December 15, 2009, the EPA officially published its findings that emissions of +carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other +climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late +September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse +gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission +sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could +require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil, natural gas and NGLs that we produce. +Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or +“ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 +levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas +emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion +of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of +legislation to reduce greenhouse gas emissions through an emission allowance system. +Although it is not possible at this time +to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could +require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce. +Even if such legislation is not adopted at the national level, more than one-third of the states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce emissions of greenhouse gases, as +have a number of local governments. Although most of the regional and state-level +20 +Table of Contents +Index to Financial Statements +initiatives have to date been focused on large sources of greenhouse gas emissions, such as coal-fired electric power plants, smaller sources of emissions could become subject to greenhouse gas +emission limitations, allowance purchase requirements or other restrictions or costs. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of +operations. +Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse +gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they +could have an adverse effect on our assets and operations. +We face extensive competition in our industry. +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these +companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to +take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +We depend upon two customers for the sale of most of our oil and natural gas production. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our +management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil +and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell +Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB, other than the production sold under forward sales contracts, is being sold in accordance with the Shell posted price for +West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $3.45 per barrel for transportation. During 2009, we sold 92% and 7% of +our oil production to Shell and Windsor Energy Group, respectively and 45%, 38%, and 16% of our natural gas production to Windsor Energy Group, Chevron and Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell +and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and 16% of our natural gas production to Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. During 2007, we sold +99% of our oil production to Shell and 69% and 23% of our natural gas production to Chevron and Hilcorp, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Our method of accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and +certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, +discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are +depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. +Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized +costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center +21 +Table of Contents +Index to Financial Statements +ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average +of the first-day-of-the-month prices for 2009 and prior to 2009, unescalated year-end prices, adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, and excluding the estimated abandonment +costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being +amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or +noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. If +prices of oil, natural gas and natural gas liquids decrease, we may be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of operations. +Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could +adversely affect the results of our drilling operations. +Even when properly used and interpreted, 2-D and 3-D seismic data +and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In +addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not +be successful or economical. +We have entered into forward sales contracts and may in the future enter into additional contracts for a +portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. +To mitigate the effects of commodity price fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000 barrels of WCBB production at a weighted average price of $55.01 per +barrel before transportation costs. We delivered approximately 49% of our 2009 production under these agreements. Initially, for the period January through December 2009, we had entered into agreements to sell 3,000 barrels of WCBB production per +day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. Subsequently, we entered into forward sales contracts +for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We also entered into forward sales contracts for the sale of +3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and +May 2009 for an aggregate of approximately $2.0 million. For the period January 2010 through February 2010 we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 +per barrel, before transportation costs. For the period March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, +before transportation costs. Under these contracts, we have committed to deliver approximately 45% of our estimated 2010 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where +production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contacts are accounted for as cash flow hedges and recorded at fair value +pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements. +22 +Table of Contents +Index to Financial Statements +A terrorist attack or armed conflict could harm our business. +Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect +the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural +gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if +infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at +all. +Conservation measures and technological advances could reduce demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological +advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, +results of operations and cash flows. +Risks Related to Our Common Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number +of factors could cause these fluctuations, including: +• +changes in oil and natural gas prices; +• +changes in production levels; +• +changes in governmental regulations and taxes; +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary +significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some +future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +Our officers and directors together with our largest stockholder beneficially own a significant percentage of our common stock, and their interests may +conflict with those of our other stockholders. +As of December 31, 2009, our executive officers and directors, in the +aggregate, beneficially owned approximately 3% of our outstanding common stock and Charles E. Davidson, one of our major stockholders, beneficially owned approximately 36% of our outstanding common stock. As a result, these stockholders acting +together are able to exercise significant influence over most matters requiring approval by our stockholders, including the election of directors and the approval of significant corporate transactions. Such a concentration of ownership may have the +effect of delaying or preventing a change in control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices. +23 +Table of Contents +Index to Financial Statements +An active trading market for our common stock may not develop or be sustained. +Since July 14, 2006, our common stock has been listed on The NASDAQ Global Select Market under the symbol “GPOR.” From +February 28, 2006 until that date, our common stock was listed on the NASDAQ National Market. Prior to that date, our common stock was traded on the NASD OTC Bulletin Board under the symbol “GPOR.OB.” There is a limited market for our +shares. An active trading market may not develop, or if it does, it may not be sustained. +We do not currently pay dividends on our common +stock and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and we may not pay +cash dividends on our common stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit +agreement prohibit the payment of any dividends to the holders of our common stock. +A change of control could limit our use of net +operating losses. +As of December 31, 2009, we had a net operating loss, or NOL, carry forward of approximately $55.7 +million for federal income tax purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of +NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +Future sales of our common stock may depress our stock price. +We and certain of our stockholders have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the +public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of +common or preferred stock. As of March 1, 2010, there were 42,697,402 shares of our common stock issued and outstanding, excluding 59,251 shares of restricted stock awarded under our 2005 Stock Incentive Plan. +We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our +common stock or which could have anti-takeover effects. +We are authorized to issue up to 5,000,000 shares of preferred +stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively +designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other +series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the +designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock +could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock. +In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors +to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders. +24 +Table of Contents +Index to Financial Statements +The existence of some provisions in our organizational documents could delay or prevent a +change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None +ITEM 2. +PROPERTIES +Proved Oil and Natural Gas +Reserves +Recent SEC Rule-Making Activity +In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” The new rules require disclosure of oil and gas proved reserves by significant geographic area, +using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the +following: +• +Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis. +• +Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities +will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. +• +Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production +history. +• +Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees +the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. +• +Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method +of extraction. +We adopted the rules effective December 31, 2009, as required by the SEC. +Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and natural gas than +would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in proved reserves of approximately 19,877 Mboe. Use of the old year-end prices rules would have resulted in proved +reserves of approximately 20,241 Mboe at December 31, 2009. Accordingly, the total impact of the new price methodology rules resulted in a negative reserve revision of 364 Mboe. +Total proved reserves were 19,877 Mboe at December 31, 2009 and 25,477 Mboe at December 31, 2008. Approximately 7,375 Mboe of this +decrease is attributable to our exclusion from proved undeveloped reserves of 81 PUD locations that were not scheduled to be drilled within the next five years in accordance with the new SEC rules. +Evaluation and Review of Reserves. +Reserve estimates at December 31, 2009 were prepared by NSAI with respect to our WCBB field (27% of our proved reserves at December 31, 2009), by Pinnacle with respect to our assets in the Permian Basin in West Texas (58% of our +proved reserves at December 31, 2009) and by our personnel with respect to our Hackberry fields and our overriding royalty and non-operated interests (15% of our proved reserves at December 31, 2009). +25 +Table of Contents +Index to Financial Statements +NSAI and Pinnacle are independent petroleum engineering firms. Copies of their summary +reserve reports are included as Exhibit 99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, +objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest +in any of our properties and are not employed by us on a contingent basis. +We maintain an internal staff of petroleum +engineers and geoscience professionals who work closely with NSAI and Pinnacle to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI and Pinnacle +periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI and Pinnacle for our properties such as ownership interest, oil and gas production, well +test data, commodity prices and operating and development costs. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI and +Pinnacle, as well as management review and approval. +Our proved reserves to our Hackberry fields and other minority +interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our chief reserve engineer is a petroleum engineer with over 30 years of reservoir and operations experience and our geophysical staff +has over 60 years combined industry experience. Our technical staff uses historical information for our properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The +preparation of our proved reserve estimates are completed in accordance with our internal control procedures including management review and approval. +The following table sets forth our estimated proved reserves at December 31, 2009, 2008 and 2007: +Year Ended December 31, +2009 +2008 +2007 +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Proved developed +6,165 +4,325 +7,072 +7,187 +7,116 +6,746 +Proved undeveloped +11,323 +10,007 +14,699 +15,048 +17,999 +17,513 +Total (1) +17,488 +14,332 +21,771 +22,235 +25,115 +24,259 +Year Ended December 31, +2009 +2008 +2007 +Total net proved oil and natural gas reserves (Mboe) (1) +19,877 +25,477 +29,158 +PV-10 value (in millions) (2) +$ +263.0 +$ +126.2 +$ +821.2 +Standardized measure (in millions) (3) +$ +240.8 +$ +126.2 +$ +668.3 +(1) +Estimates of reserves as of year-end 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a +field-by-field basis on the first day of each month within the 12-month period ended December 31, 2009, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009. Estimates of reserves as of year-end 2008 +and 2007 were prepared using constant prices and costs in accordance with previous guidelines of the SEC based on hydrocarbon prices received on a field-by-field basis as of December 31st of the applicable year. Reserve estimates do not include any +value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual +future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. +26 +Table of Contents +Index to Financial Statements +(2) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net +revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our +reserve reports dated December 31, 2009 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December 2009, using $57.90 per barrel and 3.87 per MMBtu and adjusted by lease +for transportation fees and regional price differentials. The estimated future production in our reserve reports dated December 31, 2008 and 2007 is priced using constant year-end pricing of $41.00 per barrel and $5.71 per MMBtu and $92.50 per +barrel and $6.80 per MMBtu, respectively, and adjusted by lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional +analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We +have included a reconciliation of PV-10 to the most directly comparable GAAP measure—standardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value: +December 31, +2009 +2008 +2007 +Standardized measure of discounted future net cash flows +$ +240,774,000 +$ +126,240,000 +$ +668,295,000 +Add: Present value of future income tax discounted at 10% +22,237,000 +— +152,949,000 +PV-10 value +$ +263,011,000 +$ +126,240,000 +$ +821,244,000 +(3) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, +production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure +includes the effect of future income taxes. +The above table does not include proved reserves net to our +interest in Tatex of 2.739 Bcf of gas at December 31, 2008. For further discussion of our interest in Tatex, see Item 1. “Description of Business—Additional Properties.” +The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating +volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, +the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are +ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and +future production rates and costs. See “Risk Factors” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the +beginning of our last fiscal year. +Additional information regarding estimates of proved reserves, proved developed reserves +and proved undeveloped reserves, or PUDs, at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or +Supplemental Information , in Note 21 to our consolidated financial statements included in this report. Also contained in the Supplemental Information are our estimates of future net cash flows and discounted +27 +Table of Contents +Index to Financial Statements +future net cash flows from proved reserves. Additional information regarding our proved reserves can be found in “Management’s Discussion and Analysis of Financial Condition and Results +of Operations—Results of Operations” and “—Critical Accounting Policies and Estimates” included in this report. +Proved Undeveloped Reserves (PUDs) +As of December 31, 2009, our proved undeveloped reserves totaled +11,323 Mboe of oil and 10,007 MMcf of natural gas, for a total of 12,991 Mboe. Approximately 75% of our PUDs at year-end 2009 were located in the Permian Basin, 14% of our PUDs were located in WCBB and 11% were located in our East Hackberry field. +Each of these PUDs will be converted from undeveloped to developed as the well begins production. Changes in PUDs that occurred during 2009 were due to: +• +Conversion of approximately 402 Mboe attributable to PUDs into proved developed reserves; +• +Positive revisions of approximately 458 Mboe in PUDs due to changes in commodity prices; and +• +Exclusion of 7,375 Mboe attributable to 81 PUD locations that were not scheduled to be drilled within the next five years. +Costs incurred relating to the development of PUDs were approximately $6.4 million in 2009. Estimated +future development costs relating to the development of PUDs are projected to be approximately $47.8 million in 2010, $28 million in 2011, $38.7 million in 2012, $39.5 million in 2013 and $26.1 million in 2014. +All PUD drilling locations are scheduled to be drilled prior to the end of 2014. +As of December 31, 2009, 19.3% of our total proved reserves were classified as proved developed non-producing. +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2009 +2008 +2007 +Production Volumes: +Oil (MBbls) +1,531 +1,584 +1,501 +Gas (MMcf) +491 +712 +816 +Natural gas liquids (Gallons) +2,719 +2,583 +— +Oil equivalents (Mboe) +1,677 +1,764 +1,637 +Average Prices: +Oil (per Bbl) +$ +53.29 +(1) +$ +83.23 +(1) +$ +66.71 +(1) +Gas (per Mcf) +$ +4.06 +$ +9.23 +$ +7.40 +Natural gas liquids (per Gallon) +$ +0.73 +$ +1.26 +$ +— +Oil equivalents (per Boe) +$ +51.01 +$ +80.30 +$ +64.86 +Production Costs: +Average production costs (per Boe) +$ +9.73 +(2) +$ +12.96 +(2) +$ +10.18 +(2) +Average production taxes (per Boe) +$ +5.84 +$ +8.96 +$ +7.74 +Total production costs (per Boe) +$ +15.57 +$ +21.92 +$ +17.92 +(1) +Includes fixed contract prices at a weighted average price of: +June – December 2007 +$ +66.10 +January – December 2008 +$ +78.56 +January – December 2009 +$ +55.01 +28 +Table of Contents +Index to Financial Statements +Excluding the effect of the fixed price contracts, the average oil price for 2009 would have +been $57.98 per barrel and $55.29 per barrel of oil equivalent. The total volume hedged for 2009 represented approximately 49% of our total oil sales volumes for the year. Excluding the net effect of the fixed price contracts, the average oil price +for 2008 would have been $97.36 per barrel and $92.98 per barrel of oil equivalent. The total volume hedged for 2008 represented approximately 73% of our total oil sales for the year. Excluding the net effect of the fixed price contracts, the +average oil price for 2007 would have been $72.25 per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represented approximately 43% of our total oil sales volumes for the year. +(2) +Does not include production taxes. +Productive Wells and Acreage +The following table presents our total gross and net productive wells, expressed +separately for oil and gas, and the total gross and net developed acres as of December 31, 2009 +NRI/WI (1) +Productive +Oil Wells +(2) +Productive +Gas Wells +Non-Productive +Oil Wells +Non-Productive +Gas Wells +Developed +Acreage (3) +Undeveloped +Acreage +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +West Cote Blanche Bay Field (4) +80.1/100 +93 +93 +2 +2 +163 +163 +18 +18 +5,668 +5,668 +— +— +E. Hackberry Field (5) +79.4/100 +18 +18 +— +— +86 +86 +— +— +3,291 +3,291 +1,579 +1,579 +W. Hackberry Field +87.5/100 +3 +3 +— +— +24 +24 +— +— +592 +592 +— +— +Permian Basin +38.1/49.5 +64 +32 +— +— +— +— +— +— +8,157 +4,078 +8,190 +4,095 +Williston Basin (6) +3.1/4.1 +4 +1 +— +— +— +— +— +— +2,560 +127 +3,920 +779 +Overrides/Royalty Non-operated +Various +31 +1 +1 +0 +15 +1 +2 +1 +— +— +— +— +Total +213 +148 +3 +2 +288 +274 +20 +19 +20,268 +13,756 +13,689 +6,453 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes nine gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 68% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +29 +Table of Contents +Index to Financial Statements +Completed and Present Drilling and Recompletion Activities +The following table sets forth information with respect to wells completed during the periods indicated. The information should not be +considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce +commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +2009 +2008 +2007 +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +64 +62.5 +58 +56.5 +62 +62 +Dry +— +— +— +— +— +— +Total +64 +62.5 +58 +56.5 +62 +62 +Development: +Productive +25 +18 +69 +27 +23 +23 +Dry +1 +1 +— +— +3 +3 +Total +26 +19 +69 +27 +26 +26 +Exploratory: +Productive +1 +1 +— +— +9 +9 +Dry +— +— +1 +1 +3 +3 +Total +1 +1 +1 +1 +12 +12 +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the +time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with +industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management’s opinion, will in the aggregate materially restrict our +operations. +ITEM 3. +LEGAL PROCEEDINGS +The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR +maintains that we paid approximately $1.8 million less in severance taxes under fixed price terms than the severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any +liability to the LDR for underpayment of severance taxes and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. +We have maintained our right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against our company seeking $2,275,729 in severance taxes, +plus interest and court costs. We filed a response denying any liability to the LDR for underpayment of severance taxes and are defending our company in the lawsuit. The case is in the early stages of discovery. +In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us, Great White Pressure Control LLC, or Great White, and +six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and +several other causes of action relating to +30 +Table of Contents +Index to Financial Statements +Great White’s employment of the former Cudd employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was +dismissed without prejudice by order of the court on February 14, 2007. We filed a motion for summary judgment on October 5, 2007. The Court entered a final interlocutory judgment in favor of all defendants, including us, on April 8, +2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered summary +judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended +petition with the state court (a) alleging that we conspired with the other defendants to misappropriate, and misappropriated, Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking unspecified +monetary damages. On February 10, 2010, we filed a motion to be dismissed from the proceeding for lack of personal jurisdiction, which motion is pending. This state court proceeding is in its initial stages. +On July 27, 2007, Robotti & Company, LLC filed a putative class action lawsuit in the Court of Chancery for the State of +Delaware in and for Kent County, Delaware. The original complaint alleged a breach of fiduciary duty by us and our then present directors in connection with the pricing of our 2004 rights offering. Plaintiff filed an amended complaint on +January 15, 2008, and we filed a motion to dismiss in early February 2008 and filed the brief in support of such motion on April 29, 2008. The court held a hearing on October 3, 2008, ultimately deciding to allow the plaintiff to file +a second amended complaint. Plaintiff filed its second amended complaint December 22, 2008, which sets forth class action and derivative claim allegations that our then present directors breached their fiduciary duty in connection with the +pricing of the 2004 rights offering. The defendants filed their motion to dismiss on January 19, 2009 and their brief in support of such motion on February 20, 2009. Briefing by the parties concluded on April 6, 2009, oral arguments +on the motion were heard by the court on April 22, 2009 and on January 14, 2010, the court issued an opinion granting defendants’ motion to dismiss and entered an order dismissing the case with prejudice. +Due to the current stages of the LDR and Cudd litigation, the outcomes are uncertain and management cannot determine the amount of loss, if +any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse affect on our financial condition or results of operations. +In addition to the above, we have been named as a defendant in various other lawsuits related to our business. The ultimate resolution of +such other matters is not expected to have a material adverse effect on our financial condition or results of operations. +ITEM 4. +RESERVED +31 +Table of Contents +Index to Financial Statements +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market under the symbol “GPOR.” The +following table sets forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2008 +First Quarter +$ +19.41 +$ +10.16 +Second Quarter +17.67 +10.43 +Third Quarter +17.07 +9.00 +Fourth Quarter +10.03 +2.87 +2009 +First Quarter +$ +5.20 +$ +1.50 +Second Quarter +7.65 +2.23 +Third Quarter +8.99 +5.23 +Fourth Quarter +11.89 +7.25 +2010 +First Quarter (through February 26, 2010) +$ +12.68 +$ +8.89 +On February 26, +2010, the last reported sale price of our common stock on The NASDAQ Global Select Market was $9.80. +Unregistered Sales of Equity +Securities and Use of Proceeds +None. +Holders of Record +At the close of business on March 2, 2010, there +were 358 stockholders of record holding 42,697,402 shares of our outstanding common stock. There were approximately 7,397 beneficial owners of our common stock as of March 2, 2010. +Dividend Policy +We have never paid dividends on our common stock. We +currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends +to the holders of our common stock. +32 +Table of Contents +Index to Financial Statements +ITEM 6. +SELECTED FINANCIAL DATA +You should read the following selected consolidated financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the +related notes appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2009, December 31, 2008 and December 31, 2007 and the selected consolidated balance +sheet data at December 31, 2009 and December 31, 2008 are derived from our audited consolidated financial statements appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended +December 31, 2006 and December 31, 2005 and the selected consolidated balance sheet data at December 31, 2007, December 31, 2006 and December 31, 2005 are derived from our audited consolidated financial statements that +are not included in this report. The historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during any of the periods set forth in the following table. +Fiscal Year Ended December 31, +2009 +2008 +2007 +2006 +2005 +Selected Consolidated Statements of Operations Data: +Revenues +$ +85,262,000 +$ +141,217,000 +$ +105,838,000 +$ +60,390,000 +$ +27,559,000 +Costs and expenses: +Lease operating expenses +16,316,000 +22,856,000 +16,670,000 +10,670,000 +7,654,000 +Production taxes +9,797,000 +15,813,000 +12,667,000 +7,366,000 +3,622,000 +Depreciation, depletion and amortization +29,225,000 +42,472,000 +29,681,000 +12,652,000 +4,789,000 +Impairment of oil and natural gas properties +— +272,722,000 +— +— +— +General and administrative +4,992,000 +6,843,000 +5,802,000 +3,251,000 +1,561,000 +Accretion expense +582,000 +560,000 +554,000 +596,000 +516,000 +60,912,000 +361,266,000 +65,374,000 +34,535,000 +18,142,000 +Income (Loss) from Operations +24,350,000 +(220,049,000 +) +40,464,000 +25,855,000 +9,417,000 +Other (Income) Expense: +Interest expense +2,309,000 +4,762,000 +3,091,000 +1,956,000 +250,000 +Interest expense—preferred stock +— +— +— +— +272,000 +Insurance recoveries +(1,050,000 +) +(769,000 +) +— +(3,601,000 +) +(1,710,000 +) +Settlement of fixed price contracts +— +(39,000,000 +) +— +— +— +Interest income +(564,000 +) +(540,000 +) +(523,000 +) +(308,000 +) +(290,000 +) +695,000 +(35,547,000 +) +2,568,000 +(1,953,000 +) +(1,478,000 +) +Income (Loss) before Income Taxes +23,655,000 +(184,502,000 +) +37,896,000 +27,808,000 +10,895,000 +Income Tax Expense +28,000 +— +121,000 +— +— +Net Income (Loss) +23,627,000 +(184,502,000 +) +37,775,000 +27,808,000 +10,895,000 +Net Income (Loss) Available to Common Stockholders +$ +23,627,000 +$ +(184,502,000 +) +$ +37,775,000 +$ +27,808,000 +$ +10,895,000 +Net Income (Loss) Per Common Share—Basic: +$ +0.55 +$ +(4.33 +) +$ +1.03 +$ +0.85 +$ +0.36 +Net Income (Loss) Per Common Share—Diluted: +$ +0.55 +$ +(4.33 +) +$ +1.01 +$ +0.82 +$ +0.34 +33 +Table of Contents +Index to Financial Statements +At December 31, +2009 +2008 +2007 +2006 +2005 +Selected Consolidated Balance Sheet Data: +Total assets +$ +227,344,000 +$ +221,873,000 +$ +419,137,000 +$ +195,151,000 +$ +111,820,000 +Total debt, including current maturity +$ +52,428,000 +$ +70,731,000 +$ +66,533,000 +$ +37,691,000 +$ +10,200,000 +Total liabilities +$ +102,293,000 +$ +107,772,000 +$ +115,015,000 +$ +71,342,000 +$ +27,493,000 +Stockholders’ equity +$ +125,051,000 +$ +114,101,000 +$ +304,122,000 +$ +123,809,000 +$ +84,327,000 +34 +Table of Contents +Index to Financial Statements +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included +elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or +financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and +“Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. +Overview +We are an independent oil and natural gas exploration and production company with our principal producing properties located +along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil +Sands ULC, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +2009 Developments +• +Oil and natural gas revenues decreased 40% to $85.6 million for the year ended December 31, 2009 from $141.7 million for 2008. +• +Net income increased to $23.6 million for the year ended December 31, 2009 from a loss of $184.5 million for the year ended December 31, +2008. +• +Production decreased 5% to 1,677,474 BOE for the year ended December 31, 2009 from 1,764,053 BOE for 2008. +• +During 2009, we drilled 27 wells and recompleted 64 wells. Of our 27 new wells drilled, 22 were completed as producing wells, one was non-productive +and four are waiting on completion. +• +We sold approximately 18,000 net acres in the Bakken for $18.8 million. +Critical Accounting Policies and Estimates +Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles +generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We +have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates +including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our +consolidated financial statements: +Oil and Natural Gas Properties . We use the full cost method of accounting for oil +and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net +capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, +including the estimated future development costs and site remediation costs, +35 +Table of Contents +Index to Financial Statements +if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of +oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of +undeveloped leaseholds and totaled $17.5 million at December 31, 2009 and $22.5 million at December 31, 2008. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and +natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available +funds for exploration and development. +Ceiling Test . Companies that use the full cost method of accounting for oil and +gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income +taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month +price for the period January – December 2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the +estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included +in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or +noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. +For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272,722,000 for the year ended December 31, 2008. If prices of oil, +natural gas and natural gas liquids continue to decrease, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. No ceiling test impairment was required for the year +ended December 31, 2009. +Asset Retirement Obligations . We have obligations to remove equipment and restore land +at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. +We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of +the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially +recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the +related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation +requirements. +The fair value of the liability associated with these retirement obligations is determined using significant +assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment +risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount +of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural +gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates. +36 +Table of Contents +Index to Financial Statements +Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the +quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, +Sewell & Associates, Inc., Pinnacle Energy Services, LLC and to a lesser extent our personnel have prepared reserve reports of our reserve estimates on a well-by-well basis for our properties. +Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to +depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with SEC guidelines. The accuracy of our +reserve estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, +reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. +Income +Taxes . We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement +carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those +temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the +year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A +valuation allowance for our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2009, a valuation allowance of $73.2 million had been provided +for deferred tax assets based on the uncertainty of future taxable income. +Revenue Recognition . We derive almost all +of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three +months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are +recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. +Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred +and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent +payment of legal liabilities. +Derivative Instruments and Hedging Activities . We seek to reduce our exposure to +unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, “ Derivatives and Hedging ,” as amended. It requires that all derivative instruments be +recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments +37 +Table of Contents +Index to Financial Statements +using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and +credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. +Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in +accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We +recognize any change in fair value resulting from ineffectiveness immediately in earnings. +To mitigate the effects of +commodity price fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000 barrels of WCBB production at a weighted average price of $55.01 per barrel before transportation costs. We delivered approximately 49% of +our 2009 production under these agreements. Initially, for the period January through December 2009, we had entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before +transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a +weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average +daily price of $54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and May 2009 for an aggregate of approximately $2.0 million. For +the period January 2010 through February 2010 we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March +2010 through December 2010, we have entered into forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before transportation costs. Under these contracts, we have +committed to deliver approximately 45% of our estimated 2010 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In +addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contacts are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and +Hedging, ” and related pronouncements. +38 +Table of Contents +Index to Financial Statements +RESULTS OF OPERATIONS +Results of Operations +The markets for oil and natural gas have +historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2009 +2008 +2007 +Production Volumes: +Oil (MBbls) +1,531 +1,584 +1,501 +Gas (MMcf) +491 +712 +816 +Natural gas liquids (Gallons) +2,719 +2,583 +— +Oil equivalents (Mboe) +1,677 +1,764 +1,637 +Average Prices: +Oil (per Bbl) +$ +53.29 +(1) +$ +83.23 +(1) +$ +66.71 +(1) +Gas (per Mcf) +$ +4.06 +$ +9.23 +$ +7.40 +Natural gas liquids (per Gallon) +$ +0.73 +$ +1.26 +$ +— +Oil equivalents (per Boe) +$ +51.01 +$ +80.30 +$ +64.86 +Production Costs: +Average production costs (per Boe) +$ +9.73 +(2) +$ +12.96 +(2) +$ +10.18 +(2) +Average production taxes (per Boe) +$ +5.84 +$ +8.96 +$ +7.74 +Total production costs (per Boe) +$ +15.57 +$ +21.92 +$ +17.92 +(1) +Includes fixed contract prices at a weighted average price of: +June – December 2007 +$ +66.10 +January – December 2008 +$ +78.56 +January – December 2009 +$ +55.01 +Excluding the effect +of the fixed price contracts, the average oil price for 2009 would have been $57.98 per barrel and $55.29 per barrel of oil equivalent. The total volume hedged for 2009 represented approximately 49% of our total oil sales volumes for the year. +Excluding the net effect of the fixed price contracts, the average oil price for 2008 would have been $97.36 per barrel and $92.98 per barrel of oil equivalent. The total volume hedged for 2008 represented approximately 73% of our total oil sales +for the year. Excluding the net effect of the fixed price contracts, the average oil price for 2007 would have been $72.25 per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represented approximately 43% of our +total oil sales volumes for the year. +(2) +Does not include production taxes. +From 2008 to 2009, our net equivalent oil production decreased 5% from 1,764,000 barrels to 1,677,000 barrels due to our reduced drilling activity and normal production declines. From 2007 to 2008, our net oil equivalent production +increased 8% from 1,637,000 barrels to 1,764,000 barrels due primarily to continued drilling and recompletion activities. We currently estimate that our 2010 production will be between 1,850,000 and 2,050,000 BOE. However, such estimate may change +based on the changing economic climate and unforeseen events, such as hurricanes. +39 +Table of Contents +Index to Financial Statements +Comparison of the Years Ended December 31, 2009 and December 31, 2008 +We reported net income of $23,627,000 for the year ended December 31, 2009, as compared to a net loss of $184,502,000 for the year ended +December 31, 2008. This net income is primarily attributable to a 29% decrease in lease operating expenses, a 27% decrease in general and administrative expenses and a 38% decrease in production taxes, partially offset by a 36% decrease in +realized BOE prices to $51.01 from $80.30 and a 5% decrease in net production to 1,677,474 BOE. In addition, the net loss for 2008 was primarily attributable to an impairment charge of $272,722,000 related to the drastic decline in oil and gas +prices. Further, we had $1,050,000 of insurance proceeds received during the year ended December 31, 2009 compared to insurance proceeds of $769,000 received during 2008. +Oil and Gas Revenues . For the year ended December 31, 2009, we reported oil and natural gas revenues of $85,576,000 as compared +to oil and natural gas revenues of $141,650,000 during 2008. This $56,074,000, or 40%, decrease in revenues is primarily attributable to a 36% decrease in realized BOE prices to $51.01 from $80.30 and a 5% decrease in net production to 1,677,474 BOE +for the year ended December 31, 2009 from 1,764,053 BOE for the year ended December 31, 2008. +The following table +summarizes our oil and natural gas production and related pricing for the years ended December 31, 2009 and December 31, 2008: +Year Ended +December 31, +2009 +2008 +Oil production volumes (MBbls) +1,531 +1,584 +Gas production volumes (MMcf) +491 +712 +Natural gas liquids production volumes (Gallons) +2,719 +2,583 +Oil equivalents (Mboe) +1,677 +1,764 +Average oil price (per Bbl) +$ +53.29 +$ +83.23 +Average gas price (per Mcf) +$ +4.06 +$ +9.23 +Average natural gas liquids (per gallon) +$ +0.73 +$ +1.26 +Oil equivalents (per Boe) +$ +51.01 +$ +80.30 +Lease Operating +Expenses . Lease operating expenses not including production taxes decreased to $16,316,000 for 2009 from $22,856,000 for 2008. This decrease is mainly a result of a decrease in contract labor expenses, a decrease in workovers, compressor and +other equipment rentals and repairs, a decrease in the cost of chemicals and supplies and a decrease in personal property taxes. In addition, the lease operating expenses for 2008 included $3,408,000 of unreimbursed expenses related to hurricane +repairs as compared to approximately $23,000 of unreimbursed expenses related to hurricane repairs in 2009. +Production +Taxes . Production taxes decreased to $9,797,000 for 2009 from $15,813,000 for 2008. This decrease was primarily related to a 40% decrease in oil and gas revenues mainly as a result of the decrease in the average realized BOE price received. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense decreased to $29,225,000 +for 2009, and consisted of $28,939,000 in depletion on oil and natural gas properties and $286,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $42,472,000 for 2008. This +decrease was due primarily to the reduction in the book value of our oil and gas properties used to calculate depreciation, depletion and amortization expense. This reduction resulted from the drop in commodity prices reflected as of +December 31, 2008 and the resulting reduction in our proved reserves which caused us to recognize a ceiling test impairment to our full cost pool of $272,722,000 for the year ended December 31, 2008. +Impairment of Oil and Gas Properties. We use the full cost method of accounting for oil and gas properties and are required to +perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value +40 +Table of Contents +Index to Financial Statements +of our oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as +the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period of January through December 2009, and prior to +2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement +obligations recorded on our balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to +differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash write-down is required. There was no +impairment charge for the year ended December 31, 2009. As a result of the drop in commodity prices on December 31, 2008, we recognized a ceiling test impairment of $272,722,000 for the year ended December 31, 2008. +General and Administrative Expenses . Net general and administrative expenses decreased to $4,992,000 for 2009 from $6,843,000 for +2008. This $1,851,000 decrease was due primarily to reductions in franchise taxes as a result of the impairment mentioned in the depreciation, depletion and amortization section above which reduced our net assets used to calculate franchise taxes, a +reduction in stock based compensation expenses, reductions in payroll costs including payroll taxes and related benefits mainly due to decreases in the total number of employees partially offset by a decrease in general and administrative +reimbursements from our affiliates and a decrease in general and administrative overhead related to exploration and development activity capitalized to the full cost pool. +Accretion Expense . Accretion expense increased slightly to $582,000 for 2009 from $560,000 for 2008. +Interest Expense . Interest expense decreased to $2,309,000 for 2009 from $4,762,000 for 2008 due to a decrease in average debt +outstanding and lower interest rates on amounts borrowed under our facilities with Bank of America. Total debt outstanding under our facilities with Bank of America was $49.9 million as of December 31, 2009 and $68.1 million as of the same date +in 2008. Total weighted debt outstanding under our facilities with Bank of America was $59.9 million for 2009 and $84.2 million for 2008. As of December 31, 2009, amounts borrowed under our revolving credit facility and our two term loans with +Bank of America bore interest of 3.73%, 4.23% and 3.25%, respectively. +Income Taxes . As of December 31, 2009, we +had a net operating loss carry forward of approximately $55.7 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it +is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some +portion will not be realized. At December 31, 2009, a valuation allowance of $73.2 million had been provided for deferred tax assets, as the Company has historically had non-taxable income and has future projections of no taxable income during +the carryforward period, with the exception of $533,000 related to alternative minimum taxes. We had $28,000 of state income tax expense for the year ended December 31, 2009. +Comparison of the Years Ended December 31, 2008 and December 31, 2007 +We reported a net loss of $184,502,000 for the year ended December 31, 2008, compared to net income of $37,775,000 for the year ended December 31, 2007. This net loss was primarily attributable to an impairment charge of +$272,722,000 related to the drastic decline in oil and gas prices, partially offset by a $39.0 million gain from the sale in December 2008 of all of our then existing 2009 fixed price contracts. Excluding the effect of the impairment, our net income +increased 133% due primarily to (1) a 8% increase in net production to 1,764,053 BOE for the year ended December 31, 2008 from 1,636,902 BOE for 2007, (2) a 25% increase in the average oil price received to $83.23 per barrel for the +year ended December 31, 2008 from $66.71 per barrel for 2007 and (3) a $39.0 million gain from the sale in December 2008 of all of our then existing fixed price contracts. +41 +Table of Contents +Index to Financial Statements +Oil and Gas Revenues . For the year ended December 31, 2008, we reported oil and +gas revenues of $141,650,000, compared to oil and gas revenues of $106,163,000 during 2007. This 33% increase in revenues is mainly attributable to an 8% increase in net production to 1,764,053 BOE for the year ended December 31, 2008 from +1,636,902 BOE for 2007 and a 25% increase in the average oil price received to $83.23 per barrel for the year ended December 31, 2008 from $66.71 per barrel for 2007. This increase in oil and natural gas production was the result of production +from our 2008 drilling programs and the acquisition of the Permian wells in December 2007. Production in 2008 was adversely affected by the damage caused by Hurricane Ike with production not fully restored until December, 2008. We estimate that +approximately 170,000 barrels of oil equivalents production were deferred to other periods. +The following table summarizes +our oil and natural gas production and related pricing for the years ended December 31, 2008 and December 31, 2007: +Year Ended +December 31, +2008 +2007 +Oil production volumes (MBbls) +1,584 +1,501 +Gas production volumes (MMcf) +712 +816 +Natural gas liquids production volumes (Gallons) +2,583 +— +Oil equivalents (Mboe) +1,764 +1,637 +Average oil price (per Bbl) +$ +83.23 +$ +66.71 +Average gas price (per Mcf) +$ +9.23 +$ +7.40 +Average natural gas liquids (per gallon) +$ +1.26 +$ +— +Oil equivalents (per Boe) +$ +80.30 +$ +64.86 +Lease Operating +Expenses . Lease operating expenses, or LOE, excluding the effects of hurricane related costs and production taxes, increased to $19,448,000 for 2008 from $16,670,000 for 2007. The increase in ongoing LOE was mainly due to $2,700,000 of LOE +related to the Permian properties acquired in December 2007. In addition, there were also increases in personal property taxes and repairs to compressors and other equipment in our operating area along the Louisiana Gulf Coast. Included in total LOE +of $22,856,000 before production taxes is $3,408,000 of hurricane related LOE costs incurred during 2008. +Production +Taxes . Production taxes increased to $15,813,000 for 2008 from $12,667,000 for 2007. This increase was directly related to a 33% increase in oil and gas revenues as a result of the 24% improvement in the price received per barrel of oil +equivalent and an 8% increase in production for 2008 as compared to 2007. +Depreciation, Depletion and Amortization . +Depreciation, depletion and amortization expense increased to $42,472,000 for the year ended December 31, 2008, and consisted of $42,194,000 in depletion on oil and natural gas properties and $278,000 in depreciation of other property and +equipment. This compares to total depreciation, depletion and amortization expense of $29,681,000 for the year ended December 31, 2007, which consisted of $29,220,000 in depreciation on oil and natural gas properties and $461,000 in +depreciation of other property and equipment. This increase was due primarily to an increase in our oil and natural gas property costs associated with our 2008 drilling program, an increase in our oil and gas production for the period and a decrease +in our total oil and gas reserve volumes. +Impairment of Oil and Gas Properties. We use the full cost method of +accounting for oil and gas properties and are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of our oil and gas properties. Net capitalized costs are limited to the lower of unamortized +cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and +costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on our balance sheet, +(b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of +42 +Table of Contents +Index to Financial Statements +unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book +value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash write-down is required. As a result of the drop in commodity prices on December 31, 2008, we recognized a ceiling test impairment of +$272,722,000 for the year ended December 31, 2008. This impairment however will reduce future depletion expense. There was no impairment charge for the year ended December 31, 2007. +General and Administrative Expenses . Net general and administrative expenses increased to $6,843,000 for 2008 from $5,802,000 for +2007. This $1,041,000 increase was due primarily to an $832,000 increase in franchise taxes as a result of an increase in total assets and shares outstanding and slight increases in audit fees and insurance costs. +Accretion Expense . Accretion expense increased slightly to $560,000 for 2008 from $554,000 for 2007, due to a larger obligation at +the beginning of 2008 compared to the beginning of 2007, resulting from the addition of future abandonment obligations on new wells drilled during 2007. +Interest Expense . Interest expense increased to $4,762,000 for 2008 from $3,091,000 for 2007 due to an increase in average debt outstanding. Total weighted debt outstanding under our facilities +with Bank of America was $84.2 million for 2008 as compared to $33.2 million for 2007. +Settlement of Fixed Price +Contracts. In December 2008, we terminated all of our then existing 2009 fixed price contracts. Through the termination of these contracts, we received a $39.0 million payment during the fourth quarter of 2008, and in accordance with FASB ASC +815, these amounts were recognized into earnings during the fourth quarter of 2008, the period in which the fixed price contracts were settled. There was not a termination of any fixed price contracts during the year ended December 31, 2007. +Income Taxes . As of December 31, 2008, we had a net operating loss carry forward of approximately $60 million, in +addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our future taxable income to determine whether it is more likely than not that a valuation allowance is needed, +looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2008, a +valuation allowance of $81.9 million had been provided for our entire net deferred tax asset, with the exception of $653,000 related to alternative minimum taxes. +Liquidity and Capital Resources +Overview . Historically, our primary +sources of funds have been cash flow from our producing oil and natural gas properties, the issuance of equity securities and borrowings under our bank and other credit facilities. Our ability to access any of these sources of funds can be +significantly impacted by decreases in oil and natural gas prices or oil and gas production. In addition, during 2009, we also received proceeds from the sale of Bakken assets. +Net cash flow provided by operating activities was $53,299,000 for 2009, as compared to $135,323,000 for 2008. This decrease was primarily +the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 36% decrease in net realized prices and a 5% decrease in our net BOE production. +Net cash flow provided by operating activities was $135,323,000 for 2008, as compared to net cash flow provided by operating activities of +$68,902,000 for 2007. The increase of $66,421,000 in 2008 was primarily the result of the termination in December 2008 of our then existing 2009 fixed price contracts for $39,000,000, an increase in cash receipts from our oil and gas purchasers due +to higher prices received for oil production and an 8% increase in net production, partially offset by increase in cash paid for lease operating expenses and production taxes. +43 +Table of Contents +Index to Financial Statements +Net cash used in investing activities for 2009 was $39,246,000, as compared to $136,823,000 +for 2008. During the year ended December 31, 2009, we spent (a) $49,533,000 in additions to oil and natural gas properties, of which $20,296,000 was spent on our 2009 drilling and recompletion programs, $14,255,000 was spent on costs +attributable to the wells drilled during 2008, $3,719,000 was spent on our 2008 recompletions, $1,191,000 was spent on barges and other facility enhancements, $866,000 was spent on plugging and abandonment activities, $2,853,000 was spent on lease +related costs and $1,744,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses, and (b) $3,813,000 on our investment in Tatex III and we loaned $4,377,000 to Grizzly. In May, +September and December 2009, we received aggregate net proceeds of approximately $18,286,000 from our sale of properties in the Bakken. During the year ended December 31, 2009, we used cash from operations and proceeds from the sale of Bakken +properties to fund our investing activities. +Net cash used in investing activities for 2008 was $136,823,000, as compared to +$240,733,000 for 2007. During the year ended December 31, 2008, we spent $126,030,000 in additions to oil and natural gas properties, of which $77,074,000 was spent on our 2008 drilling and recompletion program, $27,131,000 was attributable to +the wells drilled or recompleted during 2007, $4,665,000 was spent on compressors, $3,200,000 was spent on facilities, $1,148,000 was spent on plugging activities, $1,933,000 was spent on lease related costs primarily in the Bakken, $1,128,000 was +spent on our Belize activities, $841,000 was spent on a new storage barge with the remainder attributable mainly to capitalized general and administrative expenses. In addition, during the year ended December 31, 2008, we received cash +distributions of $862,000 from Tatex Thailand II and we made cash investments of $885,000 in Tatex Thailand III and $10,670,000 in Grizzly. We used cash from operations and borrowings under our credit facility to fund our investing activities in +2008. +Net cash used by financing activities for 2009 was $18,273,000, which amount is primarily attributable to principal +payments of $18,206,000 under our credit agreement with Bank of America. +Net cash provided by financing activities for 2008 +was $4,680,000, as compared to $167,968,000 for 2007. The 2008 amount is primarily attributable to $30,000,000 of borrowings under our line of credit, mostly offset by repayments on the line. The 2007 amount provided by financing activities is +primarily attributable to borrowings of $76,000,000 under our credit facility with Bank of America and aggregate proceeds of approximately $138,258,000 from the sale of shares of our common stock in February 2007, May 2007, July 2007 and +December 2007, after deducting the underwriting discount and offering expenses, and $868,000 from the exercise of stock options. Net proceeds were used to pay down $46,328,000 of outstanding existing debt under our credit facility with Bank of +America, fund substantially all of the purchase price for the acquisition of our interest in certain strategic assets in Upton County, Texas in the Permian Basin and for other general corporate purposes. +Credit Facility . In March 2005, we entered into a three-year secured revolving credit agreement, as amended, with Bank of America, +N.A. providing for a revolving credit facility. Borrowings under the credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million subject to adjustment. On November 1, 2005, the amount available under the +borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount available under the borrowing base limitation was increased to $30.0 million. Effective +July 19, 2007, the credit facility increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0 million. In connection with our acquisition of strategic assets in West Texas in the Permian +Basin, effective as of December 20, 2007, our borrowing base under the revolving credit facility increased from $60.0 million to $90.0. In addition, the maturity date was extended from March 31, 2009 to March 31, 2010. On +August 31, 2009, the lender completed its periodic redetermination of our borrowing base giving consideration to our year-end 2008 and mid-year 2009 reserve information and then current bank pricing decks, among other factors. As a result of +this redetermination, our available borrowing base was reset at $45.0 million, primarily in response to significant declines in commodity prices. Our outstanding principal balance at the effective time of this redetermination was approximately $59.0 +million. Amounts borrowed under the credit facility bear interest at the Eurodollar rate plus 3.50% (3.73% at December 31, 2009). The approximately $14.0 million of outstanding borrowings under our +44 +Table of Contents +Index to Financial Statements +credit facility in excess of the new borrowing base was converted into a term loan as of August 31, 2009. An initial $2.0 million payment was made on the term loan at that time and we agreed +to make additional monthly payments of $1.0 million commencing on September 30, 2009, with all unpaid amounts due on March 31, 2010. +Outstanding borrowings under the term loan accrue interest at the Eurodollar Rate (as defined in the credit agreement) plus 4% (4.23% at December 31, 2009) or, at our option, at the base rate (which +is the highest of the lender’s prime rate, the Federal funds rate plus 1/2 of 1%, and the one-month Eurodollar Rate plus 1%) plus 3%. Effective August 31, 2009, we also agreed to adjustments in the commitment fees, interest rates for +revolving loans and fees for letters of credit under our credit facility. Specifically, we agreed to pay (a) commitment fees ranging from 0.5% to 0.625% (an increase from 0.15% to 0.25%), (b) margin interest rates ranging from 2.75% to +3.50% for Eurodollar loans (an increase from 1.25% to 2.0%), (c) margin interest rates ranging from 1.75% to 2.5% for base rate loans (an increase from 1.25% to 2.0%), and (d) letter of credit fees at the margin interest rates for +Eurodollar loans, in each case based on our utilization percentage. In addition, we agreed to limitations on certain dispositions and investments by us, and to mandatory prepayments of the loans from the net cash proceeds of specified asset sales +and other events. +Effective December 31, 2009, we entered into the amended and restated credit agreement with Bank of +America, N.A., as administrative agent, and the other lenders from time to time party thereto. The restated credit agreement amended and restated our original 2005 credit agreement primarily to reflect the subsequent amendments thereto and to extend +the maturity date of the revolving loan under our original 2005 credit agreement with Bank of America, N.A. from March 31, 2010 to April 1, 2011. The restated credit agreement did not alter the March 31, 2010 maturity date of the term +loan outstanding under the original 2005 credit agreement. Our obligations under the restated credit agreement are guaranteed by our subsidiaries. +The restated credit agreement contains certain affirmative and negative covenants, including, but not limited to the following financial covenants: (a) the ratio of funded debt to EBITDAX (net income +before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest expense, plus exploration costs deducted in determining net income under +full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with all covenants at +December 31, 2009. As we have historically, we continue to make all interest payments on time. +As of December 31, +2009, approximately $45.0 million was outstanding under the revolving credit facility and $2.0 million was outstanding under the term loan, which are included in long-term debt, net of current maturities and current maturities of long-term debt, +respectively, on the accompanying consolidated balance sheet. As of March 1, 2010, approximately $45.0 million was outstanding under the revolving credit facility and the term loan had been paid in full. We have used the proceeds of our +borrowings under the credit facility for the development of our oil and natural gas properties and other capital expenditures, acquisition opportunities and for other general corporate purposes. +On July 10, 2006, we entered into a $5.0 million term loan agreement with Bank of America, N.A. related to the purchase of new gas +compressor units. The loan began amortizing quarterly on March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. Amounts borrowed bear interest at Bank of America prime +(3.25% at December 31, 2009). We make quarterly interest payments on amounts borrowed under the agreement. Our obligations under the agreement are collateralized by a lien on the compressor units. As of December 31, 2009, approximately +$2.9 million was outstanding under this agreement, of which $714,000 and $2.2 million are included in current maturities of long-term debt and long-term debt, net of current maturities, respectively, on our accompanying consolidated balance sheet. +Building Loans . We had three loans associated with two of our buildings. One loan, in the original principal amount of +$115,000, related to a building in Lafayette, Louisiana, that we purchased in 1996 to be used as our Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. We repaid this loan in full during +45 +Table of Contents +Index to Financial Statements +the third quarter of 2007. In addition, in June 2004 we purchased the office building we occupy in Oklahoma City, Oklahoma for $3.7 million. One of the two loans associated with this building, +with an original principal amount of $389,000, matured in March 2006 and bore interest at a rate of 6% per annum. The other loan associated with this building, with an original principal amount of $3.0 million, matures in June 2011 and bears +interest at a rate of 6.5% per annum. As of December 31, 2009, approximately $2.5 million was outstanding on this loan. The remaining building loan requires monthly interest and principal payments and is collateralized by the respective +land and buildings. +Capital Expenditures . Our recent capital commitments have been primarily for the development of +our proved reserves, to increase our net acreage position in Grizzly and fund Grizzly’s delineation drilling program and for acquisitions, primarily our acquisitions in the Permian Basin. Our strategy, subject to economic and industry +conditions, is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, and +(2) explore acquisition and disposition opportunities. We have upgraded our infrastructure and our existing facilities in Southern Louisiana with the goal of increasing operating efficiencies and volume capacities and lowering lease operating +expenses. These upgrades were also intended to better enable our facilities to withstand future hurricanes with less damage. Additionally, we completed the reprocessing of 3-D seismic data in one of our principal properties, WCBB. The reprocessed +data enables our geophysicists to continue to generate new prospects and enhance existing prospects in the intermediate zones in the field, thus creating a portfolio of new drilling opportunities. In addition, with our acquisition of strategic +assets in the Permian Basin in West Texas, we are required to pay 50% of all drilling costs for drilling activity on such properties. To combat significant declines in the commodity prices during the second half of 2008, management undertook a +series of actions aimed at reducing capital spending and operating costs. As a result, we reduced our drilling and other capital activities to a minimum in the fourth quarter of 2008, releasing all rigs in Southern Louisiana and the Permian and only +selectively participating in wells in the Bakken. During 2009, we were not bound by lease obligations and long term capital commitments relating to the exploration or development of our oil and gas properties. As a result of the then current +economic conditions, we initially reduced our estimated capital activities and aggressively sought price concessions from our service providers until such time costs were reduced to more appropriate levels. Currently, our AFE costs have been reduced +by 35% to 40% since 2008. As a result of the improvements in commodity prices and reductions in costs, we currently intend to expand our 2010 drilling activities. +In our December 31, 2009 reserve reports, 65% of our net reserves were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent +that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement +activities or use third parties to accomplish those activities. +Our inventory of prospects includes approximately 21 proved +undeveloped drilling locations at WCBB. The drilling schedule used in our December 31, 2009 reserve report anticipates that all of those wells will be drilled by 2012. From January 1, 2010 through March 1, 2010, we recompleted eight +existing wells at our WCBB field. We currently intend to spend a total of approximately $33.0 to $36.0 million to drill 20 wells and recomplete 40 wells in our WCBB field during 2010. +In our East Hackberry field, we intend to drill three land wells during 2010. Total capital expenditures for our East Hackberry field during +2010 are estimated at $6.0 to $7.0 million. +From January 1, 2010 through March 1, 2010, two gross wells were +drilled in our Permian acreage. We currently anticipate that our capital requirements for our properties in the Permian Basin in West Texas will be approximately $15.0 to $17.0 million during 2010. We have identified 191 gross proved undeveloped +(95.5 net) future development drilling locations. We currently expect that approximately 12 to 13 net wells will be drilled on this acreage in 2010. +46 +Table of Contents +Index to Financial Statements +During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of +December 31, 2009, our net investment in Grizzly was approximately $41.0 million, including a note receivable of $15.9 million. Capital requirements in 2010 for this project are estimated to be approximately $5.0 million, +primarily for the expenses associated with initial preparations of the Algar Lake facility. +Capital expenditures in 2010 +relating to our interest in Thailand are expected to be approximately $750,000, which we believe will be mostly offset from our share of production from the Phu Horm field. +Due to our sale transactions in 2009, we expect no capital expenditures in 2010 relating to our interest in the Bakken Shale in the +Williston Basin. +Our total capital expenditures for 2010 are currently estimated to be $56.0 to $62.0 million. This is +an increase from the $45.2 million spent in 2009 as we intend to expand our activities as a result of the improved commodity pricing and reduced cost environment. In addition, through our cost reduction initiative, AFE costs have been reduced +by 35% to 40% from the costs quoted in 2008. We intend to monitor pricing and cost developments during 2010 and make adjustments to our capital expenditure program as warranted. +We believe that our cash on hand, cash flow from operations and availability under our credit facility, if any, will be sufficient to meet +our normal recurring operating needs, debt service obligations, and our WCBB, Hackberry, Permian Basin and Grizzly capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling programs, pursue +acquisitions or accelerate our Canadian oil sands project, we may be required to obtain additional funds which we may do so through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. Needed +capital may not be available to us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions +that may be favorable to us. +Commodity Price Risk +The volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate posted price for crude +oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.73 per million British thermal units, or MMBtu, in +September 2009 to a high of $15.52 per MMBtu in December 2005. On December 31, 2009, the West Texas Intermediate posted price for crude oil was $79.39 per bbl and the Henry Hub spot market price of natural gas was $5.83 per MMBtu. Any +substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write +downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price +fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000 barrels of WCBB production at a weighted average price of $55.01 per barrel before transportation costs. We delivered approximately 49% of our 2009 +production under these agreements. Initially, for the period January through December 2009, we had entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation +costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average +daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of +$54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and May 2009 +47 +Table of Contents +Index to Financial Statements +for an aggregate of approximately $2.0 million. For the period January 2010 through February 2010 we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day +at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted +average daily price of $58.24 per barrel, before transportation costs. Under these contracts, we have committed to deliver approximately 45% of our estimated 2010 production. Such arrangements may expose us to risk of financial loss in certain +circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +Commitments +In connection +with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the +obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in March +2009, we became entitled to access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2009, the plugging and abandonment trust totaled approximately $3,136,000. At December 31, 2009, we +had plugged 273 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. +Contractual and Commercial Obligations +Payment due by period (1) +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +Short-term and long-term debt +$ +52,428,000 +$ +2,842,000 +$ +49,586,000 +$ +— +$ +— +Asset retirement obligations +10,153,000 +635,000 +1,668,000 +815,000 +7,035,000 +Total +$ +62,581,000 +$ +3,477,000 +$ +51,254,000 +$ +815,000 +$ +7,035,000 +(1) +Does not include estimated interest of $1,921,000 less than one year, $5,220,000 1-3 years, and $3,348,000 3-5 years and short-term derivative instruments of +$18,735,000 less than one year. +New Accounting Pronouncements +In June 2009, the FASB issued the FASB Accounting Standards Codification, or ASC, and the Hierarchy of Generally Accepted Accounting +Principles, which we refer to as the Codification. The Codification became the single official source of authoritative, nongovernmental U.S. generally accepted accounting principles, or GAAP. The Codification did not change GAAP but reorganizes the +literature. The Codification is effective for interim and annual periods ending after September 15, 2009. There was no impact to our consolidated financial statements as a result of the Codification. +Effective January 1, 2008, we implemented FASB ASC Topic 820, “Fair Value Measurements and Disclosures,” or FASB ASC 820, +which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We elected to implement this statement with the permitted one-year deferral for nonfinancial assets and nonfinancial +liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis. The deferral applied to nonfinancial assets and liabilities measured at fair value in a business combination, impaired properties, plants and +equipment, intangible assets and goodwill, and initial recognition of asset retirement obligations and restructuring costs for which fair value is used. The adoption of the provisions of FASB ASC 820 did not have a material impact on our +consolidated financial statements. +48 +Table of Contents +Index to Financial Statements +In December 2007, the FASB issued FASB ASC Topic 805, “Business Combinations,” or +FASB ASC 805. FASB ASC 805 establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and +the goodwill acquired. FASB ASC 805 also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. FASB ASC 805 is effective for acquisitions that occur in an entity’s +fiscal year that begins after December 15, 2008. The adoption did not have an immediate impact on our consolidated financial statements. +In December 2007, the FASB issued FASB ASC Topic 810, “Consolidation,” or FASB ASC 810, which requires that accounting and reporting for minority interest will be recharacterized as +noncontrolling interest and classified as a component of equity. FASB ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of +the noncontrolling owners. FASB ASC 810 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more +subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. We adopted FASB ASC 810 as of January 1, 2009. The adoption did not +have a material impact on our consolidated financial statements. +In March 2008, the FASB issued FASB ASC Topic 815, +“Derivatives and Hedging,” or FASB ASC 815, which requires enhanced disclosures for derivative and hedging activities, including (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related +hedged items are accounted for under FASB ASC 815 and related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash flows. This statement is +effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted FASB ASC 815 as of January 1, 2009. The adoption did not have a material impact on our consolidated financial +statements. +In November 2008, the FASB ratified the consensus reached in FASB ASC Topic 323, “Investments-Equity Method +and Joint Ventures,” or FASB ASC 323. FASB ASC 323 was issued to address questions that arose regarding the application of the equity method subsequent to the issuance of FASB ASC 805. FASB ASC 323 concluded that the equity method investments +should continue to be recognized using a cost accumulation model, thus continuing to include transaction costs in the carrying amount of the equity method investment. In addition, FASB ASC 323 clarifies that an impairment assessment should be +applied to the equity method investment as a whole, rather than to the individual assets underlying the investment. FASB ASC 323 is effective for fiscal years beginning on or after December 15, 2008. We adopted FASB ASC 323 as of +January 1, 2009. The adoption did not have a material impact on our consolidated financial statements. +In December 2008, +the SEC published a final rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about +reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves. In addition, the new disclosure requirements require companies to (a) report the independence and qualifications of its reserve +preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year end +prices. The new requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted in quarterly reports prior to the first annual report in which the revised +disclosures are required. We adopted this final rule as of December 31, 2009. The adoption of the rule resulted in a lower price used in reserve calculations and a decrease in 2009 reserves. Updated disclosures are included in Item 2. +“Properties—Proved Oil and Natural Gas Reserves” and Note 21 to our consolidated financial statements included in this report. +In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (currently codified in FASB ASC Topic 932, “Extractive Activities +– Oil & Gas”), or FASB ASC 932. The purpose of the amendments in this Update is to align the oil and gas reserve estimation and +49 +Table of Contents +Index to Financial Statements +disclosure requirements of FASB ASC 932 with the requirements in the SEC’s final rule, “Modernization of Oil and Gas Reporting . ” The amendments to FASB ASC 932 are effective +for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We adopted FASB ASC 932 effective December 31, 2009, the impact of which is noted above. +In August 2009, the FASB issued FASB ASC Topic 820, “Fair Value Measurements and Disclosures,” or FASB ASC 820, in order to +clarify how entities should estimate the fair value of liabilities. FASB ASC 820 clarifies that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair +value using one or more of the prescribed valuation techniques. We adopted the guidance effective October 1, 2009. The adoption did not have a material impact on our consolidated financial statements. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. +Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and +natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather +conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with +operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree +to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate posted +price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.73 per million British thermal units, or +MMBtu, in September 2009 to a high of $15.52 per MMBtu in December 2005. On December 31, 2009, the West Texas Intermediate posted price for crude oil was $79.39 per bbl and the Henry Hub spot market price of natural gas was $5.83 per MMBtu. Any +substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write +downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price +fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000 barrels of WCBB production at a weighted average price of $55.01 per barrel before transportation costs. We delivered approximately 49% of our 2009 +production under these agreements. Initially, for the period January through December 2009, we had entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation +costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average +daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August 2009. We also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of +$54.81 per barrel, before transportation costs, for the period September 2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and May 2009 for an aggregate of approximately $2.0 million. For the period +January 2010 through February 2010 we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average +50 +Table of Contents +Index to Financial Statements +daily price of $54.81 per barrel, before transportation costs. For the period March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,300 barrels of WCBB +production per day at a weighted average daily price of $58.24 per barrel, before transportation costs. Under these contracts, we have committed to deliver approximately 45% of our estimated 2010 production. Such arrangements may expose us to risk +of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. +Our credit facility and term loans with Bank of America are structured under floating rate terms and, as such, our interest expense is +sensitive to fluctuations in the prime rates in the U.S. Borrowings under our revolving credit facility with Bank of America under the restated credit agreement bear interest at the Eurodollar rate plus 3.5% (3.73% at December 31, 2009). +Outstanding borrowings under the term loan under the restated credit agreement accrue interest at the Eurodollar Rate (as defined in the credit agreement) plus 4% (4.23% at December 31, 2009) or, at our option, at the base rate (which is the +highest of the lender’s prime rate, the Federal funds rate plus 1/2 of 1%, and the one-month Eurodollar Rate plus 1%) plus 3%. Borrowings under our other term loan with Bank of America bear interest at Bank of America prime (3.25% at +December 31, 2009). Based on the current debt structure, a 1% increase in interest rates would increase interest expense by approximately $584,000 per year, based on an aggregate of $49.9 million outstanding under our credit facilities as of +December 31, 2009. As of December 31, 2009, we did not have any interest rate swaps to hedge our interest risks. +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure +that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The +disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely +decisions regarding required disclosures. +As of December 31, 2009, an evaluation was performed under the supervision and +with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under +the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2009, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over +financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +51 +Table of Contents +Index to Financial Statements +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is +also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to +provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the +effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting +financial information. +Management conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—Integrated +Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2009. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended +December 31, 2009 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2009, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +52 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport +Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the +“Company”) as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The +Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s +Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material +weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting +includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with +authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material +effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control +over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as +of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2009 and our report +dated March 12, 2010 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 12, 2010 +ITEM 9B. +OTHER INFORMATION +None. +53 +Table of Contents +Index to Financial Statements +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission +within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning Item 11—Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is +incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, +see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted +therein that are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive +proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not +incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For information concerning Item 14—Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after +the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +54 +Table of Contents +Index to Financial Statements +PART IV +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +List the following documents filed as part of this report: +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor +Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party +seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the +SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, +2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the +Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with +the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a +Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other +Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, +certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +55 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.5 +of Amendment No. 1 to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5 +Amended and Restated Credit Agreement, dated as of December 31, 2009, among the Company, each lender from time to time party thereto and Bank of America, N.A., as +administrative agent (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 6, 2010). +10.6 +Continuing Guaranty, dated as of December 31, 2009, made by Grizzly Holdings, Inc., Jaguar Resources LLC and Gator Marine, Inc. (incorporated by reference to Exhibit 10.2 of +Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 6, 2010). +10.7 +Amended and Restated Revolving Note, dated December 31, 2009, issued by the Company under the Restated Credit Agreement (incorporated by reference to Exhibit 10.3 of Form +8-K, File No. 000-19514, filed by the Company with the SEC on January 6, 2010). +10.8 +Term Note, dated December 31, 2009, issued by the Company under the Restated Credit Agreement (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 000-19514, +filed by the Company with the SEC on January 6, 2010). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Pinnacle Energy Services, LLC. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +56 +Table of Contents +Index to Financial Statements +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the +undersigned, thereunto duly authorized. +Date: March 12, 2010 +G ULFPORT E NERGY C ORPORATION +By: +/s/ J AMES D. +P ALM +James D. Palm +Chief Executive Officer +In accordance with the +Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Date: March 12, 2010 +By: +/s/ J AMES D. +P ALM +James D. Palm +Chief Executive Officer and Director +(Principal Executive Officer) +Date: March 12, 2010 +By: +/s/ M IKE +L IDDELL +Mike Liddell +Chairman of the Board and Director +Date: March 12, 2010 +By: +/s/ M ICHAEL G. +M OORE +Michael G. Moore +Vice President and Chief Financial Officer +(Principal Financial and +Accounting Officer) +Date: March 12, 2010 +By: +/s/ D ONALD +D ILLINGHAM +Donald Dillingham +Director +Date: March 12, 2010 +By: +/s/ D AVID L. +H OUSTON +David L. Houston +Director +Date: March 12, 2010 +By: +/s/ S COTT E. +S TRELLER +Scott E. Streller +Director +S-1 +Table of Contents +Index to Financial Statements +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets, December 31, 2009 and December 31, 2008 +F-3 +Consolidated Statements of Operations, Years Ended December 31, 2009, 2008 and +2007 +F-4 +Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss), Years Ended December 31, +2009, 2008 and 2007 +F-5 +Consolidated Statements of Cash Flows, Years Ended December 31, 2009, 2008 and +2007 +F-6 +Notes to Financial Statements +F-7 +F-1 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated +statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s +management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in +accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of +material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates +made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation and Subsidiaries as of +December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of +America. +As discussed in Note 1, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009. +We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gulfport Energy +Corporation and Subsidiaries’ internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of +the Treadway Commission (COSO) and our report dated March 12, 2010 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 12, 2010 +F-2 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +(Amounts rounded to nearest thousand) +December 31, +2009 +December 31, +2008 +Assets +Current assets: +Cash and cash equivalents +$ +1,724,000 +$ +5,944,000 +Accounts receivable—oil and gas +9,492,000 +12,543,000 +Accounts receivable—related parties +136,000 +1,101,000 +Prepaid expenses and other current assets +2,047,000 +1,045,000 +Total current assets +13,399,000 +20,633,000 +Property and equipment: +Oil and natural gas properties, full-cost accounting, $17,521,000 and $22,543,000 excluded from amortization in 2009 and 2008, +respectively +628,849,000 +599,761,000 +Other property and equipment +7,182,000 +7,168,000 +Accumulated depletion, depreciation, amortization and impairment +(473,915,000 +) +(444,690,000 +) +Property and equipment, net +162,116,000 +162,239,000 +Other assets: +Equity investments +32,006,000 +25,440,000 +Note receivable—related party +15,920,000 +9,153,000 +Other assets +3,370,000 +3,755,000 +Total other assets +51,296,000 +38,348,000 +Deferred tax asset +533,000 +653,000 +Total assets +$ +227,344,000 +$ +221,873,000 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +20,977,000 +$ +27,772,000 +Asset retirement obligation—current +635,000 +635,000 +Short-term derivative instruments +18,735,000 +— +Current maturities of long-term debt +2,842,000 +815,000 +Total current liabilities +43,189,000 +29,222,000 +Asset retirement obligation—long-term +9,518,000 +8,634,000 +Long-term debt, net of current maturities +49,586,000 +69,916,000 +Total liabilities +102,293,000 +107,772,000 +Commitments and contingencies (Notes 18 and 19) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; +0 issued and outstanding +— +— +Stockholders’ equity: +Common stock—$.01 par value, 100,000,000 authorized, 42,696,409 issued and outstanding in 2009 and 42,639,201 in +2008 +427,000 +426,000 +Paid-in capital +273,901,000 +273,343,000 +Accumulated other comprehensive income (loss) +(18,039,000 +) +(4,803,000 +) +Retained earnings (accumulated deficit) +(131,238,000 +) +(154,865,000 +) +Total stockholders’ equity +125,051,000 +114,101,000 +Total liabilities and stockholders’ equity +$ +227,344,000 +$ +221,873,000 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2009 +2008 +2007 +Revenues: +Oil and condensate sales +$ +81,587,000 +$ +131,825,000 +$ +100,120,000 +Gas sales +1,992,000 +6,570,000 +6,043,000 +Natural gas liquid sales +1,997,000 +3,255,000 +— +Other income (expense) +(314,000 +) +(433,000 +) +(325,000 +) +85,262,000 +141,217,000 +105,838,000 +Costs and expenses: +Lease operating expenses +16,316,000 +22,856,000 +16,670,000 +Production taxes +9,797,000 +15,813,000 +12,667,000 +Depreciation, depletion, and amortization +29,225,000 +42,472,000 +29,681,000 +Impairment of oil and gas properties +— +272,722,000 +— +General and administrative +4,992,000 +6,843,000 +5,802,000 +Accretion expense +582,000 +560,000 +554,000 +60,912,000 +361,266,000 +65,374,000 +INCOME (LOSS) FROM OPERATIONS +24,350,000 +(220,049,000 +) +40,464,000 +OTHER (INCOME) EXPENSE: +Interest expense +2,309,000 +4,762,000 +3,091,000 +Settlement of fixed price contracts +— +(39,000,000 +) +— +Insurance proceeds +(1,050,000 +) +(769,000 +) +— +Interest income +(564,000 +) +(540,000 +) +(523,000 +) +695,000 +(35,547,000 +) +2,568,000 +INCOME (LOSS) BEFORE INCOME TAXES +23,655,000 +(184,502,000 +) +37,896,000 +INCOME TAX EXPENSE +28,000 +— +121,000 +NET INCOME (LOSS) +$ +23,627,000 +$ +(184,502,000 +) +$ +37,775,000 +NET INCOME (LOSS) PER COMMON SHARE: +Basic +$ +0.55 +$ +(4.33 +) +$ +1.03 +Diluted +$ +0.55 +$ +(4.33 +) +$ +1.01 +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) +(Amounts rounded to nearest thousand except shares) +Common Stock +Additional +Paid-in +Capital +Accumulated +Other +Comprehensive +Income (Loss) +Retained +Earnings +(Accumulated +Deficit) +Total +Stockholders’ +Equity +Shares +Amount +Balance at January 1, 2007 +33,659,759 +337,000 +131,610,000 +— +(8,138,000 +) +123,809,000 +Net income +— +— +— +— +37,775,000 +37,775,000 +Other Comprehensive Income: +Foreign currency translation adjustment +— +— +— +2,254,000 +— +2,254,000 +Total Comprehensive Income +40,029,000 +Stock Compensation +— +— +1,158,000 +— +— +1,158,000 +Issuance of Common Stock in public offerings, net of related expenses of $740,000 +8,547,500 +85,000 +138,173,000 +— +— +138,258,000 +Issuance of Restricted Stock +35,930 +— +— +— +— +— +Issuance of Common Stock through exercise of options +210,398 +2,000 +866,000 +— +— +868,000 +Balance at December 31, 2007 +42,453,587 +424,000 +271,807,000 +2,254,000 +29,637,000 +304,122,000 +Net loss +— +— +— +— +(184,502,000 +) +(184,502,000 +) +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +(7,057,000 +) +— +(7,057,000 +) +Total Comprehensive Income (Loss) +(191,559,000 +) +Stock Compensation +— +— +1,056,000 +— +— +1,056,000 +Issuance of Restricted Stock +41,493 +— +— +— +— +— +Issuance of Common Stock through exercise of options +144,121 +2,000 +480,000 +— +— +482,000 +Balance at December 31, 2008 +42,639,201 +426,000 +273,343,000 +(4,803,000 +) +(154,865,000 +) +114,101,000 +Net income +— +— +— +— +23,627,000 +23,627,000 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +5,499,000 +— +5,499,000 +Change in fair value of derivative instruments +— +— +— +(13,422,000 +) +— +(13,422,000 +) +Reclassification of derivative contracts +— +— +— +(5,313,000 +) +— +(5,313,000 +) +Total Comprehensive Income (Loss) +10,391,000 +Stock Compensation +— +— +529,000 +— +— +529,000 +Issuance of Restricted Stock +43,458 +— +— +— +— +— +Issuance of Common Stock through exercise of options +13,750 +1,000 +29,000 +— +— +30,000 +Balance at December 31, 2009 +42,696,409 +$ +427,000 +$ +273,901,000 +$ +(18,039,000 +) +$ +(131,238,000 +) +$ +125,051,000 +See accompanying notes to consolidated financial statements. +F-5 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2009 +2008 +2007 +Cash flows from operating activities: +Net income (loss) +$ +23,627,000 +$ +(184,502,000 +) +$ +37,775,000 +Adjustments to reconcile net income to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +582,000 +560,000 +554,000 +Depletion, depreciation and amortization +29,225,000 +42,472,000 +29,681,000 +Impairment of oil and gas properties +— +272,722,000 +— +Stock-based compensation expense +317,000 +634,000 +845,000 +Loss from equity investments +706,000 +656,000 +477,000 +Interest income—note receivable +(547,000 +) +(410,000 +) +— +Deferred income tax benefit +120,000 +(653,000 +) +— +Changes in operating assets and liabilities: +Decrease (increase) in accounts receivable +3,051,000 +(2,033,000 +) +(2,925,000 +) +Decrease in accounts receivable—related party +965,000 +1,107,000 +1,994,000 +(Increase) decrease in prepaid expenses +(1,002,000 +) +301,000 +(374,000 +) +(Decrease) increase in accounts payable and accrued liabilities +(3,686,000 +) +5,328,000 +2,153,000 +Settlement of asset retirement obligation +(59,000 +) +(859,000 +) +(1,278,000 +) +Net cash provided by operating activities +53,299,000 +135,323,000 +68,902,000 +Cash flows from investing activities: +Deductions (additions) to cash held in escrow +8,000 +(40,000 +) +(121,000 +) +Additions to deposits for oil and gas properties +— +— +(3,080,000 +) +Additions to other property, plant and equipment +(14,000 +) +(60,000 +) +(457,000 +) +Additions to oil and gas properties +(49,533,000 +) +(126,030,000 +) +(220,044,000 +) +Proceeds from sale of oil and gas properties +18,286,000 +— +500,000 +Note receivable—related party +(4,377,000 +) +(10,519,000 +) +— +Investment in Grizzly Oil Sands ULC +— +(151,000 +) +(17,316,000 +) +Investment in Tatex Thailand II, LLC +197,000 +862,000 +(88,000 +) +Investment in Tatex Thailand III, LLC +(3,813,000 +) +(885,000 +) +— +Investment in Windsor Bakken, LLC +— +— +(127,000 +) +Net cash used in investing activities +(39,246,000 +) +(136,823,000 +) +(240,733,000 +) +Cash flows from financing activities: +Principal payments on borrowings +(18,303,000 +) +(25,802,000 +) +(47,158,000 +) +Borrowings on line of credit +— +30,000,000 +76,000,000 +Proceeds from issuance of common stock, net of offering costs of $740,000 for 2007, and exercise of stock options +30,000 +482,000 +139,126,000 +Net cash (used in) provided by financing activities +(18,273,000 +) +4,680,000 +167,968,000 +Net (decrease) increase in cash and cash equivalents +(4,220,000 +) +3,180,000 +(3,863,000 +) +Cash and cash equivalents at beginning of period +5,944,000 +2,764,000 +6,627,000 +Cash and cash equivalents at end of period +$ +1,724,000 +$ +5,944,000 +$ +2,764,000 +Supplemental disclosure of cash flow information: +Interest payments +$ +2,300,000 +$ +4,898,000 +$ +3,341,000 +Income tax payments +$ +543,000 +$ +135,000 +$ +121,000 +Supplemental disclosure of non-cash transactions: +Investment subscription payable +$ +— +$ +— +$ +151,000 +Capitalized stock based compensation +$ +212,000 +$ +422,000 +$ +313,000 +Asset retirement obligation capitalized +$ +361,000 +$ +934,000 +$ +500,000 +Dissolution of interest in Windsor Bakken, LLC +$ +— +$ +2,468,000 +$ +— +Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC +$ +3,656,000 +$ +(5,281,000 +) +$ +2,254,000 +Foreign currency translation gain (loss) on note receivable—related party +$ +1,843,000 +$ +(1,776,000 +) +$ +— +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil +and gas exploration, development and production company with its principal properties located in the Louisiana Gulf Coast and in West Texas in the Permian Basin and has investments in companies operating in Canada and Thailand. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include +the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc. and Puma Resources, Inc. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The +Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its receivables are from two purchasers of the Company’s oil and gas and one operator of certain of the Company’s +properties. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for +doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length +of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and +the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful +accounts. No allowance was deemed necessary at December 31, 2009 and December 31, 2008. +Oil and Gas Properties +The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and +certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, based on the 12-month +unweighted average of the first-day-of the month price for the period January through December 2009, and for prior years, year-end prices, and costs as adjusted for the Company’s cash flow hedge positions and net of tax effects, discounted at +10% per year, from proven oil and gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are +depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly +alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject +F-7 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +to amortization consist of the cost of unproved leaseholds and totaled $17,521,000 and $22,543,000 at December 31, 2009 and December 31, 2008, respectively. These costs are reviewed +quarterly by management for impairment. If an impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its +impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. +The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, “ Asset Retirement and Environmental +Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation +meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original +liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the +liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment +is provided on a straight-line basis over estimated useful lives of the related assets, which range from 3 to 30 years. +Foreign Currency +The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity +investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. +Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table +presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive income. +December 31, 2006 +$ +— +December 31, 2007 +$ +2,254,000 +December 31, 2008 +$ +(4,803,000 +) +December 31, 2009 +$ +696,000 +Net Income per Common Share +Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number +of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common +shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 13. +F-8 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Income Taxes +Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized +for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax +assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized +in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the +deferred tax assets will not be realized. +The company adopted the provisions of FASB ASC Topic 740 as of January 1, +2007. The adoption of FASB ASC 740 had no effect on the Company’s consolidated financial statements. The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1996 – 2008 U.S. +federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2009, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The +Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended December 31, 2009, there is no interest or +penalties associated with uncertain tax positions in the Company’s consolidated financial statements. +Revenue Recognition +Gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any +production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. There is no such +liability or asset recorded at December 31, 2009 and 2008 because the Company has no imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month produced. +Investments—Equity Method +Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The +Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. There was no impairment of equity method investments at +December 31, 2009 or 2008. +Accounting for Stock-Based Compensation +The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, “ Compensation—Stock +Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options, to be recognized as equity or liabilities at the fair value on the date of grant and to be +expensed over the applicable vesting period. +F-9 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Accounting for Derivative Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price +contracts. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in the +statement of financial position, measured at fair value. +The Company estimates the fair value of all derivative instruments +using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values reported in the +consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but +re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized +in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized +immediately in earnings. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that +affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to +these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred +tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment +of oil and gas properties. +Recent Accounting Pronouncements +In June 2009, the FASB issued the FASB Accounting Standards Codification (“ASC”) and the Hierarchy of Generally Accepted Accounting +Principles (the “Codification”). The Codification became the single official source of authoritative, nongovernmental U.S. generally accepted accounting principles (“GAAP”). The Codification did not change GAAP but reorganizes +the literature. The Codification is effective for interim and annual periods ending after September 15, 2009. There was no impact on the Company’s consolidated financial statements as a result of the Codification. +Effective January 1, 2007, the Company adopted FASB ASC Topic 740, “ Income Taxes ” (“FASB ASC 740”). FASB 740 +prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Based on this guidance, the Company regularly analyzes tax positions taken or expected +to be taken in a tax return based on the threshold prescribed under FASB 740. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. The adoption of FASB ASC 740 had no effect on the Company’s +consolidated financial statements. +F-10 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Effective January 1, 2008, the Company implemented FASB ASC +Topic 820, “Fair Value Measurements and Disclosures” (“FASB ASC 820”), which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. The Company elected to +implement the provisions of FASB ASC 820 with the permitted one-year deferral for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis until the effective date of +January 1, 2009. The deferral applied to nonfinancial assets and liabilities measured at fair value in a business combination, impaired properties, plants and equipment, intangible assets and goodwill, and initial recognition of asset retirement +obligations and restructuring costs for which fair value is used. The adoption of the provisions of FASB ASC 820 did not have a material impact on the Company’s consolidated financial statements. +In December 2007, the FASB issued FASB ASC Topic 805, “ Business Combinations ” (“FASB ASC 805”). FASB ASC 805 +establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. FASB +ASC 805 also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. FASB ASC 805 is effective for acquisitions that occur in an entity’s fiscal year that begins after +December 15, 2008. The adoption did not have an immediate impact on the Company’s consolidated financial statements. +In December 2007, the FASB issued FASB ASC Topic 810, “ Consolidation ” (“FASB ASC 810”), which requires that accounting and reporting for minority interest will be recharacterized as noncontrolling interest and +classified as a component of equity. FASB ASC 810 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the noncontrolling owners. +FASB ASC 810 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that +deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company adopted FASB ASC 810 as of January 1, 2009. The adoption did not have a +material impact on the Company’s consolidated financial statements. +In March 2008, the FASB issued FASB ASC Topic 815, +“ Derivatives and Hedging ” (“FASB ASC 815”), which requires enhanced disclosures for derivative and hedging activities, including (a) how and why an entity uses derivative instruments, (b) how derivative +instruments and related hedged items are accounted for under FASB ASC 815 and related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, results of operations, and cash +flows. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company adopted FASB ASC 815 as of January 1, 2009. The adoption did not have a material impact +on the Company’s consolidated financial statements. +In November 2008, the FASB ratified the consensus reached in FASB +ASC Topic 323, “ Investments-Equity Method and Joint Ventures ” (“FASB ASC 323”). FASB ASC 323 was issued to address questions that arose regarding the application of the equity method subsequent to the issuance of FASB ASC +805. FASB ASC 323 concluded that the equity method investments should continue to be recognized using a cost accumulation model, thus continuing to include transaction costs in the carrying amount of the equity method investment. In addition, FASB +ASC 323 clarifies that an impairment assessment should be applied to the equity method investment as a whole, rather than to the individual assets underlying the investment. FASB ASC 323 is effective for fiscal years beginning on or after +December 15, 2008. The Company adopted FASB ASC 323 as of January 1, 2009. The adoption did not have a material impact to the Company’s consolidated financial statements. +F-11 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +In December 2008, the Securities and Exchange Commission +published a Final Rule, “ Modernization of Oil and Gas Reporting .” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about +reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves. In addition, the new disclosure requirements require companies to (a) report the independence and qualifications of its reserve +preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average price based upon the prior 12 month period rather than year end +prices. The new requirements were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company adopted the Final Rule as of December 31, 2009. The adoption of the rule resulted in a lower +price used in reserve calculations and a decrease in 2009 reserves. See Item 2. Properties and Note 21 for further discussion of the impact of implementation. +In January 2010, the FASB issued Accounting Standards Update 2010-03, “ Oil and Gas Reserve Estimation and Disclosures ” (currently codified in FASB ASC Topic 932, “ Extractive +Activities – Oil & Gas ”) (“FASB ASC 932”). The purpose of the amendments in this Update is to align the oil and gas reserve estimation and disclosure requirements of FASB ASC 932 with the requirements in the Security +and Exchange Commission’s Final Rule, “ Modernization of Oil and Gas Reporting. ” The amendments to FASB ASC 932 are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The impact +of the adoption of FASB ASC 932 is noted above. +In August 2009, the FASB issued Accounting Standards Update 2009-05, +“ Measuring Liabilities at Fair Value ” (currently codified in FASB ASC Topic 820, “ Fair Value Measurements and Disclosures ”) (“FASB ASC 820”) in order to clarify how entities should estimate the fair value +of liabilities. FASB ASC 820 clarifies that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the prescribed valuation +techniques. The Company adopted the guidance effective October 1, 2009. The adoption did not have a material impact on the Company’s consolidated financial statements. +2. +ACQUISITIONS +On +December 20, 2007, Gulfport closed on the acquisition of an ownership interest in certain oil and gas properties located in the Permian Basin of West Texas, consisting of approximately 4,100 net acres with 32 gross producing wells from ExL +Petroleum, LP and 12 other sellers. The effective date of the acquisition was November 1, 2007. The total purchase price for the assets, as adjusted at the original closing on December 20, 2007, was $85.2 million, which was recorded as oil +and natural gas properties on the accompanying balance sheet. This amount includes an adjustment for the results of operations of the assets between the November 1, 2007 effective date and the December 20, 2007 closing date. The final post +closing adjustments occurred 90 days from the original closing date of December 20, 2007, or March 20, 2008, and the purchase price was adjusted accordingly. The total adjusted purchase price for the assets was $83.8 million. +Gulfport funded this transaction predominately through a 4.5 million common share offering, which closed on December 12, 2007. +The Company received net proceeds of approximately $75.6 million from the equity offering, as discussed in Note 8. The Company funded the remainder of the purchase price from borrowings under its line of credit. +The following unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company’s consolidated +results of operations as if the acquisition had occurred on January 1, 2007. The pro +F-12 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +forma results for the period presented are the result of combining the Company’s consolidated statements of operations with the revenues and direct operating expenses of the acquired +properties adjusted for (1) incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the acquisition, amortized on a unit-of-production basis over the remaining life of total proved reserves, as +applicable, (2) incremental accretion of discount on asset retirement obligation associated with the acquired properties, (3) estimated incremental interest expenses associated with borrowings under Gulfport’s revolving credit +facility to fund the acquisitions, and (4) the issuance of 4.5 million shares of common stock in the offering at January 1, 2007 rather than December 12, 2007. The pro forma information is based upon numerous assumptions, and is +not necessarily indicative of what the Company’s actual results would have been or the Company’s future results of operations. +Unaudited +Year Ended December 31, +2007 +Total revenue +$ +121,903,000 +Net income +46,799,000 +Net income per common share: +Basic +$ +1.14 +Diluted +$ +1.12 +3. +ACCOUNTS RECEIVABLE—RELATED PARTIES +Included in the accompanying December 31, 2009 and December 31, 2008 consolidated balance sheets are amounts receivable from related parties of the Company. These receivables represent amounts +billed by the Company for general and administrative functions, such as accounting, human resources, legal, and technical support, performed by Gulfport’s personnel on behalf of these related parties. These services are solely administrative in +nature and for entities in which the Company has no property interests. The amounts reimbursed to the Company for these services are for the purpose of Gulfport recovering costs associated with the services and do not include the assessment of any +fees or other amounts beyond the estimated costs of performing such services. At December 31, 2009 and December 31, 2008, these receivables totaled $136,000 and $1,101,000, respectively. The Company recorded $593,000, $1,363,000 and +$11,153,000 for the years ended December 31, 2009, 2008 and 2007, respectively, for general and administrative functions which are reflected as a reduction of general and administrative expenses in the consolidated statements of operations and +include the amounts under service contracts discussed below. +The Company is or has been a party to administrative service +agreements with Caliber Development Company, LLC, Great White Energy Services LLC, and Diamondback Energy Services LLC. Under these agreements, the Company’s services include accounting, human resources, legal and technical support. The +services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a three-year term, and upon expiration of that term the agreements will continue on a +month-to-month basis until cancelled by either party with at least 30 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to the Company +and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. +The Company is also a party to administrative service agreements with Stampede Farms LLC, Grizzly Oil Sands ULC, Everest Operations Management LLC and Tatex Thailand III, LLC. Under these agreements, the +F-13 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Company’s services include professional and technical support and office space. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each +of these administrative service agreements has a two-year term, and upon expiration of that term such agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at least 60 days prior written notice. +Each administrative service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to the Company and (2) by either party if the other party is in material breach and such breach has not been +cured within 30 days of receipt of written notice of such breach. +The Company was reimbursed the following amounts by the +specified entities in consideration for its administrative services for the years ended December 31, 2009, 2008 and 2007. These amounts are reflected as a reduction of general and administrative expenses in the consolidated statements of +operations. Wexford Capital LP (“Wexford”) controls and/or owns a greater than 10% interest in each of these entities. Affiliates of Wexford own approximately 36% of Gulfport’s outstanding stock. +Agreement +Effective Date +Entity +December 31, +2009 +2008 +2007 +2/9/2005 +Caliber Development Company, LLC* +$ +— +$ +60,000 +$ +1,249,000 +7/22/2006 +Great White Energy Services LLC +61,000 +83,000 +754,000 +9/26/2006 +Diamondback Energy Services LLC* +— +10,000 +17,000 +3/1/2008 +Stampede Farms LLC +— +159,000 +123,000 +3/1/2008 +Grizzly Oil Sands ULC +20,000 +368,000 +953,000 +3/1/2008 +Everest Operations Management LLC +508,000 +154,000 +— +3/1/2008 +Tatex Thailand III, LLC +— +— +— +* +Agreement was terminated effective December 10, 2008. +For the year ended December 31, 2009, the Company was also reimbursed approximately $2,000 and $1,000 by Stampede Farms LLC and Everest Operations Management LLC, respectively, and approximately +$20,000 and $26,000, respectively, for the year ended December 31, 2008, for office space under the administrative service agreements, which is included in other income (expense) in the consolidated statements of operations. +Effective July 1, 2008, the Company entered into an acquisition team agreement with Everest Operations Management LLC +(“Everest”) to identify and evaluate potential oil and gas properties in which the Company and Everest may wish to invest. Upon a successful closing of an acquisition or divestiture, the party identifying the acquisition or divestiture is +entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or divestiture consideration. The agreement may be +terminated by either party upon 30 days notice. +F-14 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +4. +PROPERTY AND EQUIPMENT +The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2009 and 2008 are as follows: +December 31, +2009 +2008 +Oil and natural gas properties +$ +628,849,000 +$ +599,761,000 +Office furniture and fixtures +2,996,000 +2,982,000 +Building +3,926,000 +3,926,000 +Land +260,000 +260,000 +Total property and equipment +636,031,000 +606,929,000 +Accumulated depletion, depreciation, amortization and impairment +(473,915,000 +) +(444,690,000 +) +Property and equipment, net +$ +162,116,000 +$ +162,239,000 +At December 31, 2008, the net book value of the Company’s oil and natural gas properties, less +related deferred income taxes, was above the calculated ceiling as a result of reduced commodity prices at December 31, 2008. As a result, the Company was required to record an impairment of its oil and natural gas properties under the full +cost method of accounting in the amount of $272.7 million for the year ended December 31, 2008. No impairment of oil and natural gas properties was required for the year ended December 31, 2009. +Included in oil and natural gas properties at December 31, 2009 and December 31, 2008 is the cumulative capitalization of +$14,009,000 and $10,614,000, respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred +directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with +exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $3,395,000, $4,645,000 and $2,041,000 for the years ended December 31, 2009, 2008 and 2007, +respectively. +The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of +December 31, 2009: +Costs Incurred in +2009 +2008 +2007 +Prior to +2007 +Total +Acquisition costs +$ +2,592,000 +$ +5,000 +$ +13,003,000 +$ +592,000 +$ +16,192,000 +Exploration costs +155,000 +1,069,000 +105,000 +— +1,329,000 +Development costs +— +— +— +— +— +Total oil and gas properties not subject to amortization +$ +2,747,000 +$ +1,074,000 +$ +13,108,000 +$ +592,000 +$ +17,521,000 +At December 31, 2009, approximately $2,329,000 of +oil and gas properties related to the Company’s Belize properties is excluded from amortization as it relates to non-producing properties. In addition, approximately +F-15 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +$13,842,000 of non-producing leasehold costs resulting from the Company’s acquisition of West Texas Permian properties and $361,000 of non-producing leasehold costs related to the +Company’s Bakken properties are excluded from amortization at December 31, 2009. Approximately $989,000 of non-producing leasehold costs related to the Company’s Southern Louisiana assets was also excluded from amortization. At +December 31, 2008, approximately $22,543,000 of non-producing leasehold costs was not subject to amortization. +The +Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s +amortization calculation is expected to occur within three to five years. +A reconciliation of the asset retirement obligation +for the years ended December 31, 2009 and 2008 is as follows: +December 31, +2009 +2008 +Asset retirement obligation, beginning of period +$ +9,269,000 +$ +8,634,000 +Liabilities incurred +361,000 +934,000 +Liabilities settled +(59,000 +) +(859,000 +) +Accretion expense +582,000 +560,000 +Asset retirement obligation as of end of period +10,153,000 +9,269,000 +Less current portion +635,000 +635,000 +Asset retirement obligation, long-term +$ +9,518,000 +$ +8,634,000 +5. +EQUITY INVESTMENTS +Investments accounted for by the equity method consist of the following as of December 31, 2009 and 2008: +December 31, +2009 +2008 +Investment in Tatex Thailand II, LLC +$ +2,485,000 +$ +2,683,000 +Investment in Tatex Thailand III, LLC +4,482,000 +876,000 +Investment in Grizzly Oil Sands ULC +25,039,000 +21,881,000 +$ +32,006,000 +$ +25,440,000 +Tatex Thailand II, LLC +During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a cost of $2,400,000. The +remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a +reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. During 2009, Gulfport paid $320,000 in cash calls and received $517,000 in distributions, bringing its total +investment in Tatex (including previous investments) to $2,485,000. The loss on equity investment related to Tatex was immaterial for the years ended December 31, 2009, 2008 and 2007. +F-16 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Tatex Thailand III, LLC +During the first quarter of 2008, the Company purchased a 5% ownership interest in Tatex Thailand III, LLC (“Tatex III”) at a cost +of $850,000. In December 2009, the Company purchased an additional approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing its total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2009, Gulfport paid $428,000 in cash calls, bringing its total investment in Tatex III to $4,482,000. The Company recognized a loss on equity +investment of $207,000 and $9,000 for the year ended December 31, 2009 and 2008, respectively, which is included in other income (expense) in the consolidated statements of operations. +Windsor Bakken, LLC +During +2005, the Company purchased a 20% ownership interest in Windsor Bakken, LLC (“Bakken”). The remaining interests in Bakken are owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the +Williston Basin areas of western North Dakota and eastern Montana. As of December 31, 2007, Gulfport’s net investment in Bakken was $2,468,000. As of December 31, 2007, Bakken had commenced drilling of some of its undeveloped acreage. +The Company recognized losses on equity investment of $92,000 for the year ended December 31, 2007 which is included in other income (expense) in the consolidated statements of operations. +Effective January 1, 2008, the Company acquired a direct, undivided 20% interest in Bakken’s assets in redemption of its 20% +interest in Bakken. As a result, the Company recognized $2,468,000 of oil and natural gas assets which was included in oil and natural gas properties on the accompanying consolidated balance sheets. +Grizzly Oil Sands ULC +During the third quarter of 2006, the Company, through its wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company, for +approximately $8.2 million. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands +development projects. Grizzly has commenced drilling of core holes for feasibility of oil production in five separate lease blocks but has not commenced development of operations. As of December 31, 2009 and 2008, Gulfport’s net investment +in Grizzly was $25,039,000 and $21,881,000, respectively. Grizzly’s functional currency is the Canadian dollar. The Company’s investment in Grizzly was increased by $3,656,000 as a result of a currency translation gain for the year ended +December 31, 2009 and decreased by $5,281,000 as a result of a currency translation loss for the year ended December 31, 2008. The Company recognized a loss on equity investment of $498,000, $639,000 and $385,000 for the years ended +December 31, 2009, 2008 and 2007, respectively, which is included in other income (expense) in the consolidated statements of operations. +The Company, through its wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow funds from the Company. +Borrowed funds bear interest at LIBOR plus 400 basis points. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan matures on December 31, 2012. The Company loaned Grizzly approximately $4,377,000 +during the year ended December 31, 2009. The Company recognized interest income of approximately $547,000 and $410,000 for the years ended December 31, 2009 and 2008, respectively, which +F-17 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +is included in interest income in the consolidated statements of operations. The note balance was increased by approximately $1,843,000 as a result of a currency translation gain for the year +ended December 31, 2009 and decreased by approximately $1,776,000 as a result of a currency translation loss for the year ended December 31, 2008. The total $15,920,000 due from Grizzly is included in note receivable—related party on +the accompanying consolidated balance sheets. +The table below summarizes financial information for Grizzly as of December 31, +2009, 2008 and 2007. +December 31, +2009 +2008 +2007 +Current assets +$ +2,064,000 +$ +1,481,000 +$ +428,000 +Noncurrent assets +$ +164,043,000 +$ +125,024,000 +$ +114,857,000 +Current liabilities +$ +1,585,000 +$ +2,663,000 +$ +4,175,000 +Noncurrent liabilities +$ +64,365,000 +$ +36,397,000 +$ +— +Gross revenue +$ +— +$ +— +$ +— +Loss from continuing operations +$ +1,992,000 +$ +2,595,000 +$ +1,540,000 +Net loss +$ +1,991,000 +$ +2,557,000 +$ +1,540,000 +6. +OTHER ASSETS +Other +assets consist of the following as of December 31, 2009 and 2008: +December 31, +2009 +2008 +Plugging and abandonment escrow account on the WCBB properties (Note 18) +$ +3,136,000 +$ +3,144,000 +Certificates of Deposit securing letter of credit +200,000 +200,000 +Prepaid drilling costs +30,000 +407,000 +Deposits +4,000 +4,000 +$ +3,370,000 +$ +3,755,000 +7. +LONG-TERM DEBT +A +break-down of long-term debt as of December 31, 2009 and 2008 is as follows: +December 31, +2009 +2008 +Reducing credit agreement (1) +$ +45,000,000 +$ +64,521,000 +Term loans (1) +4,903,000 +3,588,000 +Building loans (2) +2,525,000 +2,622,000 +Less: current maturities of long term debt +(2,842,000 +) +(815,000 +) +Debt reflected as long term +$ +49,586,000 +$ +69,916,000 +F-18 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Maturities of long-term debt as of December 31, 2009 are as +follows: +2010 +$ +2,842,000 +2011 +48,132,000 +2012 +714,000 +2013 +740,000 +2014 +— +Thereafter +— +Total +$ +52,428,000 +(1) On March 11, 2005, Gulfport entered into a +three-year secured reducing credit agreement, as amended, with Bank of America, N.A. providing for a revolving credit facility. Borrowings under the revolving credit facility are subject to a borrowing base limitation, which was initially set at +$18.0 million, subject to adjustment. On November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount +available under the borrowing base limitation was increased to $30.0 million. Effective July 19, 2007, the credit facility was increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0 +million. In connection with the Company’s acquisition of strategic assets in West Texas in the Permian Basin, effective as of December 20, 2007, the borrowing base under the revolving credit facility was increased from $60.0 million to +$90.0 million. In addition, the maturity date was extended from March 31, 2009 to March 31, 2010. On August 31, 2009, the lender completed its periodic redetermination of the Company’s borrowing base giving consideration to +year-end 2008 and mid-year 2009 reserve information and then current bank pricing decks, among other factors. As a result of this redetermination, the Company’s available borrowing base was reset at $45.0 million, primarily in response to +significant declines in commodity prices. The Company’s outstanding principal balance at the effective time of this redetermination was approximately $59.0 million. Amounts borrowed under the credit facility bear interest at the Eurodollar rate +plus 3.50% (3.73% at December 31, 2009). The approximately $14.0 million of outstanding borrowings under the credit facility in excess of the new borrowing base was converted into a term loan as of August 31, 2009. An initial $2.0 million +payment was made on the term loan at that time and the Company agreed to make additional monthly payments of $1.0 million commencing on September 30, 2009, with all unpaid amounts due on March 31, 2010. +Outstanding borrowings under the term loan accrue interest at the Eurodollar rate (as defined in the credit agreement) plus 4.0% (4.23% at +December 31, 2009) or, at the option of the Company, at the base rate (which is the highest of the lender’s prime rate, the Federal funds rate plus half of 1%, and the one-month Eurodollar rate plus 1%) plus 3%. Effective August 31, +2009, the Company also agreed to an adjustment in the commitment fees, interest rates for revolving loans and fees for letters of credit under the credit facility. Specifically, the Company agreed to pay (a) commitment fees ranging from 0.5% to +0.625% (an increase from 0.15% to 0.25%), (b) margin interest rates ranging from 2.75% to 3.50% for Eurodollar loans (an increase from 1.25% to 2.0%), (c) margin interest rates ranging from 1.75% to 2.5% for base rate loans (an increase +from 1.25% to 2.0%), and (d) letter of credit fees at the margin interest rates for Eurodollar loans, in each case based on the Company’s utilization percentage. In addition, the Company agreed to limitations on certain dispositions and +investments and to mandatory prepayments of the loans from the net cash proceeds of specified asset sales and other events. +Effective December 31, 2009, the Company entered into the amended and restated credit agreement with Bank of America, N.A., as administrative agent, and the other lenders from time to time party thereto. The restated credit agreement +amended and restated the Company’s original 2005 credit agreement primarily to reflect the subsequent +F-19 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +amendments thereto and to extend the maturity date of the revolving loan under the original 2005 credit agreement with Bank of America, N.A. from March 31, 2010 to April 1, 2011. The +restated credit agreement did not alter the March 31, 2010 maturity date of the term loan outstanding under the original 2005 credit agreement. The obligations under the restated credit agreement are guaranteed by the Company’s +subsidiaries. +The Company’s obligations under the credit facility are collateralized by a lien on substantially all of +the Company’s Louisiana and West Texas assets. The restated credit agreement contains certain affirmative and negative covenants, including, but not limited to the following financial covenants: (a) the ratio of funded debt to EBITDAX (net +income before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest expense, plus exploration costs deducted in determining net income +under full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. The Company was in compliance with all +covenants at December 31, 2009. As it has historically, the Company continues to make all interest payments on time. +As +of December 31, 2009, approximately $45.0 million was outstanding under the revolving credit facility, which is included in long-term debt, net of current maturities on the accompanying consolidated balance sheet and approximately $2.0 million +was outstanding under this term loan, which is included in current maturities of long-term debt on the accompanying consolidated balance sheet. +On July 10, 2006, Gulfport entered into a $5 million term loan agreement with Bank of America, N.A. related to the purchase of new gas compressor units. The loan began amortizing quarterly on +March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. The Company makes quarterly principal payments of approximately $176,000. Amounts borrowed bear interest at Bank of +America Prime (3.25% at December 31, 2009). The Company makes quarterly interest payments on amounts borrowed under the agreement. The Company’s obligations under the agreement are collateralized by a lien on the compressor units. As of +December 31, 2009, approximately $2.9 million was outstanding under this agreement, of which $714,000 and $2.2 million are included in current maturities of long-term debt and long-term debt, net of current maturities, respectively, on the +accompanying consolidated balance sheet. +(2) In June 2004, the Company purchased the office building it occupies in Oklahoma +City, Oklahoma, for $3.7 million. One loan associated with this building matured in March 2006 and bore interest at the rate of 6% per annum, while the other loan matures in June 2011 and bears interest at the rate of 6.5% per annum. In +addition, the building loans included a loan related to a building in Lafayette, Louisiana, purchased in 1996 to be used as the Company’s Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. The Company paid this +loan in full during the third quarter of 2007, in advance of its February 2008 maturity date. The remaining building loan requires monthly interest and principal payments of approximately $23,000 and is collateralized by the Oklahoma City office +building and associated land . +8. +COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the +“Plan”), which is administered by the Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be +granted, the number of +F-20 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are +defined as all directors of the Company, all officers of the Company and all key employees of the Company with a customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted +under the Plan, as adjusted for changes in capitalization which have taken place since the Plan’s adoption, was 883,000. The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of +December 31, 2009. No additional securities will be issued under the Plan other than upon exercise of options that are outstanding. +The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may +determine when options shall be granted, to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the +exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) Incentive Stock Options, (b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), +(d) Performance Awards and (e) Stock Appreciation Rights and (ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares +underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 2009, the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. +Restricted Stock +On April 1, 2007, the Company granted 16,389 shares of restricted common stock of the Company. These shares vest monthly over a three year period. On May 15, 2007, the Company granted 10,000 shares of restricted common stock of +the Company. These shares vest in equal monthly installments over a three year period. On August 14, 2007, the Company granted 8,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three +year period. On November 9, 2007, the Company granted 3,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three year period. +On March 13, 2008, the Company granted 6,666 shares of restricted common stock of the Company, of which 740 shares vested on +April 1, 2008 with the remaining shares vesting over 36 equal monthly installments beginning on May 1, 2008. On August 6, 2008, the Company granted 2,000 shares of restricted common stock of the Company. The shares vest over twelve +equal quarterly installments beginning on September 17, 2008. On September 15, 2008, the Company granted 10,000 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments beginning on +September 17, 2008. On December 5, 2008, the Company granted 66,667 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments beginning on December 17, 2008. +On November 3, 2009, the Company granted 13,332 shares of restricted common stock of the Company. The shares vest over twelve equal +quarterly installments beginning on December 17, 2009. All shares of restricted common stock of the Company were granted under the amended and restated 2005 Plan. +F-21 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Sale of Common Stock +On January 30, 2007, the Company sold 1,150,000 shares of common stock in an underwritten offering at an offering price to the public of +$11.92 per share. In connection with the offering, the Company granted the underwriter an option to purchase up to an additional 172,500 shares of common stock to cover any over-allotments, which the underwriter exercised in full on February 1, +2007. The Company received the net proceeds of approximately $15.3 million from the sale of these shares on February 5, 2007 after deducting the underwriting discount and before offering expenses. +In May 2007, the Company sold 1,500,000 shares of common stock in an underwritten offering at an offering price to the public of $16.00 per +share. In connection with the offering, the Company granted the underwriter an option to purchase up to an additional 225,000 shares of common stock to cover any over-allotments, which the underwriter exercised in full. The Company received the net +proceeds of approximately $26.8 million from the sale of these shares on May 22, 2007 after deducting the underwriting discount and before offering expenses. +In July 2007, the Company sold 1,000,000 share of common stock in an underwritten offering at an offering price to the public of $22.00 per share. The Company received the net proceeds of approximately +$21.2 million from the sale of these shares on July 25, 2007 after deducting the underwriting discount and before offering expenses. +In December 2007, the Company sold 4,500,000 shares of common stock in an underwritten offering at an offering price to the public of $17.50 per share. The Company received the net proceeds of +approximately $75.6 million from the sale of these shares on December 12, 2007 after deducting underwriting discounts and before offering expenses. In connection with the offering, a selling stockholder granted the underwriter an option to +purchase an additional 675,000 shares of common stock to cover any over-allotments, which the underwriter exercised in full. The Company did not receive any proceeds from the sale of shares of the common stock by the selling stockholder. +Private Placement Offering +In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred Stock, Series A, of the Company (the “Preferred”) and (ii) a warrant to +purchase up to 250 shares of common stock, par value $0.01 per share, of the Company (the “Warrants”). Holders of the Preferred were entitled to receive dividends at the rate of 12% of the liquidation preference per annum payable quarterly +in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of Preferred at the rate of 15% of the liquidation preference per annum. All Preferred shares were +redeemed in 2005. +The 2,322,962 Warrants issued have a term of ten years and a current exercise price of $1.19 per share of +common stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the Warrants. The Company considered the valuation +of the Warrants and did not consider them materially significant. The Company had 60,550 Warrants outstanding at December 31, 2009 and 2008 which can be converted into 203,529 shares of common stock. +F-22 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +9. +STOCK-BASED COMPENSATION +During the years ended December 31, 2009, 2008 and 2007, the Company’s stock-based compensation cost was $529,000, $1,056,000 and $1,158,000, respectively, of which the Company capitalized $212,000, $422,000 and $313,000, +respectively, relating to its exploration and development efforts, which reduced basic and diluted earnings per share by $0.01 and $0.01 for the years ended December 31, 2009 and December 31, 2008, respectively. +The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. Expected volatilities +are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon historical experience of the Company, the expected term of options granted is equal to the vesting +period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have an exercise price not less +than the fair value of the Company’s common stock on the date of the grant. +No stock options were issued during the +years ended December 31, 2009, 2008 and 2007. +The Company has not declared dividends and does not intend to do so in the +foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance that the value +an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. +A summary of the status +of stock options and related activity for the years ended December 31, 2009, 2008 and 2007 are presented below: +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value +Options outstanding at December 31, 2006 +967,233 +$ +5.54 +7.76 +$ +7,782,000 +Granted +— +— +Exercised +(210,398 +) +4.13 +2,284,000 +Forfeited/expired +(82,445 +) +3.66 +Options outstanding at December 31, 2007 +674,390 +6.22 +6.97 +8,098,000 +Granted +— +— +Exercised +(144,121 +) +3.34 +1,694,000 +Forfeited/expired +(7,889 +) +6.17 +Options outstanding at December 31, 2008 +522,380 +7.01 +6.24 +$ +(1,599,000 +) +Granted +— +— +Exercised +(13,750 +) +2.20 +71,000 +Forfeited/expired +— +— +Options outstanding at December 31, 2009 +508,630 +$ +7.14 +5.38 +$ +2,192,000 +Options exercisable at December 31, 2009 +404,509 +$ +8.11 +5.46 +$ +1,350,000 +F-23 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Unrecognized compensation expense as of December 31, 2009 +related to outstanding stock options and restricted shares was $377,000. The expense is expected to be recognized over a weighted average period of 1.49 years. +The following table summarizes information about the stock options outstanding at December 31, 2009: +Exercise +Price +Number +Outstanding +Weighted Average +Remaining Life +(in +years) +Number +Exercisable +$ +2.00 +11,500 +0.71 +11,500 +$ +3.36 +232,241 +5.06 +128,120 +$ +9.07 +64,889 +5.69 +64,889 +$ +11.20 +200,000 +5.92 +200,000 +508,630 +404,509 +The following table summarizes restricted stock +activity for the twelve months ended December 31, 2009, 2008 and 2007: +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2006 +69,518 +$ +12.81 +Granted +37,389 +15.66 +Vested +(35,930 +) +13.13 +Forfeited +(11,944 +) +15.24 +Unvested shares as of December 31, 2007 +59,033 +$ +13.94 +Granted +85,333 +$ +5.64 +Vested +(41,493 +) +11.97 +Forfeited +(9,417 +) +15.84 +Unvested shares as of December 31, 2008 +93,456 +$ +7.04 +Granted +13,332 +$ +8.08 +Vested +(43,458 +) +8.16 +Forfeited +(3,086 +) +15.77 +Unvested shares as of December 31, 2009 +60,244 +$ +6.01 +10. +INSURANCE PROCEEDS +In +May 2008, the Company received insurance proceeds of approximately $769,000 related to damages incurred resulting from a 2006 barge accident in its WCBB field. The costs associated with repairing the field were expensed to lease operating expenses +as incurred in 2006 and 2007. The Company recognized the insurance proceeds in other (income) expense in the accompanying consolidated statements of operations. +In March 2009, the Company received insurance proceeds of approximately $1,050,000 related to damages incurred in its WCBB field as a result of Hurricane Ike in 2008. The costs associated with repairing +the field were +F-24 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +expensed to lease operating expenses as incurred in 2008 and 2009. The Company recognized the insurance proceeds in other (income) expense in the accompanying consolidated statements of +operations. In September and October 2009, the Company received additional insurance proceeds of approximately $994,000 related to damages incurred in the WCBB field as a result of Hurricane Ike and related debris removal. As the costs related to +these repairs and debris removal were incurred in 2009 and expensed to lease operating expense, the Company recognized the insurance proceeds in lease operating expenses in the accompanying consolidated statements of operations. +11. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current and long-term debt are carried +at cost, which approximates market value. +The fair value of the derivative instruments is computed based on the difference +between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and +are subject to significant volatility. +12. +INCOME TAXES +The income +tax provision consists of the following: +2009 +2008 +2007 +Current: +State +$ +28,000 +$ +— +$ +— +Federal +32,000 +653,000 +121,000 +Deferred: +State +— +— +— +Federal +(32,000 +) +(653,000 +) +— +Total income tax expense (benefit) provision +$ +28,000 +$ +— +$ +121,000 +A reconciliation of the statutory federal income tax +amount to the recorded expense follows: +2009 +2008 +2007 +Income (loss) before federal income taxes +$ +23,655,000 +$ +(184,502,000 +) +$ +37,775,000 +Expected income tax at statutory rate +8,279,000 +(64,576,000 +) +13,221,000 +State income taxes +1,370,000 +(7,033,000 +) +2,131,000 +Other differences +(891,000 +) +(527,000 +) +528,000 +Changes in valuation allowance +(8,730,000 +) +72,136,000 +(15,759,000 +) +Income tax expense recorded +$ +28,000 +$ +— +$ +121,000 +F-25 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +The tax effects of temporary differences and net operating loss +carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2009, 2008 and 2007 are estimated as follows: +2009 +2008 +2007 +Deferred tax assets: +Net operating loss carryforward +$ +22,268,000 +$ +23,810,000 +$ +37,197,000 +Oil and gas property basis difference +49,638,000 +57,789,000 +— +FASB ASC 718 compensation expense +341,000 +238,000 +216,000 +Investment in pass through entities +528,000 +— +72,000 +AMT credit +598,000 +718,000 +64,000 +Non-oil and gas property basis difference +316,000 +118,000 +148,000 +Total deferred tax assets +73,689,000 +82,673,000 +37,697,000 +Deferred tax liabilities: +Oil and gas property basis difference +— +— +27,947,000 +Investment in pass through entities +— +134,000 +— +Unrealized gain on hedging activities +— +— +— +Total deferred tax liabilities +— +134,000 +27,947,000 +Total deferred tax asset +73,689,000 +82,539,000 +9,750,000 +Valuation allowance +(73,156,000 +) +(81,886,000 +) +(9,750,000 +) +Net deferred tax asset (liability) +$ +533,000 +$ +653,000 +$ +— +The Company has an available tax net operating loss carryforward estimated at approximately $55,671,000 as +of December 31, 2009. This carryforward will begin to expire in the year 2018. A valuation allowance has been provided at December 31, 2009, 2008 and 2007 because it is management’s belief, based upon the Company’s past history +of no taxable income and future projections of no taxable income during the carryforward period, it is more likely than not the net deferred tax assets will not be realized. +The Company had income tax expense of $121,000 during the year ended December 31, 2007 related to the payment of alternative minimum +taxes due for 2006 and 2007. Although the Company has substantial net operating loss carryforwards, these cannot be used to offset alternative minimum tax liabilities. In 2009, the Company had income tax expense of $28,000 related to state income +tax. +13. +EARNINGS PER SHARE +A +reconciliation of the components of basic and diluted net income per common share is presented in the table below: +2009 +2008 +2007 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per +Share +Basic: +Net income (loss) +$ +23,627,000 +42,667,581 +$ +0.55 +$ +(184,502,000 +) +42,599,611 +$ +(4.33 +) +$ +37,775,000 +36,774,163 +$ +1.03 +Effect of dilutive securities: +Stock options and awards +— +350,067 +— +— +— +676,935 +Diluted: +Net income +$ +23,627,000 +43,017,648 +$ +0.55 +$ +(184,502,000 +) +42,599,611 +$ +(4.33 +) +$ +37,775,000 +37,451,098 +$ +1.01 +F-26 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +For the year ended December 31, 2009, options to purchase +64,889 shares at $9.07 per share and 200,000 shares at $11.20 per share were excluded from the calculation of dilutive earnings per share because they were anti-dilutive. For the year ended December 31, 2008, all options were excluded from the +calculation of dilutive earnings per share because the Company had a net loss and, therefore, the effect would have been anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive for the year ended +December 31, 2007. +14. +HEDGING ACTIVITIES +Oil Price Hedging +Activities +The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant +and often volatile fluctuation, by entering into forward sales contracts. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating cash flows and earnings +when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. +The Company accounts for its oil derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related +pronouncements. All derivative contracts are marked to market each quarter end and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. +At December 31, 2009, the fair value of derivative liabilities related to the forward sales contracts is as follows: +Short-term derivative instruments – liability +$ +18,735,000 +All forward +sales contracts have been executed in connection with the Company’s oil price hedging program. For forward sales contracts qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract price is included in oil sales in the +period for which the underlying production was hedged. +For derivatives designated as cash flow hedges and meeting the +effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative +changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company did not recognize into earnings any amount related to +hedge ineffectiveness for the year ended December 31, 2009 as the hedges were deemed to be perfectly effective. +During +the first quarter of 2009, the Company entered into forward sales contracts with the purchaser of the Company’s WCBB oil. The Company receives the fixed price amount stated in the contract for the specified volumes. At December 31, 2009, +the Company had the following forward sales contracts in place: +Daily Volume +(Bbls/day) +Weighted +Average Price +January – February 2010 +3,000 +$ +54.81 +March – December 2010 +2,300 +$ +58.24 +F-27 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +In the first quarter of 2009, the Company terminated forward +sales contracts for 3,000 barrels per day of March 2009 production for approximately $1.5 million and terminated forward sales contracts for 3,000 barrels per day in the second quarter of 2009 for $476,000. For the year ended December 31, 2009, +approximately $2.0 million related to such terminations is included in oil and condensate sales on the accompanying consolidated statements of operations. There were no contracts in place which were accounted for as hedges at December 31, 2008. +The Company delivered approximately 49% of its 2009 production under these forward sales contracts. +15. +FAIR VALUE MEASUREMENTS +The Company adopted FASB ASC 820 for all financial assets and liabilities measured at fair value on a recurring basis. The Company adopted FASB ASC 820 effective January 1, 2009 for all non-financial assets and liabilities. FASB ASC +820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable +inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and disclosed in one of the following categories: +Level 1 – Quoted prices in active markets for identical assets and liabilities. +Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in +markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. +Level 3 – Significant inputs to the valuation model are unobservable. +Financial assets and liabilities are +classified based on the lowest level of input that is significant to the fair value measurement. +The following table +summarizes the Company’s financial and nonfinancial liabilities by FASB ASC 820 valuation level as of December 31, 2009: +Level 1 +Level 2 +Level 3 +Assets: +Forward sales contracts +$ +— +$ +— +$ +— +Liabilities: +Forward sales contracts +$ +— +$ +18,735,000 +$ +— +The +estimated fair value of the Company’s forward sales contracts was based upon forward commodity prices based on quoted market prices, adjusted for differentials. +The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”). The +initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of +the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset +retirement obligations incurred during the twelve months ended December 31, 2009 were approximately $361,000. +F-28 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +The carrying amounts on the accompanying consolidated balance +sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current and long-term debt are carried at cost, which approximates market value. +16. +OPERATING LEASES +In +October 2006, the Company began leasing the Louisiana building that it owns to an unrelated party. The cost of the building totaled approximately $217,000 and accumulated depreciation amounted to approximately $90,000 as of December 31, 2009. +The lease commenced on October 15, 2006 and was extended to expire on October 14, 2010, with equal monthly installments of $10,500. The future minimum lease payments to be received are as follows: +Fiscal year ending December 31, 2010 +$ +100,000 +17. +RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business activities with certain entities affiliated with its largest stockholder. +Windsor Energy Group, LLC (“WEG”), an entity controlled by Wexford, operates the Permian Basin wells in West Texas. At December 31, 2009 and 2008, the Company owed WEG approximately +$1,631,000 and $3,724,000, respectively, related to reimbursement for services provided. Approximately $2,368,000 and $2,711,000 of services provided by WEG are included in lease operating expenses in the consolidated statements of operations for +the years ended December 31, 2009 and 2008, respectively. Approximately $8,063,000 and $37,693,000 related to services performed by WEG is included in oil and natural gas properties on the accompanying consolidated balance sheets at +December 31, 2009 and 2008, respectively. +Athena Construction LLC (“Athena”), an entity controlled by Wexford, +performs services for the Company at its WCBB and Hackberry fields. At December 31, 2009 and December 31, 2008, the Company owed Athena approximately $836,000 and $759,000, respectively, related to these services. Approximately $709,000 +and $1,303,000 of services provided by Athena are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2009 and 2008, respectively. Approximately $1,286,000 and $1,783,000 related to +services performed by Athena are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2009 and 2008, respectively. +Packers & Service Tools, Inc. (“Packers”), an entity controlled by Wexford, performs services for the Company at its WCBB +and Hackberry fields. At December 31, 2008 the Company owed Packers approximately $465,000 related to these services. Approximately $11,000 of services provided by Packers are included in lease operating expenses in the consolidated statements +of operations for the year ended December 31, 2008. Approximately $1,995,000 relating to services performed by Packers are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2008. +Packers ceased to be controlled by Wexford in November 2008. +Diamondback Completions LLC (“Completions”), an entity +controlled by Wexford, performed services for the Company at its WCBB and Hackberry fields. At December 31, 2008, the Company owed Completions +F-29 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +approximately $24,000, related to these services. Approximately $227,000 relating to services performed by Completions are included in oil and natural gas properties on the accompanying +consolidated balance sheets at December 31, 2008. Completions ceased to be controlled by Wexford in November 2008. +Great +White Towing LLC (“Towing”), an entity controlled by Wexford, performed services for the Company at its WCBB field. At December 31, 2008, the Company owed Towing approximately $222,000, related to these services. No amounts were owed +to Towing at December 31, 2009. Approximately $102,000 of services performed by Towing are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2008. Approximately $339,000 +relating to services performed by Towing are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2008. No services were performed by Towing in 2009. +Great White Directional Services LLC (“Directional”), an entity controlled by Wexford, performs services for the Company at its +WCBB and Hackberry fields. At December 31, 2009, the Company owed Directional approximately $699,000 related to these services. No amounts were owed to Directional at December 31, 2008. Approximately $1,064,000 relating to services +performed by Directional are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2009. No services were performed by Directional in 2008. +18. +COMMITMENTS +Plugging and Abandonment +Funds +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed +the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. +Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company can access the trust for use in plugging and abandonment charges associated with +the property. As of December 31, 2009, the plugging and abandonment trust totaled approximately $3,136,000. At December 31, 2009, the Company has plugged 273 wells at WCBB since it began its plugging program in 1997, which management +believes fulfills its current minimum plugging obligation. +Texaco Global Settlement +Pursuant to the terms of a global settlement between Texaco and the State of Louisiana which includes the State Lease No. 50 portion of +Gulfport’s East Hackberry field, Gulfport was obligated to commence drilling a well or other qualifying development operation on certain non-producing acreage in the field prior to March 1998. Because of prevailing market conditions during +1998, the Company believed it was commercially impractical to shoot seismic or commence drilling operations on the subject property. As a result, Gulfport agreed to surrender approximately 440 non-producing acres in this field to the State of +Louisiana. At December 31, 2009, Gulfport was in the process of releasing these properties to the State of Louisiana. +Contributions +to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 15% +of their total compensation through salary deferrals. Also under these plans, the Company will make a +F-30 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals. During the years ended +December 31, 2009, 2008 and 2007, Gulfport incurred $279,000, $651,000 and $640,000, respectively, in contributions expense related to this plan. +Employment Agreement +In May 1999, Gulfport entered into an employment agreement with its Chairman of the +Board. The original term of the agreement expired on May 31, 2004, but automatically renews for successive terms of one year unless Gulfport or the Chairman elects otherwise. The employment agreement calls for an annual salary of $200,000, +subject to adjustment for cost of living increases. +19. +CONTINGENCIES +The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 to 2007. The LDR maintains that +Gulfport paid approximately $1,800,000 less in severance taxes under fixed price terms than the severance taxes Gulfport would have had to pay had it paid severance taxes on the oil at the contracted market rates only. Gulfport has denied any +liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. +Gulfport has maintained its right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against Gulfport seeking $2,275,729 in severance taxes, plus +interest and court costs. Gulfport filed a response denying any liability to the LDR for underpayment of severance taxes and is defending itself in the lawsuit. The case is in the early stages of discovery. +Other Litigation +In +November 2006, Cudd Pressure Control, Inc. (“Cudd”) filed a lawsuit against Gulfport, Great White Pressure Control LLC (“Great White”) and six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit +was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White’s employment of the former Cudd +employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007. Gulfport filed a motion for +summary judgment on October 5, 2007. The court entered a final interlocutory judgment in favor of all defendants, including Gulfport, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the +Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, +and Cudd filed a motion to remand the case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition with the state court (a) alleging that Gulfport conspired with the other defendants to +misappropriate, and misappropriated, Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking unspecified monetary damages. On February 10, 2010, Gulfport filed a motion to be dismissed from the +proceeding for lack of personal jurisdiction, which motion is pending. This state court proceeding is in its initial stages. +On July 27, 2007, Robotti & Company, LLC filed a putative class action lawsuit in the Court of Chancery for the State of Delaware. The original complaint alleged a breach of fiduciary duty by Gulfport and its then +F-31 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +present directors in connection with the pricing of Gulfport’s 2004 rights offering. Plaintiff filed an amended complaint on January 15, 2008, and Gulfport filed a motion to dismiss in +early February 2008 and filed the brief in support of such motion on April 29, 2008. The court held a hearing on October 3, 2008, ultimately deciding to allow the plaintiff to file a second amended complaint. Plaintiff filed its second +amended complaint December 22, 2008, which sets forth class action and derivative claim allegations that Gulfport’s then present directors breached their fiduciary duty in connection with the pricing of the 2004 rights offering. The +defendants filed their motion to dismiss on January 19, 2009 and their brief in support of such motion on February 20, 2009. Briefing by the parties concluded April 6, 2009, oral arguments on the motion were heard by the court on +April 22, 2009 and on January 14, 2010, the court issued an opinion granting defendants’ motion to dismiss and entered an order dismissing the case with prejudice. +Due to the current early stages of the LDR and Cudd litigation, the outcome is uncertain and management cannot determine the amount of loss, +if any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations. +The Company has been named as a defendant on various other litigation matters. The ultimate resolution of these matters is not expected to +have a material adverse effect on the Company’s financial condition or results of operations for the periods presented in the consolidated financial statements. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry +principally in the state of Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their +specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long +term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit +Insurance Corporation up to $250,000. At December 31, 2009, Gulfport held cash in excess of insured limits in these banks totaling $1,147,000. +During the year ended December 31, 2009, Gulfport sold approximately 92% and 7% of its oil production to Shell Trading Company (“Shell”) and WEG, respectively, 100% of its natural gas +liquids production to WEG, and 45%, 38%, and 16% of its natural gas production to WEG, Chevron, and Hilcorp Energy Company (“Hilcorp”), respectively. During the year ended December 31, 2008, Gulfport sold approximately 87% and 11% of +its oil production to Shell and WEG, respectively, 100% of its natural gas liquids production to WEG, and 60%, 22%, and 16% of its natural gas production to Chevron, WEG, and Hilcorp, respectively. During the year ended December 31, 2007, +approximately 99% of Gulfport’s oil sales and 69% and 23% of Gulfport’s natural gas sales were attributable to three purchasers: Shell, Chevron, and Hilcorp, respectively. +Forward Sales Contracts +The Company was a party to forward sales contracts +for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, the Company entered into forward +sales contracts for the sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation +F-32 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +costs. In addition, the Company entered into forward sales contracts for the sale of 3,500 barrels of production per day for the months of January 2008 through May 2008 at a weighted average +daily price of $70.29 per barrel before transportation costs. For June 2008, the Company had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of +July 2008, the Company had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $85.89 per barrel before transportation costs. For August 2008, Gulfport had agreements to sell 3,500 barrels of production per +day at a weighted average daily price of $86.81 per barrel before transportation costs. For the periods September 2008 through December 2008, the Company entered into forward sales contracts for the sale of 3,500 barrels of production per day at a +weighted average daily price of $86.60 per barrel before transportation costs. For the period of January 2009 through December 2009, the Company entered into agreements to sell 3,000 barrels of production per day at a weighted average daily price of +$89.06 per barrel before transportation costs. These contracts were originally designated as normal sales of production under FASB ASC 815, based on the Company’s intent to physically deliver the production quantities under the contract terms, +and exempted from the provisions of FASB ASC 815. +In December 2008, the Company terminated the 2009 forward sales contracts +in exchange for $39.0 million cash, which is included in other (income) expense on the accompanying consolidated statements of operations. As a result of this cash settlement, beginning in 2009, the Company is required to account for similar +contracts under the provisions of FASB ASC 815 until a reasonable period passes and the Company redevelops a past history of physical delivery under fixed price contracts without net cash settlement. See Note 14 for further discussion of the +Company’s 2009 forward sales contracts. +20. +LITIGATION TRUST ENTITY +Pursuant to the Company’s 1997 plan of reorganization, all of Gulfport’s possible causes of action against third parties (with the exception of certain litigation related to recovery of marine and rig equipment assets and claims +against Tri-Deck), existing as of the effective date of that plan, were transferred into a “Litigation Trust” controlled by an independent party for the benefit of most of the Company’s existing unsecured creditors. The litigation +related to recovery of marine and rig equipment and the Tri-Deck claims were subsequently transferred to the Litigation Trust as described below. +The Litigation Trust was funded by a $3,000,000 cash payment from the Company, which was made on the effective date of reorganization. Gulfport owns a 12% interest in the Litigation Trust with the other +88% being owned by the former general unsecured creditors of Gulfport. For financial statement reporting purposes, Gulfport has not recognized the potential value of recoveries which may ultimately be obtained, if any, as a result of the actions of +the Litigation Trust, treating the entire $3,000,000 payment as a reorganization cost at the time of Gulfport’s reorganization. +On January 20, 1998, Gulfport and the Litigation Trust entered into a Clarification Agreement whereby the rights to pursue various claims reserved by Gulfport under the plan of reorganization were assigned to the Litigation Trust. In +connection with this agreement, the Litigation Trust agreed to reimburse the Company $100,000 for legal fees Gulfport had incurred in connection with these claims. As additional consideration for the contribution of this claim to the Litigation +Trust, Gulfport is entitled to 20% to 80% of the net proceeds from these claims. +In December 2009, the Company received a +final distribution from the Litigation Trust of approximately $234,000. No proceeds were received from the Litigation Trust for the years ended December 31, 2008 or 2007. +F-33 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +21. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES +The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United +States: +Capitalized Costs Related to Oil and Gas Producing Activities +2009 +2008 +Proven properties +$ +610,778,000 +$ +577,218,000 +Unproven properties +15,192,000 +20,368,000 +625,970,000 +597,586,000 +Accumulated depreciation, depletion, amortization and impairment reserve +(470,649,000 +) +(441,709,000 +) +Net capitalized costs +$ +155,321,000 +$ +155,877,000 +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +2009 +2008 +2007 +Acquisition +$ +1,885,000 +$ +2,468,000 +$ +85,247,000 +Development of proved undeveloped properties +28,652,000 +64,643,000 +55,930,000 +Exploratory +502,000 +9,764,000 +57,668,000 +Recompletions +8,980,000 +16,877,000 +9,875,000 +Capitalized asset retirement obligation +361,000 +934,000 +500,000 +Total +$ +40,380,000 +$ +94,686,000 +$ +209,220,000 +Equity investment in Windsor Bakken LLC +$ +— +$ +— +$ +2,297,000 +F-34 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is +calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude +general office overhead and interest expense attributable to oil and gas production. +2009 +2008 +2007 +Revenues +$ +85,576,000 +$ +141,650,000 +$ +106,163,000 +Production costs +(26,113,000 +) +(38,669,000 +) +(29,337,000 +) +Impairment of oil and gas assets +— +(272,722,000 +) +— +Depletion +(28,939,000 +) +(42,194,000 +) +(29,220,000 +) +30,524,000 +(211,935,000 +) +47,606,000 +Income tax expense +Current +28,000 +— +121,000 +Deferred +— +— +— +28,000 +— +121,000 +Results of operations from producing activities +$ +30,496,000 +$ +(211,935,000 +) +$ +47,485,000 +Depletion per barrel of oil equivalent (BOE) +$ +17.25 +$ +23.92 +$ +17.85 +Net earnings from equity method investment in Winsor Bakken LLC +$ +— +$ +— +$ +20,000 +Oil and Gas Reserves (Unaudited) +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three +years. The 2009 reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2009, in +accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009. Estimates of reserves as of year-end 2008 and 2007 were prepared using constant prices and costs in accordance with previous guidelines of the SEC +based on hydrocarbon prices received on a field-by-field basis as of December 31st of the applicable year. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The prices +used for 2009 reserve report purposes are $57.90 per barrel and $3.87 per MMbtu, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices at December 31, 2008 and 2007 +used for reserve report purposes are $41.00 per barrel and $5.71 per MMbtu and $92.50 per barrel and $6.80 per MMbtu, respectively. +F-35 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Gulfport emphasizes that the volumes of reserves shown below are +estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or +downward, as warranted by additional performance data. +2009 +2008 +2007 +Oil +Gas +Oil +Gas +Oil +Gas +Proved Reserves +Beginning of the period +21,771 +22,235 +25,115 +24,259 +19,692 +20,801 +Purchases in oil and gas reserves in place +1,728 +1,135 +77 +26 +5,699 +5,587 +Extensions and discoveries +2,614 +2,874 +1,315 +1,965 +— +— +Sales of oil and gas reserves in place +(736 +) +(282 +) +— +— +— +— +Revisions of prior reserve estimates +(6,294 +) +(11,139 +) +(3,091 +) +(3,303 +) +1,225 +(1,313 +) +Current production +(1,595 +) +(491 +) +(1,645 +) +(712 +) +(1,501 +) +(816 +) +End of period +17,488 +14,332 +21,771 +22,235 +25,115 +24,259 +Proved developed reserves +6,165 +4,325 +7,072 +7,187 +7,116 +6,746 +Equity Investment in Windsor Bakken LLC +Net proved developed and undeveloped reserves +— +— +— +— +77 +26 +Net proved developed reserves +— +— +— +— +18 +8 +The +Company experienced downward reserve revisions in estimated proved reserves in 2009. These downward revisions were primarily the result of implementing the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of +Oil and Gas Reporting” Final Rule. The Company experienced downward reserve revisions in estimated proved reserves in 2008. These downward revisions were primarily a result of year end commodity prices utilized for the reserve estimate +decreasing from $92.50 per barrel and $6.80 per MMbtu at December 31, 2007 to $41.00 per barrel and $5.71 per MMbtu at December 31, 2008. +Discounted Future Net Cash Flows (Unaudited) +The following tables present the estimated future cash flows, and +changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2009, 2008 and 2007 using an unweighted average first-of-the-month price for the period January through December 2009 for 2009 and the applicable year end +price for 2008 and 2007. +F-36 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +Standardized Measure of Discounted Future Net Cash Flows Relating to Proved +Oil and Gas Reserves (Unaudited) +Year ended December 31, +2009 +2008 +2007 +Future cash flows +$ +1,005,029,000 +$ +1,023,056,000 +$ +2,405,458,000 +Future development and abandonment costs +(209,975,000 +) +(299,362,000 +) +(326,229,000 +) +Future production costs +(236,003,000 +) +(376,176,000 +) +(420,646,000 +) +Future production taxes +(97,841,000 +) +(109,478,000 +) +(275,977,000 +) +Future income taxes +(50,229,000 +) +— +(280,538,000 +) +Future net cash flows +410,981,000 +238,040,000 +1,102,068,000 +10% discount to reflect timing of cash flows +(170,207,000 +) +(111,800,000 +) +(433,773,000 +) +Standardized measure of discounted future net cash flows +$ +240,774,000 +$ +126,240,000 +$ +668,295,000 +Equity investment in Windsor Bakken Standardized measure of discounted cash flows +$ +— +$ +— +$ +1,753,000 +In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers +in Gulfport’s reserve report, the Company will need to spend $47,845,000, $28,015,000 and $38,678,000 during years 2010, 2011 and 2012, respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2009 +2008 +2007 +Sales and transfers of oil and gas produced, net of production costs +$ +(59,463,000 +) +$ +(102,981,000 +) +$ +(76,826,000 +) +Net changes in prices, production costs, and development costs +183,426,000 +(662,004,000 +) +246,657,000 +Acquisition of oil and gas reserves in place +20,981,000 +376,000 +121,267,000 +Extensions and discoveries +32,638,000 +7,801,000 +— +Revisions of previous quantity estimates, less related production costs +(77,531,000 +) +(13,480,000 +) +27,970,000 +Sales of reserves in place +(13,185,000 +) +— +— +Accretion of discount +12,624,000 +66,830,000 +35,265,000 +Net changes in income taxes +(22,238,000 +) +152,949,000 +(106,145,000 +) +Change in production rates and other +37,282,000 +8,454,000 +67,459,000 +Total change in standardized measure of discounted future net cash flows +$ +114,534,000 +$ +(542,055,000 +) +$ +315,647,000 +F-37 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2009, 2008 AND 2007 +(Amounts rounded to nearest thousand) +22. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The following table summarizes quarterly financial data for the years ended December 31, 2009 and 2008: +2009 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +17,784,000 +$ +20,514,000 +$ +22,071,000 +$ +24,893,000 +Income from operations +2,214,000 +5,410,000 +7,130,000 +9,596,000 +Income tax expense +— +28,000 +— +— +Net income +2,733,000 +5,078,000 +6,674,000 +9,142,000 +Income per share: +Basic +$ +0.06 +$ +0.12 +$ +0.16 +$ +0.21 +Diluted +$ +0.06 +$ +0.12 +$ +0.16 +$ +0.21 +2008 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter (1) +Revenues +$ +31,118,000 +$ +35,802,000 +$ +36,731,000 +$ +37,566,000 +Income from operations +12,660,000 +14,969,000 +15,119,000 +(262,797,000 +) +Income tax expense +— +— +20,000 +(20,000 +) +Net income +11,506,000 +14,886,000 +14,107,000 +(225,001,000 +) +Income per share: +Basic +$ +0.27 +$ +0.35 +$ +0.33 +$ +(5.28 +) +Diluted +$ +0.27 +$ +0.35 +$ +0.33 +$ +(5.28 +) +(1) +Includes $272,772,000 impairment of oil and gas properties and income of $39,000,000 from the settlement of fixed price contracts. +F-38 +Table of Contents +Index to Financial Statements +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor +Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party +seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the +SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, +2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the +Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with +the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a +Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other +Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, +certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +E-1 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.5 +of Amendment No. 1 to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5 +Amended and Restated Credit Agreement, dated as of December 31, 2009, among the Company, each lender from time to time party thereto and Bank of America, N.A., as +administrative agent (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 6, 2010). +10.6 +Continuing Guaranty, dated as of December 31, 2009, made by Grizzly Holdings, Inc., Jaguar Resources LLC and Gator Marine, Inc. (incorporated by reference to Exhibit 10.2 of +Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 6, 2010). +10.7 +Amended and Restated Revolving Note, dated December 31, 2009, issued by the Company under the Restated Credit Agreement (incorporated by reference to Exhibit 10.3 of Form +8-K, File No. 000-19514, filed by the Company with the SEC on January 6, 2010). +10.8 +Term Note, dated December 31, 2009, issued by the Company under the Restated Credit Agreement (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 000-19514, +filed by the Company with the SEC on January 6, 2010). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of +Chapter 63 of Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of +Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Pinnacle Energy Services, LLC. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +E-2 \ No newline at end of file diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/filing_metadata.csv b/raw/filings/0000874499/2009/0001193125-10-055121/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..5d1245e012064e2850b9ffc07c60511714288558 --- /dev/null +++ b/raw/filings/0000874499/2009/0001193125-10-055121/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2010-03-12,2009-12-31,2010-03-12T19:12:40.000Z,0001193125-10-055121,d10k.htm,FORM 10-K,1405114,0,0,https://www.sec.gov/Archives/edgar/data/874499/000119312510055121/d10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000119312510055121/,2009,2009,1 diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/item1.txt b/raw/filings/0000874499/2009/0001193125-10-055121/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..69979d921880455b8d62b2b91f001cafcb5a551a --- /dev/null +++ b/raw/filings/0000874499/2009/0001193125-10-055121/item1.txt @@ -0,0 +1,508 @@ +ITEM 1. +DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located +along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil +Sands ULC, or Grizzly, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2009, at our WCBB field, we recompleted 56 wells and drilled 11 wells for a total cost of approximately $19.6 million as of +December 31, 2009. Of our 11 new wells drilled at WCBB in 2009, 10 were completed as producing wells and one was non-productive. During 2010, we currently anticipate drilling 20 wells and recompleting 40 wells at our WCBB field for an estimated +aggregate cost of $33.0 to $36.0 million. In December 2009, production at WCBB was 116,637 net barrels of oil equivalent, or BOE, or an average of 3,762 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From +January 1, 2010 through February 28, 2010, our average net daily production at WCBB was 3,432 BOE, 98% of which was from oil and 2% of which was from natural gas. +In 2009, at our East Hackberry field, we recompleted five wells and drilled six wells for a total cost of approximately $11.0 million as of +December 31, 2009. All wells drilled during 2009 were completed as producing wells. During 2010, we currently anticipate drilling three wells and recompleting five wells for an aggregate estimated cost of $6.0 to $7.0 million. In December 2009, +net production at East Hackberry was 13,284 BOE, or an average of 429 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production at East +Hackberry was 814 BOE, 96% of which was from oil and 4% of which was from natural gas. +In December 2009, net production at +West Hackberry was 1,202 BOE, or an average of 39 BOE per day, 100% of which was from oil. From January 1, 2010 through February 28, 2010, our average net daily production at West Hackberry was 44 BOE, 100% of which was from oil. +Effective November 1, 2007, we acquired approximately 4,100 net acres in West Texas in the Permian Basin with production +at the time of acquisition from 32 gross wells, predominately from the Wolfcamp formation. In 2008, 31 gross (15.5 net) wells were drilled on this acreage. In 2009, we acquired an additional 4,095 net acres, bringing our total net acreage position +in the Permian Basin to approximately 8,200 net acres. During the year ended December 31, 2009, we drilled four gross wells and recompleted three gross wells on this acreage. As of March 1, 2010, three of the four wells had been completed +and the other well was awaiting completion. We currently anticipate drilling 24 to 26 gross (12 to 13 net) wells on this acreage in 2010 for an estimated aggregate cost of $15.0 to $17.0 million. In December 2009, net production from our Permian +acreage was 17,030 BOE, or an average of 549 BOE per day, 82% of which was from oil and natural gas liquids and 18% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net production from our +Permian acreage was 507 BOE per day, 82% of which was from oil and natural gas liquids and 18% of which was from natural gas. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, +Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our total net investment in Grizzly was +approximately $41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one +water supply test well, tested five +2 +Table of Contents +Index to Financial Statements +separate lease blocks and conducted a seismic program. Grizzly recently filed an application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and +its currently contemplated 2010 activities relate primarily to initial preparations for this facility. +During 2005, we +purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford Capital, LP, or Wexford. Affiliates of Wexford beneficially own approximately 36% of our +outstanding common stock. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its +ownership of concessions covering three million acres which includes the Phu Horm Field. +We also own a 17.9% ownership +interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering one million acres. During 2009, the operator conducted a +3-D seismic survey on this concession. During 2010, we expect to participate in the drilling of two wells. +During 2005, we +purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. In 2006, Bakken acquired leases for undeveloped acreage in the Williston Basin area of western North Dakota and eastern Montana. Effective January 1, 2008, we acquired a +direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an +effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for $5.8 million with an effective date of July 1, 2009. As of December 31, 2009, we held approximately 900 net acres and +interests in 28 wells, as well as certain wells that might be drilled in the future. +In December 2009, net production from +our remaining Bakken acreage was 2,092 BOE, or an average of 67 BOE per day, 97% of which was from oil and natural gas liquids and 3% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net +production from our Bakken acreage was 66 BOE per day, 95% of which was from oil and 5% of which was from natural gas. +As of +December 31, 2009, we had 19.9 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $263 million and associated standardized +measure of discounted future net cash flows of approximately $240.8 million. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our +standardized measure of discounted future net cash flows to PV-10. +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2009 reflecting our net interest in our principal producing oil and +natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas and in the Williston Basin. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay Field (4) +80.108/100 +95 +95 +181 +181 +5,668 +5,668 +262 +5,028 +5,290 +E. Hackberry Field (5) +79.424/100 +18 +18 +86 +86 +3,291 +3,291 +308 +2,490 +2,798 +W. Hackberry Field +87.5/100 +3 +3 +24 +24 +592 +592 +— +172 +172 +Permian Basin +38.075/49.48 +64 +32 +— +— +8,157 +4,078 +1,816 +9,763 +11,579 +Williston Basin (6) +3.08/4.10 +4 +1 +— +— +2,560 +127 +2 +32 +34 +Overrides/Royalty Non-operated +Various +32 +1 +17 +2 +— +— +1 +3 +4 +Total +216 +150 +308 +293 +20,268 +13,756 +2,389 +17,488 +19,877 +3 +Table of Contents +Index to Financial Statements +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes nine gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 68% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. +We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in +depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 +based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in +the field. Of the 919 wells drilled as of December 31, 2009, 826 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through +December 31, 2009, we drilled 139 new wells, 16 of which were non-productive, for an 88% success rate. As of December 31, 2009, estimated field cumulative gross production was 190.1 MMBOE and 236.1 billion cubic feet, or Bcf, of gas. Of +the 919 wells drilled in WCBB as of December 31, 2009, 86 were producing, 181 were shut-in, nine were producing intermittently and five were being used as salt water disposal wells. The other 638 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In +1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the +data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected +deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large +graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs +recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 919 wellbores that had been drilled in the field as of December 31, 2009, over 4,000 potential zones have been penetrated. +These sands are highly porous and permeable reservoirs primarily with a strong water drive. +4 +Table of Contents +Index to Financial Statements +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, +or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of +these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does +introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new +wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets +are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2009 included 21 PUD wells. The drilling schedule used in the reserve report anticipates that +all of those wells will be drilled by 2012. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, six natural gas compressors, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2009, we recompleted 56 wells and drilled 11 wells at WCBB. Of these 11 new wells, 10 were completed as producers, and one was non-productive. As of February 28, 2010, we had recompleted eight wells during 2010. Of the 11 wells +drilled in 2009, none were considered deep wells. The ten productive wells, with total depths ranging from 2,500 to 10,325 feet, have approximately 1,077 feet of aggregate apparent net pay. We currently anticipate drilling 20 wells and recompleting +40 wells at WCBB during 2010. +Production Status +In December 2009, production at WCBB was 116,637 net BOE, or an average of 3,762 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2010 through +February 28, 2010, our average net daily production at WCBB was 3,432 BOE, 98% of which was from oil and 2% of which was from natural gas. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately +79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 7,738 acres, including the Erwin Heirs Block, which is located on land, and the adjacent +State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive +shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2009 was over +597,172 barrels of oil and 330 Bcf of casinghead gas production. A total of 193 wells have been drilled on our portion of the field. As of December 31, 2009, 18 wells had daily production, 86 were shut-in and two had been converted to salt +water disposal wells. The remaining 87 wells had been plugged and abandoned. +5 +Table of Contents +Index to Financial Statements +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry +acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. +These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we +completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure +natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at +this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2009 at East Hackberry, we recompleted five wells and +drilled four land wells and two wells on water. All of the six wells drilled during 2009 were completed as producing wells. As of February 28, 2010, we had not recompleted or drilled any wells during 2010. We currently intend to drill three +land wells and recomplete five wells at East Hackberry during 2010. +Production Status +In December 2009, net production at East Hackberry was 13,284 BOE, or an average of 429 BOE per day, 96% of which was from oil and 4% of +which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production at East Hackberry was 814 BOE, 96% of which was from oil and 4% of which was from natural gas. Production has increased as a +result of the successful drilling and completion of four wells during the fourth quarter of 2009. +West Hackberry Field +Location and Land +The West +Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) +in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves. +Area History +The first +discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2009 was 261 MBOE and 140 Bcf +of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and +abandoned. +6 +Table of Contents +Index to Financial Statements +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in +the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In +December 2009, net production at West Hackberry was 1,202 BOE, or 39 BOE per day. From January 1, 2010 through February 28, 2010, our average net daily production at West Hackberry was 44 BOE and was 100% oil. +Facilities +We have +land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, effective date as of +November 1, 2007, from ExL Petroleum, LP and certain other sellers. Subsequently, we acquired an additional 4,095 net acres, bringing our total acreage position to approximately 8,200 net acres as of December 31, 2009. The Permian Basin +area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy is +the operator of this field. +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found +in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the +greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp +formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian +wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private +company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to +participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2009, we hold interests in 64 gross producing wells. +Geology +The +Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is +characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +7 +Table of Contents +Index to Financial Statements +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% +from the Spraberry section. Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2009, proved reserves net to our interest in these assets were approximately 11.6 million BOE, of +which 12% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 191 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry +formations, which are generally characterized as long-lived, with predictable production profiles. +Production Status +In December 2009, net production from the Permian field was 17,030 BOE, or an average of 549 BOE per day, 82% of which was from oil and +natural gas liquids, and 18% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net production from our Permian acreage was 507 BOE per day, 82% of which was from oil and natural gas liquids +and 18% of which was from natural gas. As a result of the reduction of drilling, fracing and recompletion activities, production has decreased since year end due to normal production declines. +Facilities +There are +typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2009, four gross (two net) wells were drilled in our Permian acreage. We have identified 191 gross future development drilling locations. We currently expect an estimated 24 to 26 gross (12 to 13 net) wells to be drilled on our acreage +in 2010. The wells are expected to be drilled to approximately 10,200 feet. +Bakken +Location and Land +The +Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities +controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective +January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for +approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2009, we held +approximately 900 net acres and interests in 28 wells, as well as interests in certain wells that might be drilled in the future. +Production Status +In December 2009, net production from our Bakken acreage was 2,092 BOE, or an average of 67 +BOE per day, 97% of which was from oil and natural gas liquids and 3% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production from this acreage was 66 BOE, of which 95% was from oil +and 5% was from natural gas liquids. +8 +Table of Contents +Index to Financial Statements +Facilities +There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping +units. +Recent and future activities +As a result of the sale transactions described above, we have no activities currently scheduled for 2010 in the Williston Basin. +Additional Properties +Louisiana . In addition to our interests in +the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +1 +6 +Bayou Pigeon +Iberia +6.250 +% +0 +% +4 +5 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +6 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +1 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . During +2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 +outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +During the year ended December 31, 2009 we paid $320,000 in cash calls and received $517,000 in distributions, bringing our total investment in Tatex (including previous investments) to $2.5 million. Our investment is accounted for on the +equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately +60 million cubic feet per day. For December 2009, net gas production was approximately 83 MMcf per day and condensate production was 452 Bbl’s per day. Hess Corporation operates the field with a 35% interest. Other interest owners include +APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2008, +net to our interest, are 2.739 BCF of gas. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve +information. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, +at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2009, we paid $428,000 in cash calls, bringing our total investment in Tatex III to $4,482,000. Currently, we plan to participate in the +drilling of two wells during 2010. +Grizzly Oil Sands . During the third quarter of 2006, we, through our wholly-owned +subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the +9 +Table of Contents +Index to Financial Statements +Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our total net investment in Grizzly was approximately +$41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one water supply +test well, tested five separate lease blocks and conducted a seismic program. Grizzly recently filed an application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and its currently contemplated +2010 activities relate primarily to initial preparations for the facility. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these +companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to +take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control +of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the +effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are +located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB, other than the production sold under forward sales contracts, is being +sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $3.45 per barrel for +transportation. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor Energy Group, Chevron and +Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and 16% of our natural gas production to +Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. During 2007, we sold 99% of our oil production to Shell and 69% and 23% of our natural gas production to Chevron and Hilcorp, respectively. We may not continue to have ready +access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely +volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil +and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000 +barrels of WCBB production at a weighted average price of $55.01 per barrel before transportation costs. We delivered approximately 49% of our 2009 production under these agreements. Initially, for the period January through December 2009, we had +entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0 +million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August +2009. We also entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs, for the period September +10 +Table of Contents +Index to Financial Statements +2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and May 2009 for an aggregate of approximately $2.0 million. For the period January 2010 through +February 2010 we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs. For the period March 2010 through December 2010, we +have entered into forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before transportation costs. Under these contracts, we have committed to deliver approximately +45% of our estimated 2010 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit +the benefit to us of increases in the price of oil. These forward sales contacts are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements. +Regulation +Regulation of +Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation +and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties +for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, West Texas and the Williston Basin. These states regulate the production and sale of oil +and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and +natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development +and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental +Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws +and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production +activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former +operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict liability nature of such laws and regulations +could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup +requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and +regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated +thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and +11 +Table of Contents +Index to Financial Statements +cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more +stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that +are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes +or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous +wastes.” +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling +requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations +require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas +exploration and production wastes could increase our costs to manage and dispose of such wastes. +Comprehensive +Environmental Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without +regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated +facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to +strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for +neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, +would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such +“hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of +1972, as amended, also known as the Clean Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and +other gas and oil wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws and regulations +also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits +for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all +permits required under the Clean Water Act. Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. +Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants +through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required +to obtain permits before work can begin, permits may be required for our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of +compliance for some facilities we own or +12 +Table of Contents +Index to Financial Statements +operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act +and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or +renewing permits has the potential to delay the development of oil and natural gas projects. Our air emissions may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are +emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including, but not limited to, +blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury or death to persons and +wildlife. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental +damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully insured against could have a +material adverse effect on our financial position. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a +portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of +finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At +December 31, 2009, we had 40 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the +estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2009 and 2008, expenses reimbursed +to us under these arrangements were $0.6 million and $1.4 million, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate +the WCBB and the Hackberry fields. +Available Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange +Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange +Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other +filing that we make with the SEC. +13 +Table of Contents +Index to Financial Statements \ No newline at end of file diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/item13.txt b/raw/filings/0000874499/2009/0001193125-10-055121/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..16d76ff4775b98f113b4feef5f91a1d0f038df30 --- /dev/null +++ b/raw/filings/0000874499/2009/0001193125-10-055121/item13.txt @@ -0,0 +1,5 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive +proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not +incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/item9a.txt b/raw/filings/0000874499/2009/0001193125-10-055121/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..9f4f75f9cb7d0e7f5256eaf94c0462682492308a --- /dev/null +++ b/raw/filings/0000874499/2009/0001193125-10-055121/item9a.txt @@ -0,0 +1,67 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure +that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The +disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely +decisions regarding required disclosures. +As of December 31, 2009, an evaluation was performed under the supervision and +with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under +the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2009, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over +financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +51 +Table of Contents +Index to Financial Statements +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is +also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to +provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the +effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting +financial information. +Management conducted an evaluation of the effectiveness of our internal control over financial +reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—Integrated +Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2009. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended +December 31, 2009 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2009, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +52 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport +Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the +“Company”) as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The +Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s +Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material +weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting +includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with +authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material +effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control +over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as +of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2009 and our report +dated March 12, 2010 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 12, 2010 \ No newline at end of file diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/rp_note.txt b/raw/filings/0000874499/2009/0001193125-10-055121/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2009/0001193125-10-055121/rpt_disclosure.txt b/raw/filings/0000874499/2009/0001193125-10-055121/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ec164539a84407552b5abd7fee8f04e4e34f1311 --- /dev/null +++ b/raw/filings/0000874499/2009/0001193125-10-055121/rpt_disclosure.txt @@ -0,0 +1,81 @@ +Certain Relationships and Related Transactions +Administrative Services Agreements +We are a party to an administrative service agreement with Great White Energy Services LLC, which we refer to as Great White, which agreement was entered +into effective as of July 22, 2006. Under this agreement, our services include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. +This administrative service agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. This administrative +service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of +receipt of written notice of such breach. Great White reimbursed us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing services for such entity. We +were reimbursed approximately $61,000 by Great White for services provided under this agreement during the year ended December 31, 2009. Great White is controlled by Wexford Capital LP. Charles Davidson, who beneficially owned approximately 36% +of our outstanding common stock as of April 1, 2010, is the Chairman and Chief Investment Officer of Wexford Capital LP. +We are also a +party to administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Grizzly Oil Sands ULC, which we refer to as Grizzly, and Everest Operations Management LLC, which we refer to as Everest, which agreements were +each entered into effective March 1, 2008. Under these agreements, our services include professional and technical support. Under our agreements with Stampede Farms and Everest, we also provide office space. The services provided under these +agreements and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a two-year term, and upon expiration of that term such agreement will continue on a month-to-month basis +until cancelled by either party to such agreement with at least 60 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to us and +(2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We were reimbursed approximately $0, $20,000 and $508,000 by Stampede Farms, Grizzly and +Everest, respectively, for services provided under these agreements during the year ended December 31, 2009. We were also reimbursed approximately $2,000 and $1,000 by Stampede Farms and Everest, respectively, for office space under these +agreements for the year ended December 31, 2009. Each of Stampede Farms, Grizzly and Everest is controlled by Wexford Capital LP. +Effective July 1, 2008, we entered into an acquisition team agreement with Everest to identify and evaluate potential oil and gas properties in +which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, the party whose acquisition team +identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or +divestiture consideration. The agreement has a one year term unless earlier terminated by either party upon 30 days notice. +From time to +time, two of our petroleum engineers provide services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to Tatex Thailand II, LLC, or Tatex II, and Tatex Thailand +III LLC, or Tatex III. Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities. Each of Tatex II and Tatex III is +controlled by Wexford Capital LP. +Services Provided to Us by Our Affiliates +We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge services in our West Cote Blanche Bay, or WCBB, and Hackberry +fields located along the Louisiana Gulf Coast. For the year +30 +Table of Contents +ended December 31, 2009, we paid Athena $1,918,000 and owed an additional $836,000 for such services at that date. Athena is controlled by Wexford Capital LP. +Windsor Energy Group operates our Permian Basin wells in West Texas. For the year ended December 31, 2009, we paid Windsor Energy Group $7,158,000 +and owed an additional $1,631,000 for such services at that date. Windsor Energy Group is controlled by Wexford Capital LP. +Effective +March 1, 2008, Everest provides tax planning, preparation of supporting tax schedules and consultation services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of the parties. Everest +is controlled by Wexford Capital LP. +Caliber Development Company, LLC, or Caliber, provides building maintenance services for our +headquarters in Oklahoma City, Oklahoma. For the year ended December 31, 2009, we paid Caliber $17,000 and owed an additional $0 at that date. Caliber is an entity controlled by Wexford Capital LP. +Our Investments in Affiliates and Related Agreements +During 2005, we purchased a 23.5% ownership interest in Tatex II at a cost of $2,400,000. The remaining interests in Tatex II are owned by other entities +controlled by Wexford Capital LP. Tatex II, a privately-owned entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia +through its ownership of concessions covering three million acres which includes the Phu Horm Field. During 2009, we paid $320,000 in cash calls and received $517,000 in distributions in respect of our investment in Tatex II. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. In December 2009, we purchased an additional +approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by other entities and individuals +affiliated with Wexford Capital LP. During 2009, we paid $428,000 in cash calls in respect of our investment in Tatex III. +During 2005, we +purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken, with the remaining interests in Bakken owned by other entities controlled by Wexford Capital LP. In 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin +areas of western North Dakota and eastern Montana, which we refer to as the contract area. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During 2009, +we sold approximately 18,000 net acres in the Bakken Shale and approximately 190 net BOEPD of production for approximately $18.8 million. +Effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor Dakota LLC, or Windsor Dakota, to jointly +acquire oil and gas leases on certain lands located in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each party must offer the other party the right to +participate in such acquisition in proportion to its participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in +proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy Group, L.L.C., as the operator, also entered into an +exploration agreement, effective as of January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and Windsor Energy Group, L.L.C. agreed to act as the operator +under the terms of a joint operating agreement. In the event Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport as the operator. The parties agreed to pay Windsor +Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. +31 +Table of Contents +During the third quarter of 2006, we purchased, through our wholly owned subsidiary Grizzly Holdings, Inc., +a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for approximately $8,200,000. The remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LP. During 2006 and 2007, Grizzly acquired leases in +the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and, at December 31, 2009, our net investment in Grizzly was approximately +$41,000,000, including a note receivable of $15,900,000 as discussed in the following paragraph. +We, through our wholly owned subsidiary +Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow funds from us. Borrowed funds bear interest at LIBOR plus 4%. Interest is paid on a paid-in-kind basis by increasing the +outstanding balance of the loan. The loan matures on December 31, 2012. We loaned Grizzly approximately $4,377,000 during the year ended December 31, 2009. The Company recognized interest income of approximately $547,000 for the year ended +December 31, 2009 under this loan agreement. The note balance was increased by approximately $1,843,000 as a result of a currency translation gain for the year ended December 31, 2009. +Option and Purchase Agreement and Related Agreements +On November 30, 2007, we entered into an option agreement with Windsor Permian LLC, an entity controlled by Wexford Capital LLC, which we refer to as +Windsor Permian. Under the option agreement, we were granted the right to participate on a 50/50 basis with Windsor Permian in the acquisition of certain strategic assets in Upton County, Texas in the Permian Basin. On December 12, 2007, we +exercised the option and on December 18, 2007, the purchase agreement was amended to, among other things, add Gulfport as a buyer under the purchase agreement. On December 20, 2007, the acquisition was closed, effective as of +November 1, 2007. We and Windsor Permian also agreed to share equally all third-party costs and expenses incurred by each of us in connection with the transaction. +In addition, effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly acquire oil and +gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and +expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. +In connection +with the area of mutual interest agreement, we, Windsor Permian and Windsor Energy Group, L.L.C., as the operator, entered into the joint development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed +to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy Group, L.L.C. agreed to act as the operator under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either +party has greater than a 50% interest in a prospect, as defined in the development agreement, the majority party may designate the operator of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with +respect to the contract area as provided in the joint operating agreement. +32 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/filing.txt b/raw/filings/0000874499/2010/0001193125-11-065894/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..0453f345a69b403946c1e9e54c9423a3f9dcfcaa --- /dev/null +++ b/raw/filings/0000874499/2010/0001193125-11-065894/filing.txt @@ -0,0 +1,5845 @@ +10-K +1 +d10k.htm +FORM 10-K +Form 10-K +Table of Contents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +x +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2010 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission File Number: 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant as Specified in +Its Charter) +Delaware +73-1521290 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip code) +(405) +848-8807 +(Registrant’s Telephone Number, Including Area Code) +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities +Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the +Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 +days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such +files). Yes ¨ No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of +registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller +reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): +Large Accelerated +filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange +Act). Yes ¨ No x +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, +2010, based on the closing price of the common stock on the NASDAQ Global Select Market on June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter ($11.86 per share) was $338,894,403. +As of March 1, 2011, 44,670,930 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy Corporation’s Proxy Statement for the 2011 Annual Meeting of Stockholders are incorporated by reference in Items 9, 10, 11, 12 and 13 of Part III of this Form 10-K. +Table of Contents +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +DESCRIPTION OF BUSINESS +2 +ITEM 1A. +RISK FACTORS +17 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +29 +ITEM 2. +PROPERTIES +29 +ITEM 3. +LEGAL PROCEEDINGS +36 +ITEM 4. +RESERVED +37 +PART II +38 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +38 +ITEM 6. +SELECTED FINANCIAL DATA +39 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +41 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +56 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +57 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL +DISCLOSURE +57 +ITEM 9A. +CONTROLS AND PROCEDURES +57 +ITEM 9B. +OTHER INFORMATION +59 +PART III +60 +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +60 +ITEM 11. +EXECUTIVE COMPENSATION +60 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER +MATTERS +60 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +60 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +60 +PART IV +61 +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +61 +Signatures +S-1 +Index to Consolidated Financial Statements +F-1 +Exhibit Index +E-1 +i +Table of Contents +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the +Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and +uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed +or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” +“plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. +All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net +revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our +business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions +reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and +uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees +of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking +statements due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements +speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all +forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +PART I +ITEM 1. +DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties +located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. In 2010, we acquired an acreage position in the Niobrara Formation of Western Colorado. We also hold a +significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to +achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2010, at our WCBB field, we +recompleted 72 wells and drilled 23 wells for a total cost of approximately $40.9 million as of December 31, 2010. All 23 new wells drilled at WCBB in 2010 were completed as producing wells. During 2011, we currently anticipate drilling 20 to +24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $36.0 to $38.0 million. In the fourth quarter of 2010, production at WCBB was 293,372 net barrels of oil equivalent, or BOE, or an average of 3,189 BOE per day, +97% of which was from oil and 3% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average net daily production at WCBB was 2,721 BOE, 97% of which was from oil and 3% of which was from natural gas. +In 2010, at our East Hackberry field, we recompleted ten wells and drilled eight wells for a total cost of approximately +$20.0 million as of December 31, 2010. All wells drilled during 2010 were completed as producing wells. During 2011, we currently anticipate drilling seven to ten wells and recompleting five wells for an aggregate estimated cost of $24.0 to +$26.0 million. In the fourth quarter of 2010, net production at East Hackberry was 157,349 BOE, or an average of 1,710 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2011 through February 28, +2011, our average net daily production at East Hackberry was 1,899 BOE, 93% of which was from oil and 7% of which was from natural gas. +In the fourth quarter of 2010, net production at West Hackberry was 3,121 BOE, or an average of 34 BOE per day, 100% of which was from oil. From January 1, 2011 through February 28, 2011, our +average net daily production at West Hackberry was 35 BOE, 100% of which was from oil. +In 2007, we acquired approximately +4,100 net acres in West Texas in the Permian Basin with production at the time of acquisition from 32 gross (16 net) wells, predominately from the Wolfcamp formation. Subsequently, we acquired approximately 10,600 additional net acres, which brought +our total net acreage position in the Permian Basin to approximately 14,700 net acres. During the year ended December 31, 2010, 25 gross (11 net) wells were drilled and four gross (two net) wells were recompleted on this acreage. As of +March 1, 2011, 24 of the 25 wells had been completed and one well was awaiting completion. We currently anticipate that 40 to 42 gross (19 to 20 net) wells will be drilled and ten gross (five net) wells will be recompleted on this acreage in +2011 for an estimated aggregate net cost of $37.0 to $39.0 million. In the fourth quarter of 2010, net production from our Permian acreage was 72,791 BOE, or an average of 791 BOE per day, 84% of which was from oil and natural gas liquids and 16% of +which was from natural gas. From January 1, 2011 through February 28, 2011, our average daily net production from our Permian acreage was 787 BOE, 87% of which was from oil and natural gas liquids and 13% of which was from natural gas. +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Colorado and held leases for +19,172 net acres as of March 1, 2011. During the year ended December 31, 2010, we recompleted one gross (0.4 net) well on this acreage. In the fourth quarter of 2010, net production at Niobrara was 3,380 BOE, or an average of 37 BOE per day, +100% of which was from oil. From January 1, 2011 through February 28, 2011, our average net daily production at Niobrara was 36 BOE, 100% of which was from oil. We are in the process of permitting a 60 square mile 3-D seismic survey and +expect to begin shooting in mid-2011. +2 +Table of Contents +As of December 31, 2010, we held approximately 900 net acres in the Williston Basin of +western North Dakota and eastern Montana with interests in five wells and an overriding royalty interest in wells drilled prior to our sale, wells drilled subsequent to our sale and wells that might be drilled in the future. In the fourth quarter of +2010, our net production from this acreage was 6,522 BOE, or an average of 71 BOE per day, 95% of which was from oil and natural gas liquids and 5% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average +daily net production from our Bakken acreage was 64 BOE, 93% of which was from oil and 7% of which was from natural gas. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. +The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LP, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of +other existing oil sands projects. Grizzly has approximately 534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly +has drilled an aggregate of 199 core holes and three water supply test wells, tested nine separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application in Alberta, Canada for the development of an 11,300 barrel +per day oil sand SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first production. Grizzly recently received the supplemental information request, +or SIR, pertaining to its Algar Lake project application from the Alberta regulatory agencies. This is the standard process by which the Alberta regulatory agencies request additional information on all oil sands project applications. The SIR was +received in a timeframe consistent with anticipated timeline for project approval. The engineering and procurement contract for Grizzly’s proposed steam assisted gravity drainage, or SAGD, facility at Algar Lake has been awarded to SNC-Lavin. +Work on the detailed engineering design is underway out of Grizzly’s Calgary office and the detailed design of the project is expected to be complete by April 2011. Grizzly’s currently contemplated 2011 activities include the completion of +the 2010/2011 core hole drilling activity, seismic program and the initial preparations for the Algar Lake SAGD facility. +We +own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or +APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. +We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in +Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. During 2010, Tatex completed a 3-D seismic survey on this concession. The first well drilled on our concession in 2010 +was temporarily abandoned pending further scientific evaluation. A second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and +carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. Tatex III is currently in the process of completing the well. +As of December 31, 2010, we had 22.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of +estimated future net revenues, discounted at 10%, or PV-10, of approximately $392.6 million and associated standardized measure of discounted future net cash flows of approximately $315.5 million. See Item 2. “Properties—Proved Oil +and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +3 +Table of Contents +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2010 reflecting our net interest in our principal producing oil +and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in western Colorado and in the Williston Basin in western North Dakota and eastern Montana. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay Field (4) +80.108/100 +93 +93 +179 +179 +5,668 +5,668 +386 +4,133 +4,519 +E. Hackberry Field (5) +79.424/100 +27 +27 +74 +74 +3,291 +3,291 +291 +2,561 +2,852 +W. Hackberry Field +87.5/100 +3 +3 +22 +22 +592 +592 +— +146 +146 +Permian Basin +37.38/49.05 +82 +40 +— +— +15,888 +7,124 +1,988 +12,465 +14,453 +Niobrara Formation +36.4/44.04 +4 +2 +1 +0.4 +2,240 +628 +23 +339 +362 +Williston Basin (6) +3.2/3.9 +5 +0.2 +— +— +2,560 +127 +5 +58 +63 +Overrides/Royalty Non-operated +Various +77 +0.2 +2 +— +— +— +— +2 +2 +Total +291 +165.4 +278 +275.4 +30,239 +17,430 +2,693 +19,704 +22,397 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes nine gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten +feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in +depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the +remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 973 wells drilled as of December 31, 2010, 880 were completed as producing wells. As a result, the +field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2010, we drilled 162 new wells, 146 of which were productive, for a 90% success rate. As of December 31, +2010, estimated field cumulative gross production was 191.3 MMBOE and 236.4 billion cubic feet, or Bcf, of gas. Of the 973 wells drilled in WCBB as of December 31, 2010, 84 were producing, 179 were shut-in, nine were producing intermittently +and five were being used as salt water disposal wells. The other 696 wells have been plugged and abandoned. +4 +Table of Contents +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per +mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical +staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced +seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The +relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension +over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct +sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 973 wells that had been drilled in the field as of December 31, 2010, over 4,000 potential zones have +been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a +structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a +structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The +tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, +in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort +to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2010 included +29 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2013. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas +compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2010, we recompleted 72 gross and net wells and drilled 23 gross and net wells at WCBB. All 23 new wells were completed +as producers. As of March 11, 2011, we had drilled two wells and recompleted twelve wells during 2011. Of the 23 wells drilled in 2010, 17 were considered deep wells. The 23 productive wells, with total depths ranging from 1,800 to 9,560 feet, +have approximately 2,063 feet of aggregate apparent net pay. We currently anticipate drilling 20 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2011. +Production Status +In the fourth quarter of 2010, production at WCBB was +293,372 net BOE, or an average of 3,189 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average net daily production at WCBB was 2,721 BOE, 97% of which was +from oil and +5 +Table of Contents +3% of which was from natural gas. The decrease in production was due to operating inefficiencies with wells, machinery and equipment resulting from the sub-freezing weather conditions during +January and February 2011 in Southern Louisiana. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along +the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry +field. We hold beneficial interests in approximately 4,870 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We also hold +2,868 net acres subject to a two-year exploration agreement we entered into with an active gulf coast operator. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have +licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and are reprocessing the data. +Area History and +Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a +gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and +condensate production through 2010 was over 1,015 MBOE and 330 Bcf of casinghead gas production. A total of 201 wells have been drilled on our portion of the field. As of December 31, 2010, 27 wells had daily production, 74 were shut-in and two +had been converted to salt water disposal wells. The remaining 98 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and +west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply +dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a +field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a +per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 +square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D seismic data to +identify additional drilling locations. During 2010 at East Hackberry, we recompleted ten gross and net wells and drilled six gross and net land wells and two gross and net wells on water. All of the eight wells drilled during 2010 were completed as +producing wells. As of March 11, 2011, we had recompleted three wells during 2011, drilled one well and were in the process of drilling two additional wells. We currently intend to drill seven to ten gross and net wells and recomplete five +gross and net wells at East Hackberry during 2011. +6 +Table of Contents +Production Status +In the fourth quarter of 2010, net production at East Hackberry was 157,349 BOE, or an average of 1,710 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, +2011 through February 28, 2011, our average net daily production at East Hackberry was 1,899 BOE, 93% of which was from oil and 7% of which was from natural gas. The increase in production in 2011 is a result of our 2011 drilling activities. +West Hackberry Field +Location and Land +The +West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% +NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves. +Area History +The first +discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2010 was 274 MBOE and 140 Bcf +of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 22 are shut-in and one has been converted to a saltwater disposal well. The remaining ten wells have been plugged and +abandoned. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in +the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In +the fourth quarter of 2010, net production at West Hackberry was 3,121 BOE, or an average of 34 BOE per day. From January 1, 2011 through February 28, 2011, our average net daily production at West Hackberry was 35 BOE and was 100% oil. +Facilities +We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both +the East and West Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres and 32 gross +(16 net) producing wells in West Texas (near Midland) in the Permian Basin effective November 1, 2007. Subsequently, we acquired 10,600 additional net acres, which brought our total net acreage position in the Permian Basin to approximately +14,700 net acres as of December 31, 2010. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian +Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy LLC, an entity controlled by Wexford, is the operator of this field. +7 +Table of Contents +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found +in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the +greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp +formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian +wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private +company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to +participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2010, we held interests in 82 gross (40 net) producing wells. +Geology +The +Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is +characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. +Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2010, proved reserves net to our interest in these assets were approximately 14.5 million BOE, of which 16% were classified as +proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 226 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally +characterized as long-lived, with predictable production profiles. +Production Status +In the fourth quarter of 2010, net production from the Permian field was 72,791 BOE, or an average of 791 BOE per day, 84% of which was +from oil and natural gas liquids, and 16% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average daily net production from our Permian acreage was 787 BOE, 87% of which was from oil and natural gas +liquids and 13% of which was from natural gas. The slight production decrease was the result of the unusual sub-freezing weather conditions during January and February 2011. +Facilities +There are typical land oil and gas processing facilities in the +Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2010, 25 gross (11 net) wells were drilled in our Permian acreage. As of March 11, 2011, four gross (two net) wells had been recompleted and five gross (2.5 net wells) have been drilled +on this acreage, three of which were waiting on completion and two were currently drilling. We have identified 226 gross future development drilling locations. We currently expect an estimated 40 to 42 gross (19 to 20 net) wells to be drilled +on our acreage in 2011. The wells are expected to be drilled to approximately 10,200 feet. +8 +Table of Contents +Niobrara Formation (Western Colorado) +Location and Land +Effective as of April 1, 2010, we acquired +leasehold interests in the Niobrara Formation in western Colorado, and held leases for 19,172 acres as of March 1, 2011. We are the operator on the acreage. +Area History +The Niobrara Formation is a shale oil rock formation located +in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 – 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as +another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of the earliest production +dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and +limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature. +Geology +The Niobrara +Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured +marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and +fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. The producing intervals are geologically equivalent +to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play. +Production +Status +In the fourth quarter of 2010, net production from our Niobrara acreage was 3,380 BOE, or an average of 37 BOE per +day, 100% of which was from oil. From January 1, 2011 through February 28, 2011, our average daily net production from our Niobrara acreage was 36 BOE, 100% of which was from oil. +Facilities +There are typical land oil and gas processing facilities in the +Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +We recompleted one well at Niobrara during +2010. We are in the process of permitting a 60 square mile 3-D seismic survey over our Craig Dome prospect and expect to begin shooting in mid-2011. We currently intend to drill four to five gross wells at Niobrara during 2011. +9 +Table of Contents +Bakken +Location and Land +The Bakken Shale is located in the Williston Basin areas +of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired +leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest +in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. +During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2010, we held approximately 900 net acres, interests in five wells and an overriding +royalty interest in wells drilled prior to our sale, wells drilled subsequent to our sale and wells that might be drilled in the future. +Production Status +In +the fourth quarter of 2010, net production from our Bakken acreage was 6,522 BOE, or an average of 71 BOE per day, 95% of which was from oil and natural gas liquids and 5% of which was from natural gas. From January 1, 2011 through +February 28, 2011, our average net daily production from this acreage was 64 BOE, of which 93% was from oil and 7% was from natural gas. +Facilities +There are +typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and future activities +One gross well was drilled on our acreage in 2010. We have no activities currently scheduled for 2011 in the Williston Basin. +Additional Properties +Louisiana . In addition to our interests in +the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +1 +2 +Bayou Pigeon +Iberia +6.250 +% +0 +% +0 +0 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +0 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +0 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . +During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the +1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes +the Phu Horm Field. During +10 +Table of Contents +the year ended December 31, 2010, we received $565,000 in distributions, reducing our total investment in Tatex to $1.9 million. Our investment is accounted for on the equity method. Tatex +accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet +per day. For December 2010, net gas production was approximately 98 MMcf per day and condensate production was 477 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP +(20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is +accounted for by the cost method, these reserves are not included in our year-end reserve information. +During the first +quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million +bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. Tatex III +recently completed a 3-D seismic survey on this concession. During the year ended December 31, 2010, we paid $402,000 in cash calls, bringing our total investment in Tatex III to $4.7 million. The first well drilled on our concession in 2010 +was temporarily abandoned pending further scientific evaluation. A second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried +a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. Tatex III is currently in the process of completing the well. +Grizzly Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are +owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles from other existing oil sands projects. Grizzly has approximately +534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly has drilled an aggregate of 199 core holes and three water +supply test wells, tested nine separate lease blocks and conducted a seismic program. In connection with its 2010/2011 winter drilling program, Grizzly plans to drill a total of 71 core hole locations, 68 of which have been drilled to date. Upon the +completion of the 2010/2011 drilling season, Grizzly will have drilled 32 locations at Thickwood Hills, 14 locations at Firebag River, 17 locations at Algar Lake, and eight total locations at Athabasca Rapids and Horse River. In March 2010, Grizzly +filed an application in Alberta, Canada for the development of an 11,300 barrel per day SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first +production. Grizzly recently received the supplemental information request, or SIR, pertaining to its Algar Lake project application from the Alberta regulatory agencies. This is the standard process by which the Alberta regulatory agencies request +additional information on all oil sands project applications. The SIR was received in a timeframe consistent with anticipated timeline for project approval. The engineering and procurement contract for Grizzly’s proposed steam assisted gravity +drainage facility at Algar Lake has been awarded to SNC-Lavin. Work on the detailed engineering design is underway out of Grizzly’s Calgary office and the detailed design of the project is expected to be complete by April 2011. Grizzly’s +currently contemplated 2011 activities include the completion of the 2010/2011 core hole drilling activity and the initial preparations for the Algar Lake SAGD facility. +Competition and Markets +The oil and natural gas industry is intensely +competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products +on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to +11 +Table of Contents +withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government +regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond +the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and +equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our +wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB, other than the production sold under forward sales contracts, +is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $2.70 per +barrel for transportation. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 50%, 32%, and 10% of our natural gas production to Windsor Energy Group, +Chevron and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to +Windsor Energy Group, Chevron and Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and +16% of our natural gas production to Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price +at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the +factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the +effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the +period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel +before transportation costs and differentials. We delivered approximately 45% of our 2010 production under these agreements. +In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel, +before transportation costs and differentials, for the period January 2011 through December 2011. Under the 2011 contracts, we have committed to deliver approximately 30% to 33% of our estimated 2011 production. Such arrangements may expose us to +risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contacts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value +pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation +affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our +cost of doing business and, consequently, affects our profitability. +12 +Table of Contents +We own interests in a number of producing oil and natural gas properties located along the +Louisiana Gulf Coast, West Texas and the Niobrara Formation. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new +fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production +allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the +discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly +compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, +restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying +within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or +revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The +strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly +pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that +we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and +regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and +non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, +development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste +provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future +regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations +could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal +penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, +registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any +legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state +laws, generally +13 +Table of Contents +imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a +“hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or +arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or +remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health +studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our +operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of +the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The +Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the +unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance +with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure, or SPCC, plan requirements under federal law require appropriate containment terms and similar structures to help prevent the contamination of +navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also +adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or +developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for +discharges or operations that may impact groundwater conditions. +The Oil Pollution Act, or OPA, is the primary federal law +for oil spill liability. OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore +facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects +owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well +as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. +Air +Emissions . The Federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and +continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations, +and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose +administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air +emissions regulations +14 +Table of Contents +and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas +projects. Our operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to +environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to +property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our +properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third +party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is +no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced +production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and +cash flows. +Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million +which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore West Cote Blanche Bay properties, we also have a $25.0 million property physical damage +policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $10.0 million for damages arising as a result of a named windstorm. In the event +of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $500,000 per occurrence ($1.5 million in the case of a +named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for +our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be +given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by +new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial +condition and results of operations. +At the depths and in the areas in which we operate, and in light of the vertical and +directional drilling that we undertake, we typically do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for two specific +wells we are drilling this year. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and +subcontractors hired by the service provider. +We have prepared and have in place spill prevention control and countermeasure +plans for each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and +15 +Table of Contents +updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround +drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters. This emergency +response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. It reports that it currently owns over 164 response vehicles, 65 +response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage barge sets, allowing for storage of up to 248 barrels of recovered oil +each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for the retainer and clean up services during 2009 and 2010 were +approximately $139,000. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the future, if and when needed, could be hindered or delayed +in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure at our WCBB field, we believe other companies would be +available to us in the event our primary remediation company was unable to perform. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease +a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of +finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At +December 31, 2010, we had 45 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the +estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2009 and 2008, expenses reimbursed +to us under these arrangements were $0.6 million and $1.4 million, respectively, and are reflected as a reduction in our general and administrative expenses. No amounts were reimbursed to us under these arrangements in 2010. A Louisiana well +servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. +Available Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those +reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is +electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on +Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +16 +Table of Contents +ITEM 1A. +RISK FACTORS +Risks Related to Our +Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas +properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety +of additional factors that are beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +• +weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +political instability or armed conflict in oil and natural gas producing regions; and +• +the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the +West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per +million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. On March 7, 2011, the West Texas Intermediate posted price for crude oil was $105.44 per bbl and the Henry Hub spot market price of +natural gas was $3.93 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas +reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +Declining general economic, +business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition. +Concerns over global economic conditions, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States +have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased +unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the +17 +Table of Contents +economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish, which could impact the price at which we can sell our oil, +natural gas and natural gas liquids, affect our vendors, suppliers and customers ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition. +Our success depends on finding, developing or acquiring additional reserves. +Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically +recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves +and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations +for the development, production, exploration and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank +and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the level of oil and natural gas we are able to produce from existing wells; +• +the prices at which oil and natural gas are sold; and +• +our ability to acquire, locate and produce new reserves. +We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and natural gas reserves, our exploratory projects or other replacement +activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices +increase significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and +integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense +competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our +ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and +difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with +regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such +additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to +effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may +fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +Our +Canadian oil sands project is a complex undertaking and may not be completed at our estimated cost or at all. +During the +third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by +18 +Table of Contents +Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has +approximately 534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly has drilled an aggregate of 199 core holes and +three water supply test wells, tested nine separate lease blocks and conducted a seismic program and expects to drill an additional three core locations during the remainder of the 2010/2011 winter delineation drilling season. In 2010, Grizzly filed +applications in Alberta, Canada for the development of an 11,300 barrel per day oil sand SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first +production. The cost of this initial facility is currently estimated to be approximately $120.0 million. This is a complex project and financing has not been secured. This project may not be completed at our estimated cost or at all. +Shortage of rigs, equipment, raw materials, supplies or personnel may restrict our operations. +The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand +and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in the number of +active rigs in service. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, raw materials +(particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracing and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our +financial condition and results of operations. +We rely on a few key employees whose absence or loss could disrupt our operations resulting +in a loss of revenues. +Many key responsibilities within our business have been assigned to a small number of employees. +The loss of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists could disrupt our operations +resulting in a loss of revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Liddell’s written employment agreement and Mr. Palm’s oral employment agreement, and our executives are not +restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key +person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees. +Our proved reserves and related PV-10 as of December 31, 2010 have been reported under SEC rules that went into effect on January 1, 2010. The estimates provided in accordance with these SEC +rules may change materially as a result of interpretive guidance that may be released by the SEC. +We have included in this +report certain estimates of our proved reserves and related PV-10 at December 31, 2010 as prepared consistent with our and our independent reserve engineers’ interpretations of the SEC rules relating to disclosures of estimated natural gas +and oil reserves. These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing. The SEC has released only +limited interpretive guidance regarding reporting of reserve estimates under these rules. Accordingly, while the estimates of our proved reserves and related PV-10 at December 31, 2010 included in this report have been prepared based on what we +and our independent reserve engineers believe to be reasonable interpretations of the SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance. +19 +Table of Contents +We may be limited in our ability to book additional proved undeveloped reserves under the recent SEC +rules. +One of the impacts of the recent SEC reserve rules is a general requirement that, subject to limited exceptions, +proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling +program. +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production. +There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and +timing of expenditures. The reserve information included in this report represents only estimates based on reports as of December 31, 2010 prepared by Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB and +Niobrara fields, by Pinnacle Energy Services, LLC, or Pinnacle, with respect to our assets in the Permian Basin in West Texas and by our personnel with respect to our Hackberry fields and our overriding royalty and non-operated interests. Petroleum +engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily +depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by +governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual +results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net +cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such +variances may be material. +Estimates of reserves as of year-end 2010 and 2009 were prepared using an +average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2010 and 2009, respectively, in accordance with the +revised guidelines of the SEC applicable to reserves estimates for such years. Estimates of reserves as of year-end 2008 were prepared using constant prices and costs in accordance with previous guidelines of the SEC based on hydrocarbon prices +received on a field-by-field basis as of December 31 st +of such year. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates +represent our net revenue interest in our properties. +The present value of future net revenues from our proved reserves is +not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2010 and 2009 on average price equal to the unweighted average of +prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2010 and 2009, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such +years. Estimated discounted future net revenue from reserves as of year-end 2008 were prepared using constant prices and costs in accordance with previous guidelines of the SEC as of December 31st of such year. However, actual future net +revenues from our oil and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from +proved +20 +Table of Contents +reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based +on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. +As +of December 31, 2010, approximately 63% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that +we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources and the indicated level of reserves or recovery of bitumen may not be realized. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or +recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve +and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may +vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable +bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. +Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric +calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same +reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to +assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly’s lands cannot be determined +at this time. +The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other +facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced. +The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we +do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact +our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field, which is our largest field. +In October 2006, for example, a natural gas line in this field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, +we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or +encounter compression or other production related difficulties, we will be required to again shut in or curtail production from the field. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural +gas produced from the field, would adversely affect our financial condition and results of operations. +21 +Table of Contents +A substantial portion of our producing properties is located in Louisiana, making us vulnerable to risks +associated with operating in this region. +Our largest field by production, WCBB, is located approximately five miles off +the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions such as fog +or rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates +we consider reasonable or that any particular types of coverage will be available. +Our identified drilling locations, which are part of +our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified over 600 drilling locations on our Louisiana, West Texas and Colorado properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and +develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the +numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ +from those presently identified, which could adversely affect our business. +Operating hazards and uninsured risks may result in +substantial losses. +Our operations are subject to all of the hazards and operating risks associated with drilling for and +production of oil and natural gas, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any +of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory +investigation and penalties and suspension of operations. For example, in October 2006, an accident occurred north of our production facilities in the WCBB field in southern Louisiana involving two contracted vessels that were performing work on our +behalf in the field. A tugboat and two barges laden with construction materials ruptured an underwater natural gas pipeline and a subsequent fire damaged the vessels. Four confirmed fatalities resulted from the accident. Several lawsuits relating to +this incident were filed against us, among other parties. These lawsuits against us have all been settled. +In accordance with +what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no +longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide +certain types of insurance coverage in the Gulf Coast region. We may not be able to secure additional insurance of bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely +impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. +Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive. +Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time +to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and +taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells +22 +Table of Contents +below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, +by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health +and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations and injunctions limiting or prohibiting some or all of our +operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and +regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. +Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating +restrictions or delays. +Hydraulic fracturing is an important and common practice that is used to +stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate +production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act’s +Underground Injection Program. While the EPA has yet to take any action enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has +commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation +of hydraulic fracturing practices. In addition, legislation was proposed in the recently ended 111 th session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and such legislation could be introduced in the +current session of Congress. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclose of chemicals used in the +hydraulic fracturing process. On March 1, 2011 a bill was introduced in the Texas Senate that would require the Railroad Commission of Texas to adopt rules requiring owners and operators of wells on which hydraulic fracturing activities been +performed or other persons who had performed such activities to provide the agency written information on, among other things, the chemicals used in such activities. If new laws or regulations that significantly restrict hydraulic fracturing are +adopted, such laws could make it more difficult or costly for us to drill and produce from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if +hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and +recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the +consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or +state legislation governing hydraulic fracturing is enacted into law. +The recent adoption of derivatives legislation by the U.S. Congress +could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. +The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative +instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other +provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was +23 +Table of Contents +signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new +legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are +their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation +may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at +this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The +new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative +contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. +If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect our ability to +plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related +to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial +position, results of operations or cash flows. +The proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our +business, financial condition, results of operations and cash flows. +The U.S. President’s Fiscal Year 2012 Budget +Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, +(ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, and (iii) implementing certain international tax reforms. These proposed changes in the U.S. tax +laws, if adopted, could adversely affect our business, financial condition, results of operations and cash flows. +The adoption of climate +change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce. +Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a +primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not +participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in +Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA determined that emissions +of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These +findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related +rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the +motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule in May 2010, and it also became +24 +Table of Contents +effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of +GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. More recently, in November 2010, the +EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage, and distribution facilities, which may include certain of our facilities, beginning in 2012 +for emissions occurring in 2011. +In June 2009, the U.S. House of Representatives passed the American Clean Energy and +Security (ACES) Act that, among other things, would have established a cap-and-trade system to regulate greenhouse gas emissions and would have required an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. +The ACES Act did not pass the Senate, however, and so was not enacted by the 111th Congress. The United States Congress is likely to again consider a climate change bill in the future. Moreover, almost half of the states have already taken legal +measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as +electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is +reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Restrictions on emissions of methane or +carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements our operations are not adversely impacted by +existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions that +could adversely impact our operations and financial condition, including the: +• +issuance of administrative, civil and criminal penalties; +• +denial, suspension or revocation of necessary permits, licenses or other authorizations; +• +imposition of injunctive obligations or limitations on our operations; +• +requirement for additional pollution controls; and +• +required performance of site investigatory, remedial or other corrective actions. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense +hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some +areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at +this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +We face extensive competition in our industry. +The oil and natural gas +industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market +petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural +gas prices and production, the availability of alternative energy sources and the application of government regulation. +25 +Table of Contents +We depend upon two customers for the sale of most of our oil and natural gas production. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our +management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil +and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell +Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB, other than the production sold under forward sales contracts, is being sold in accordance with the Shell posted price for +West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI differential less $2.70 per barrel for transportation. During 2010, we sold 75% and 19% of our oil production to +Shell and Windsor Energy Group, LLC, or Windsor, respectively and 50%, 32%, and 10% of our natural gas production to Windsor, Chevron and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and +Windsor, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor, Chevron and Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor, 100% of our natural gas liquids +production to Windsor, and 60%, 22%, and 16% of our natural gas production to Chevron, Windsor, and Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Our method of accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and +certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, +discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are +depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. +Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil +and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at +10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month prices for 2010 and 2009 and prior to 2009, unescalated year-end prices, adjusted for any contract provisions or financial derivatives, +if any, that hedge oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and +(c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value +reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and +natural gas properties is not reversible at a later date, even if oil or gas prices increase. If prices of oil, natural gas and natural gas liquids decrease, we may be required to further write down the value of our oil and gas properties. Future +non-cash asset impairments could negatively affect our results of operations. +Our use of 2-D and 3-D seismic data is subject to +interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. +Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators +and do not +26 +Table of Contents +enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling +expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. +We have entered into forward sales contracts and fixed price swaps and may in the future enter into additional contracts for a portion of our production, which may result in our making cash payments or +prevent us from receiving the full benefit of increases in prices for oil and gas. +To mitigate the effects of commodity +price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 +through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation +costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel, before transportation costs and differentials, for the period January 2011 through +December 2011. We delivered approximately 45% of our 2010 production under these agreements. Under the 2011 contracts, we have committed to deliver approximately 30% to 33% of our estimated 2011 production. Such arrangements may expose us to risk of +financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts +and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements. +A terrorist attack or armed conflict could harm our business. +Terrorist +activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of +these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and +natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security +may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. +Conservation measures and technological advances could reduce demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, +technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial +condition, results of operations and cash flows. +Risks Related to Our Common Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it +may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: +• +changes in oil and natural gas prices; +• +changes in production levels; +27 +Table of Contents +• +changes in governmental regulations and taxes; +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary +significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some +future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders. +As of December 31, 2010, Charles E. Davidson, our largest stockholder, beneficially owned approximately 25.4% of our +outstanding common stock. As a result, this stockholder acting alone is able to exercise significant influence over most matters requiring approval by our stockholders, including the election of directors and the approval of significant corporate +transactions. Such a concentration of ownership may have the effect of delaying or preventing a change in control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices. +We do not currently pay dividends on our common stock and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to +retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders +of our common stock. +A change of control could limit our use of net operating losses. +As of December 31, 2010, we had a net operating loss, or NOL, carry forward of approximately $52.4 million for federal income tax +purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax +year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +Future sales of our common stock may depress our stock price. +We and +certain of our stockholders have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market, or the perception that these sales may +occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of March 1, 2011, +there were 44,670,930 shares of our common stock issued and outstanding, excluding 112,891 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan, 30,420 shares issuable upon exercise of outstanding +warrants and 433,241 shares issuable upon exercise of outstanding options to purchase our common stock granted under our Amended and Restated 2005 Stock Incentive Plan. +We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover +effects. +We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of +preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or +28 +Table of Contents +resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and +the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of +incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special +rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce +the value of our common stock. +In addition, specific rights granted to future holders of preferred stock could be used to +restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current +stockholders. +The existence of some provisions in our organizational documents could delay or prevent a change in control of +our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Proved Oil and Natural Gas +Reserves +SEC Rule-Making Activity +In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, +using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the +following: +• +Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis. +• +Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities +will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. +• +Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production +history. +• +Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees +the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. +• +Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method +of extraction. +We adopted the rules effective December 31, 2009, as required by the SEC. +29 +Table of Contents +Evaluation and Review of Reserves. +Reserve estimates at December 31, 2010 were prepared by NSAI with respect to our WCBB and Niobrara fields (22% of our proved reserves +at December 31, 2010), by Pinnacle with respect to our assets in the Permian Basin in West Texas (65% of our proved reserves at December 31, 2010) and by our personnel with respect to our Hackberry fields and our overriding royalty and +non-operated interests (13% of our proved reserves at December 31, 2010). +NSAI and Pinnacle are independent petroleum +engineering firms. Copies of their summary reserve reports are included as Exhibit 99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements +with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent +third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. +We +maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI and Pinnacle to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our WCBB and +Niobrara fields and our assets in the Permian Basin, respectively. Our internal technical team members meet with NSAI and Pinnacle periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. +We provide historical information to NSAI and Pinnacle for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our proved reserves attributable to our Hackberry +fields and other minority interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our chief reserve engineer is primarily responsible for overseeing the preparation of all of our reserve +estimates. He is a petroleum engineer with over 30 years of reservoir and operations experience and our geophysical staff has over 60 years combined industry experience. Our technical staff uses historical information for our properties such as +ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. +The +preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: +• +review and verification of historical production data, which data is based on actual production as reported by us; +• +preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision; +• +review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all +significant reserve changes and all new proved undeveloped reserves additions; +• +direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; and +• +verification of property ownership by our land department. +30 +Table of Contents +The following table sets forth our estimated proved reserves at December 31, +2010, 2009 and 2008: +Year Ended December 31, +2010 +2009 +2008 +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Proved developed +7,230 +6,068 +6,165 +4,325 +7,072 +7,187 +Proved undeveloped +12,474 +10,090 +11,323 +10,007 +14,699 +15,048 +Total (1) +19,704 +16,158 +17,488 +14,332 +21,771 +22,235 +Year Ended December 31, +2010 +2009 +2008 +Total net proved oil and natural gas reserves (Mboe) (1) +22,397 +19,877 +25,477 +PV-10 value (in millions) (2) +$ +392.6 +$ +263.0 +$ +126.2 +Standardized measure (in millions) (3) +$ +315.5 +$ +240.8 +$ +126.2 +(1) +Estimates of reserves as of year-end 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a +field-by-field basis on the first day of each month within the 12-month period ended December 31, 2010 and 2009, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2010 and 2009. +Estimates of reserves as of year-end 2008 were prepared using constant prices and costs in accordance with previous guidelines of the SEC based on hydrocarbon prices received on a field-by-field basis as of December 31st of such year. Reserve +estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these +estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. +(2) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net +revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our +reserve reports for the years ended December 31, 2010 and 2009 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $76.16 per +barrel and $4.38 per MMBtu and $57.90 per barrel and 3.87 per MMBtu, respectively, and in each case adjusted by lease for transportation fees and regional price differentials. The estimated future production in our reserve report for the year +ended December 31, 2008 is priced using constant year-end pricing of $41.00 per barrel and $5.71 per MMBtu and adjusted by lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial +measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. +PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure—standardized measure of discounted future net cash +flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value: +December 31, +2010 +2009 +2008 +Standardized measure of discounted future net cash flows +$ +315,487,000 +$ +240,774,000 +$ +126,240,000 +Add: Present value of future income tax discounted at 10% +77,117,000 +22,237,000 +— +PV-10 value +$ +392,604,000 +$ +263,011,000 +$ +126,240,000 +31 +Table of Contents +(3) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, +production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure +includes the effect of future income taxes. +The above table does not include proved reserves net to our +interest in Tatex. For further discussion of our interest in Tatex, see Item 1. “Description of Business—Additional Properties.” +The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that +cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, +the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil +and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors” +contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. +Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves, or PUDs, at +December 31, 2010, 2009 and 2008 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 21 to +our consolidated financial statements included in this report. Also contained in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves. Additional information regarding +our proved reserves can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” and “—Critical Accounting Policies and Estimates” included in this +report. +Proved Undeveloped Reserves (PUDs) +As of December 31, 2010, our proved undeveloped reserves totaled 12,474 Mboe of oil and 10,090 MMcf of natural gas, for a total of 14,156 Mboe. Approximately 80% of our PUDs at year-end 2010 were +located in the Permian Basin, 8% of our PUDs were located in WCBB, 10% were located in our East Hackberry field and 2% of our PUDs were located in our Niobrara field. PUDs will be converted from undeveloped to developed as the applicable wells begin +production. Changes in PUDs that occurred during 2010 were primarily due to: +• +Additions of 7,952 Mboe attributable to 2010 acquisitions and extensions; +• +Conversion of approximately 718 Mboe attributable to PUDs into proved developed reserves; +• +Positive revisions of approximately 386 Mboe in PUDs due to changes in commodity prices; and +• +Exclusion of 6,455 Mboe attributable to PUD locations that were not scheduled to be drilled within the next five years. +At December 31, 2010, there were proved undeveloped reserves for four WCBB locations that have remained undeveloped for five years +or more after their disclosure as proved undeveloped reserves, a decrease from the 11 PUD locations that had remained undeveloped for over five years at December 31, 2009. The reserves attributed to these locations represented approximately +2.5% of our total proved reserves at December 31, 2010 and 7.5% of our total proved reserves at December 31, 2009. We included each of these locations because we believe them to be attractive targets. They were not drilled within five +years after their disclosure as proved undeveloped reserves due to the curtailment of our drilling activities in 2008 and 2009 as a +32 +Table of Contents +result of the sharp decrease in commodity prices. Of the four remaining PUD locations on our books at December 31, 2010, one has already been drilled during 2011 and the other three are +currently scheduled to be drilled during the summer of 2011. +Costs incurred relating to the development of PUDs were +approximately $12.2 million in 2010. Estimated future development costs relating to the development of PUDs are projected to be approximately $71.3 million in 2011, $63.1 million in 2012, $52.0 million in 2013, $20.3 million in 2014 and $47.3 in +2015. +All PUD drilling locations are scheduled to be drilled prior to the end of 2015. +As of December 31, 2010, 19% of our total proved reserves were classified as proved developed non-producing. +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2010 +2009 +2008 +Production Volumes: +Oil (MBbls) +1,777 +1,531 +1,584 +Gas (MMcf) +788 +491 +712 +Natural gas liquids (MGal) +2,821 +2,719 +2,583 +Oil equivalents (Mboe) +1,976 +1,677 +1,764 +Average Prices: +Oil (per Bbl) +$ +68.29 +(1) +$ +53.29 +(1) +$ +83.23 +(1) +Gas (per Mcf) +$ +4.40 +$ +4.06 +$ +9.23 +Natural gas liquids (per Gal) +$ +1.00 +$ +0.73 +$ +1.26 +Oil equivalents (per Boe) +$ +64.61 +$ +51.01 +$ +80.30 +Production Costs: +Average production costs (per Boe) +$ +8.92 +(2) +$ +9.73 +(2) +$ +12.96 +(2) +Average production taxes (per Boe) +$ +7.07 +$ +5.84 +$ +8.96 +Total production costs (per Boe) +$ +15.99 +$ +15.57 +$ +21.92 +(1) +Includes fixed contract prices at a weighted average price of: +January – December 2008 +$ +78.56 +January – December 2009 +$ +55.01 +January – December 2010 +$ +57.55 +Excluding the effect +of the fixed price contracts, the average oil price for 2010 would have been $78.12 per barrel and $73.45 per barrel of oil equivalent. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. Excluding +the effect of the fixed price contracts, the average oil price for 2009 would have been $57.98 per barrel and $55.29 per barrel of oil equivalent. The total volume hedged for 2009 represented approximately 49% of our total sales volumes for the +year. Excluding the net effect of the fixed price contracts, the average oil price for 2008 would have been $97.36 per barrel and $92.98 per barrel of oil equivalent. The total volume hedged for 2008 represented approximately 73% of our total sales +volumes for the year. +(2) +Does not include production taxes. +33 +Table of Contents +The following table provides a summary of our production, average sales prices and average +production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2010: +Year Ended December 31, +2010 +2009 +2008 +WCBB +Net Production +Oil (MBbls) +1,176 +1,209 +1,220 +Natural gas (MMcf) +410 +192 +356 +NGL (Mgal) +— +— +— +Total (Mboe) +1,244 +1,241 +1,280 +Average Sales Price: +Oil (per Bbl) +$ +62.57 +$ +52.39 +$ +80.20 +Natural gas (per Mcf) +$ +4.44 +$ +4.44 +$ +10.48 +NGL (per Gal) +$ +— +$ +— +$ +— +Average Production Cost (per BOE) +$ +8.90 +$ +8.54 +$ +10.86 +Permian Basin +Net Production +Oil (MBbls) +134 +118 +134 +Natural gas (MMcf) +256 +236 +234 +NGL (Mgal) +2,797 +2,694 +2,579 +Total (Mboe) +243 +221 +234 +Average Sales Price: +Oil (per Bbl) +$ +76.48 +$ +55.19 +$ +94.42 +Natural gas (per Mcf) +$ +4.21 +$ +3.72 +$ +7.57 +NGL (per Gal) +$ +1.00 +$ +0.73 +$ +1.26 +Average Production Cost (per BOE) +$ +9.78 +$ +10.71 +$ +11.59 +Productive Wells and Acreage +The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and +gas, and the total gross and net developed and undeveloped acres as of December 31, 2010. +NRI/WI (1) +Productive +Oil Wells (2) +Productive +Gas Wells +Non-Productive +Oil Wells +Non-Productive +Gas Wells +Developed +Acreage (3) +Undeveloped +Acreage +(4) +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +West Cote Blanche Bay Field (5) +80.1/100 +90 +90 +3 +3 +161 +161 +18 +18 +5,668 +5,668 +— +— +E. Hackberry Field (6) +79.4/100 +27 +27 +— +— +74 +74 +— +— +3,291 +3,291 +1,579 +1,579 +W. Hackberry Field +87.5/100 +3 +3 +— +— +22 +22 +— +— +592 +592 +— +— +Permian Basin +37.4/49.05 +82 +40 +— +— +— +— +— +— +15,888 +7,124 +20,089 +7,598 +Niobrara Formation (7) +36.4/44.04 +4 +2 +— +— +1 +0.4 +— +— +2,240 +628 +41,480 +18,817 +Williston Basin (8) +3.2/3.9 +5 +0.2 +— +— +— +— +— +— +2,560 +127 +3,920 +779 +Overrides/Royalty Non-operated +Various +76 +0.2 +1 +— +2 +— +— +— +— +— +— +— +Total +287 +162.4 +4 +3 +260 +257.4 +18 +18 +30,239 +17,430 +67,068 +28,773 +34 +Table of Contents +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes nine gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been perpetuated by production. +(4) +E. Hackberry acreage does not include 2,868 net acres subject to a two-year exploration agreement. +(5) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(6) +NRI shown is for producing wells. +(7) +The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed or extended, we +have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. +Leases representing 35%, 20%, 22%, 4% and 19% of our total Niobrara acreage are currently scheduled to expire in 2011, 2012, 2013, 2014 and thereafter, respectively. +(8) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +Completed and Present Drilling and Recompletion Activities +The following +table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the +number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +2010 +2009 +2008 +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +87 +84 +64 +62.5 +58 +56.5 +Dry +— +— +— +— +— +— +Total +87 +84 +64 +62.5 +58 +56.5 +Development: +Productive +57 +42 +25 +18 +69 +27 +Dry +— +— +1 +1 +— +— +Total +57 +42 +26 +19 +69 +27 +Exploratory: +Productive +— +— +1 +1 +— +— +Dry +— +— +— +— +1 +1 +Total +— +— +1 +1 +1 +1 +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title +examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas +properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management’s opinion, will in the aggregate materially restrict our operations. +35 +Table of Contents +ITEM 3. +LEGAL PROCEEDINGS +The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR +maintains that we paid approximately $1.8 million less in severance taxes under fixed price terms than the severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any +liability to the LDR for underpayment of severance taxes and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. +We have maintained our right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against our company seeking $2,275,729 in severance taxes, +plus interest and court costs. We filed a response denying any liability to the LDR for underpayment of severance taxes and are defending our company in the lawsuit. The case is in the early stages of discovery. +More recently, in December 2010, the LDR filed two identical lawsuits against us in different venues to recover allegedly underpaid +severance taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney's fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by +the LDR in 2009, we have denied all liability and will vigorously defend the lawsuit. The cases are in the very early stages, and we have not yet filed a response to the recent lawsuits. +In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us, Great White Pressure Control LLC, or Great White, and +six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and +several other causes of action relating to Great White’s employment of the former Cudd employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without +prejudice by order of the court on February 14, 2007. We filed a motion for summary judgment on October 5, 2007. The Court entered a final interlocutory judgment in favor of all defendants, including us, on April 8, 2008. On +November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered summary judgment +without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition +with the state court (a) alleging that we conspired with the other defendants to misappropriate, and misappropriated Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking unspecified monetary +damages. On April 13, 2010, our motion to be dismissed from the proceeding for lack of personal jurisdiction was denied. This state court proceeding is in its initial stages. In 2011, the parties have continued with written discovery and +production of documents. On February 15, 2011, Cudd filed a third amended petition seeking $26.5 million (based on a report prepared by its expert) plus disgorgement of $6.0 million in payments by Great White to the individual defendants and +punitive damages. Gulfport denies these claims with respect to itself. +On July 30, 2010, six individuals and one limited +liability company sued 15 oil and gas companies in Cameron Parish Louisiana for contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al., 38th Judicial +District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name us as a defendant, alleges that the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a +result of historic oil and gas exploration and production activities. Plaintiffs allege that the defendants, which in addition to BP America Production Company include ExxonMobil Corporation, Shell Oil Company, ConocoPhillips Company, Sun Oil +Company and Schlumberger Technology Corporation, conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and +have sued the defendants for alleged breaches of oil, gas and +36 +Table of Contents +mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, +assessment and response costs and stigma damages. On December 7, 2010, we were served with a copy of the plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and six additional defendants, +including us, bringing the total number of defendants to 21. It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the +plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its +pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages +for loss of use of land and lost profits and income; attorney fees and expenses; and damages for evaluation and remediation of any contamination that threatens groundwater. On January 21, 2011, we filed a pleading challenging the legal +sufficiency of the petitions and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. Our motion is currently set to be heard on March 23, 2011. +Due to the current stages of the above litigation, the outcomes are uncertain and management cannot determine the amount of loss, if any, +that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse affect on our financial condition or results of operations. +In addition to the above, we have been named as a defendant in various other lawsuits related to our business. The ultimate resolution of +such other matters is not expected to have a material adverse effect on our financial condition or results of operations. +ITEM 4. +RESERVED +37 +Table of Contents +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market under the symbol “GPOR.” The +following table sets forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2009 +First Quarter +$ +5.20 +$ +1.50 +Second Quarter +7.65 +2.23 +Third Quarter +8.99 +5.23 +Fourth Quarter +11.89 +7.25 +2010 +First Quarter +$ +12.68 +$ +8.89 +Second Quarter +15.25 +10.60 +Third Quarter +14.71 +10.37 +Fourth Quarter +22.92 +13.59 +2011 +First Quarter (through March 10, 2011) +$ +30.99 +$ +20.00 +On March 10, +2011, the last reported sale price of our common stock on The NASDAQ Global Select Market was $24.69. +Unregistered Sales of Equity +Securities and Use of Proceeds +None. +Holders of Record +At the close of business on March 3, 2011, there +were 340 stockholders of record holding 44,549,037 shares of our outstanding common stock. There were approximately 14,970 beneficial owners of our common stock as of March 3, 2011. +Dividend Policy +We have never paid dividends on our common stock. We +currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends +to the holders of our common stock. +38 +Table of Contents +ITEM 6. +SELECTED FINANCIAL DATA +You should read the following selected consolidated financial data in conjunction with “Management’s Discussion and Analysis of +Financial Condition and Results of Operations” and the consolidated financial statements and the related notes appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended +December 31, 2010, December 31, 2009 and December 31, 2008 and the selected consolidated balance sheet data at December 31, 2010 and December 31, 2009 are derived from our audited consolidated financial statements +appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2007 and December 31, 2006 and the selected consolidated balance sheet data at December 31, +2008, December 31, 2007 and December 31, 2006 are derived from our audited consolidated financial statements that are not included in this report. The historical data presented below is not indicative of future results. We did not pay +any cash dividends on our common stock during any of the periods set forth in the following table. +Fiscal Year Ended December 31, +2010 +2009 +2008 +2007 +2006 +Selected Consolidated Statements of Operations Data: +Revenues +$ +126,944,000 +$ +85,262,000 +$ +141,217,000 +$ +105,838,000 +$ +60,390,000 +Costs and expenses: +Lease operating expenses +17,614,000 +16,316,000 +22,856,000 +16,670,000 +10,670,000 +Production taxes +13,966,000 +9,797,000 +15,813,000 +12,667,000 +7,366,000 +Depreciation, depletion and amortization +38,907,000 +29,225,000 +42,472,000 +29,681,000 +12,652,000 +Impairment of oil and natural gas properties +— +— +272,722,000 +— +— +General and administrative +6,063,000 +4,992,000 +6,843,000 +5,802,000 +3,251,000 +Accretion expense +617,000 +582,000 +560,000 +554,000 +596,000 +77,167,000 +60,912,000 +361,266,000 +65,374,000 +34,535,000 +Income (Loss) from Operations +49,777,000 +24,350,000 +(220,049,000 +) +40,464,000 +25,855,000 +Other (Income) Expense: +Interest expense +2,761,000 +2,309,000 +4,762,000 +3,091,000 +1,956,000 +Insurance recoveries +— +(1,050,000 +) +(769,000 +) +— +(3,601,000 +) +Settlement of fixed price contracts +— +— +(39,000,000 +) +— +— +Interest income +(387,000 +) +(564,000 +) +(540,000 +) +(523,000 +) +(308,000 +) +2,374,000 +695,000 +(35,547,000 +) +2,568,000 +(1,953,000 +) +Income (Loss) before Income Taxes +47,403,000 +23,655,000 +(184,502,000 +) +37,896,000 +27,808,000 +Income Tax Expense +40,000 +28,000 +— +121,000 +— +Net Income (Loss) +47,363,000 +23,627,000 +(184,502,000 +) +37,775,000 +27,808,000 +Net Income (Loss) Available to Common Stockholders +47,363,000 +$ +23,627,000 +$ +(184,502,000 +) +$ +37,775,000 +$ +27,808,000 +Net Income (Loss) Per Common Share—Basic: +$ +1.08 +$ +0.55 +$ +(4.33 +) +$ +1.03 +$ +0.85 +Net Income (Loss) Per Common Share—Diluted: +$ +1.07 +$ +0.55 +$ +(4.33 +) +$ +1.01 +$ +0.82 +39 +Table of Contents +At December 31, +2010 +2009 +2008 +2007 +2006 +Selected Consolidated Balance Sheet Data: +Total assets +$ +319,693,000 +$ +227,344,000 +$ +221,873,000 +$ +419,137,000 +$ +195,151,000 +Total debt, including current maturity +$ +51,917,000 +$ +52,428,000 +$ +70,731,000 +$ +66,533,000 +$ +37,691,000 +Total liabilities +$ +108,637,000 +$ +102,293,000 +$ +107,772,000 +$ +115,015,000 +$ +71,342,000 +Stockholders’ equity +$ +211,056,000 +$ +125,051,000 +$ +114,101,000 +$ +304,122,000 +$ +123,809,000 +40 +Table of Contents +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes +included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating +results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk +Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. +Overview +We are an +independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. In +2010, we acquired an acreage position in Western Colorado in the Niobrara Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, and have interests in entities that +operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +2010 Highlights +• +Oil and natural gas revenues increased 49% to $127.6 million for the year ended December 31, 2010 from $85.6 million for the year ended +December 31, 2009. +• +Net income increased 100% to $47.4 million for the year ended December 31, 2010 from $23.6 million for the year ended December 31, 2009. +• +Production increased 18% to approximately 1,976,000 barrels of oil equivalent, or BOE, for the year ended December 31, 2010 from approximately +1,677,000 BOE for the year ended December 31, 2009. +• +During 2010, we drilled 57 gross (42 net) wells, which includes 26 gross (11 net) wells drilled by our operators in the Permian Basin and Bakken, and +recompleted 87 gross (84 net) wells. Of our 57 new wells drilled, 56 were completed as producing wells and one was waiting on completion. +• +During 2010, we acquired approximately 6,500 additional net acres in the Permian Basin, which brought our total net acreage position in the Permian +Basin to approximately 14,700 net acres. +• +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Colorado and held leases for 19,172 net acres as of +March 1, 2011. +• +In May 2010, we completed an underwritten public offering of 1,668,503 shares of our common stock and received approximately $21.4 million in net +proceeds, which we used to fund the acquisition of our interests in the Niobrara Formation, pay the purchase price for a portion of the additional acreage acquired by us in the Permian Basin in 2010 and for general corporate purposes. +• +On September 30, 2010, we entered into a new $100.0 million senior secured revolving credit facility with The Bank of Nova Scotia, as +administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association, and repaid and terminated our existing revolving credit facility and term loan, each with Bank of America, N.A., as administrative agent, with +borrowings under our new revolving credit facility. Our borrowing base under this facility was increased from $50.0 million to $65.0 million in December 2010. +Recent Developments +In February 2011, we entered into an agreement to +acquire certain leasehold interests located in the Utica Shale in Ohio. The agreement also grants us an exclusive right of first refusal for a period of six months on +41 +Table of Contents +certain additional tracts leased by the seller. Windsor, an affiliate of ours, has agreed to participate with us on a 50/50 basis in the acquisition of all of the leases described above. We will +be the operator on this acreage in the Utica Shale. The purchase price for our 50% interest in the initial acreage is approximately $31.6 million, subject to certain closing adjustments. This transaction is expected to close in mid-May 2011. +Critical Accounting Policies and Estimates +Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles +generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We +have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates +including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the +circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our +consolidated financial statements: +Oil and Natural Gas Properties . We use the full cost method of accounting for oil +and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. +Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are +limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based +on the 12-month unweighted average of the first-day-of-the-month price for the period 2010 and 2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil +and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or +market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, +exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent +units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the +relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled $16.8 million at December 31, 2010 and $17.5 +million at December 31, 2009. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its +impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development. +Ceiling Test . Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling +test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center +ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period January – December of +the applicable year beginning with 2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, +42 +Table of Contents +if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost +of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and +natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future +depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved +reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural gas and natural gas liquids decline, we may be required to further write down the value of our oil and gas +properties, which could negatively affect our results of operations. No ceiling test impairment was required for the year ended December 31, 2010. +Asset Retirement Obligations . We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily +associated with plugging and abandoning wells and associated production facilities. +We account for abandonment and +restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the +definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The +liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These +liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual +inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions +to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and +amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous +estimates. +Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil and +natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., +Pinnacle Energy Services, LLC and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2010 on a well-by-well basis for our properties. +Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments +to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with SEC guidelines. The accuracy of our +reserve estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +43 +Table of Contents +Our proved reserve estimates are a function of many assumptions, all of which could deviate +significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. +Income Taxes . We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of +(1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on +enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate +change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation +allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At +December 31, 2010, a valuation allowance of $54.4 million had been provided for deferred tax assets based on the uncertainty of future taxable income. +Revenue Recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is +delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will +receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. +Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or +other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to +reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities. +Derivative Instruments and Hedging Activities . We seek to reduce our exposure to unfavorable changes in oil prices by utilizing +energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, “ Derivatives and Hedging ,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance +sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our +realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. +Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in +accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We +recognize any change in fair value resulting from ineffectiveness immediately in earnings. +To mitigate the effects of +commodity price fluctuations, for the period January 2010 through February 2010, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before +transportation costs and differentials. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB +44 +Table of Contents +production per day at a weighted average daily price of $58.24 per barrel, before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of +oil per day at a weighted average price of $86.96 per barrel, before transportation costs and differentials, for the period January 2011 through December 2011. Under the 2010 contracts, we delivered approximately 45% of our estimated 2010 +production. Under the 2011 contracts, we have committed to deliver approximately 30% to 33% of our estimated 2011 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is +less than expected or oil prices increase. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. +RESULTS OF OPERATIONS +Results of +Operations +The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil +and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2010 +2009 +2008 +Production Volumes: +Oil (MBbls) +1,777 +1,531 +1,584 +Gas (MMcf) +788 +491 +712 +Natural gas liquids (MGal) +2,821 +2,719 +2,583 +Oil equivalents (Mboe) +1,976 +1,677 +1,764 +Average Prices: +Oil (per Bbl) +$ +68.29 +(1) +$ +53.29 +(1) +$ +83.23 +(1) +Gas (per Mcf) +$ +4.40 +$ +4.06 +$ +9.23 +Natural gas liquids (per Gal) +$ +1.00 +$ +0.73 +$ +1.26 +Oil equivalents (per Boe) +$ +64.61 +$ +51.01 +$ +80.30 +Production Costs: +Average production costs (per Boe) +$ +8.92 +(2) +$ +9.73 +(2) +$ +12.96 +(2) +Average production taxes (per Boe) +$ +7.07 +$ +5.84 +$ +8.96 +Total production costs (per Boe) +$ +15.99 +$ +15.57 +$ +21.92 +(1) +Includes fixed contract prices at a weighted average price of: +January – December 2008 +$ +78.56 +January – December 2009 +$ +55.01 +January – December 2010 +$ +57.55 +Excluding the net +effect of the fixed price contracts, the average oil price for 2010 would have been $78.12 per barrel and $73.45 per barrel of oil equivalent. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. +Excluding the effect of the fixed price contracts, the average oil price for 2009 would have been $57.98 per barrel and $55.29 per barrel of oil equivalent. The total volume hedged for 2009 represented approximately 49% of our total sales volumes +for the year. Excluding the net effect of the fixed price contracts, the average oil price for 2008 would have been $97.36 per barrel and $92.98 per barrel of oil equivalent. The total volume hedged for 2008 represented approximately 73% of our +total sales volumes for the year. +45 +Table of Contents +(2) +Does not include production taxes. +From 2009 to 2010, our net equivalent oil production increased 18% from 1,677,000 barrels to 1,976,000 barrels due to increased drilling activity, the success of our drilling activities and our +acquisitions of additional properties in the Permian Basin and the Niobrara Formation. From 2008 to 2009, our net equivalent oil production decreased 5% from 1,764,000 barrels to 1,677,000 barrels due to our reduced drilling activity and normal +production declines. We currently estimate that our 2011 production will be between 2,200,000 and 2,400,000 BOE. However, such estimate may change based on a change in our expected drilling and recompletion activities or the changing economic +climate and unforeseen events, such as hurricanes. +Comparison of the Years Ended December 31, 2010 and December 31, 2009 +We reported net income of $47,363,000 for the year ended December 31, 2010, as compared to net income of $23,627,000 +for the year ended December 31, 2009. This 100% increase in 2010 was due primarily to a 27% increase in realized BOE prices to $64.61 from $51.01 and an 18% increase in net production to 1,976,000 BOE, partially offset by an 8% increase in +lease operating expenses, a 21% increase in general and administrative expenses and a 43% increase in production taxes. +Oil and Gas Revenues . For the year ended December 31, 2010, we reported oil and natural gas revenues of $127,636,000 as +compared to oil and natural gas revenues of $85,576,000 during 2009. This $42,060,000, or 49%, increase in revenues is primarily attributable to a 27% increase in realized BOE prices to $64.61 from $51.01 and an 18% increase in net production to +1,975,576 BOE for the year ended December 31, 2010 from 1,677,474 BOE for the year ended December 31, 2009. +The +following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2010 and December 31, 2009: +Year Ended +December 31, +2010 +2009 +Oil production volumes (MBbls) +1,777 +1,531 +Gas production volumes (MMcf) +788 +491 +Natural gas liquids production volumes (MGal) +2,821 +2,719 +Oil equivalents (Mboe) +1,976 +1,677 +Average oil price (per Bbl) +$ +68.29 +$ +53.29 +Average gas price (per Mcf) +$ +4.40 +$ +4.06 +Average natural gas liquids (per Gal) +$ +1.00 +$ +0.73 +Oil equivalents (per Boe) +$ +64.61 +$ +51.01 +Lease Operating +Expenses . Lease operating expenses not including production taxes increased to $17,614,000 for 2010 from $16,316,000 for 2009. This increase is mainly a result of an increase in ad valorem taxes and expenses related to well workovers. +Production Taxes . Production taxes increased to $13,966,000 for 2010 from $9,797,000 for 2009. This increase was +primarily related to a 49% increase in oil and gas revenues as a result of a 27% increase in average realized BOE price received and an 18% increase in production. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $38,907,000 for 2010, and consisted of $38,600,000 in depletion on oil and +natural gas properties and $307,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $29,225,000 for 2009. This increase was due to an increase in our full cost pool as a +result of our capital activities and an increase in our production used to calculate our total DD&A expense. +46 +Table of Contents +General and Administrative Expenses . Net general and administrative expenses +increased to $6,063,000 for 2010 from $4,992,000 for 2009. This $1,071,000 increase was primarily due to a $450,000 increase in franchise taxes, a $200,000 increase in legal expenses and increases related to salaries, benefits expenses partially +offset by an increase in general and administrative overhead related to exploration and development activity capitalized to the full cost pool. +Accretion Expense. Accretion expense increased slightly to $617,000 for 2010 from $582,000 for 2009. +Interest Expense . Interest expense increased to $2,761,000 for 2010 from $2,309,000 for 2009. This increase was due to an increase in the interest rate paid as well as the recognition of +approximately $225,000 in unamortized loan fees associated with the termination of the Bank of America revolving credit facility. Effective September 30, 2010, this facility, along with the term loan with Bank of America, were repaid with +borrowings under our new senior secured revolving credit agreement with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association, entered into on September 30, 2010. +This increase in interest expense was partially offset by a decrease in average debt outstanding for the year ended December 31, 2010, as compared to the year ended December 31, 2009. Total debt outstanding under our new revolving credit +facility was $49.5 million as of December 31, 2010, as compared to $49.9 million outstanding under our prior facilities with Bank of America as of the same date in 2009. Total weighted debt outstanding under our facilities was $46.9 million for +2010 and $59.9 million for 2009. Until September 30, 2010, amounts borrowed under our term loan and revolving credit facility with Bank of America bore interest of 3.76% and 3.25%, respectively. At December 31, 2010, amounts borrowed under +our new revolving credit agreement bore interest at the Eurodollar rate of 3.77%. +Income Taxes . As of +December 31, 2010, we had a net operating loss carry forward of approximately $52.4 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable +income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more +likely than not that some portion will not be realized. At December 31, 2010, a valuation allowance of $54.4 million had been provided for deferred tax assets, with the exception of $628,000 for alternative minimum taxes. We paid $40,000 of +state income tax for the year ended December 31, 2010. +Comparison of the Years Ended December 31, 2009 and December 31, +2008 +We reported net income of $23,627,000 for the year ended December 31, 2009, as compared to a net loss of +$184,502,000 for the year ended December 31, 2008. This net income is primarily attributable to a 29% decrease in lease operating expenses, a 27% decrease in general and administrative expenses and a 38% decrease in production taxes, partially +offset by a 36% decrease in realized BOE prices to $51.01 from $80.30 and a 5% decrease in net production to 1,677,474 BOE. In addition, the net loss for 2008 was primarily attributable to an impairment charge of $272,722,000 related to the drastic +decline in oil and gas prices. Further, we had $1,050,000 of insurance proceeds received during the year ended December 31, 2009 compared to insurance proceeds of $769,000 received during 2008. +Oil and Gas Revenues . For the year ended December 31, 2009, we reported oil and natural gas revenues of $85,576,000 as +compared to oil and natural gas revenues of $141,650,000 during 2008. This $56,074,000, or 40%, decrease in revenues is primarily attributable to a 36% decrease in realized BOE prices to $51.01 from $80.30 and a 5% decrease in net production to +1,677,474 BOE for the year ended December 31, 2009 from 1,764,053 BOE for the year ended December 31, 2008. +47 +Table of Contents +The following table summarizes our oil and natural gas production and related pricing for +the years ended December 31, 2009 and December 31, 2008: +Year Ended +December 31, +2009 +2008 +Oil production volumes (MBbls) +1,531 +1,584 +Gas production volumes (MMcf) +491 +712 +Natural gas liquids production volumes (MGal) +2,719 +2,583 +Oil equivalents (Mboe) +1,677 +1,764 +Average oil price (per Bbl) +$ +53.29 +$ +83.23 +Average gas price (per Mcf) +$ +4.06 +$ +9.23 +Average natural gas liquids (per Gal) +$ +0.73 +$ +1.26 +Oil equivalents (per Boe) +$ +51.01 +$ +80.30 +Lease Operating +Expenses . Lease operating expenses not including production taxes decreased to $16,316,000 for 2009 from $22,856,000 for 2008. This decrease is mainly a result of a decrease in contract labor expenses, a decrease in workovers, compressor and +other equipment rentals and repairs, a decrease in the cost of chemicals and supplies and a decrease in personal property taxes. In addition, the lease operating expenses for 2008 included $3,408,000 of unreimbursed expenses related to hurricane +repairs as compared to approximately $23,000 of unreimbursed expenses related to hurricane repairs in 2009. +Production +Taxes . Production taxes decreased to $9,797,000 for 2009 from $15,813,000 for 2008. This decrease was primarily related to a 40% decrease in oil and gas revenues mainly as a result of the decrease in the average realized BOE price received. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization expense decreased to $29,225,000 +for 2009, and consisted of $28,939,000 in depletion on oil and natural gas properties and $286,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $42,472,000 for 2008. This +decrease was due primarily to the reduction in the book value of our oil and gas properties used to calculate depreciation, depletion and amortization expense. This reduction resulted from the drop in commodity prices reflected as of +December 31, 2008 and the resulting reduction in our proved reserves which caused us to recognize a ceiling test impairment to our full cost pool of $272,722,000 for the year ended December 31, 2008. +Impairment of Oil and Gas Properties. We use the full cost method of accounting for oil and gas properties and are required to +perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of our oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center +ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period of +January through December 2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs +for properties with asset retirement obligations recorded on our balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, +less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash +write-down is required. There was no impairment charge for the year ended December 31, 2009. As a result of the drop in commodity prices on December 31, 2008, we recognized a ceiling test impairment of $272,722,000 for the year ended +December 31, 2008. +General and Administrative Expenses . Net general and administrative expenses decreased to +$4,992,000 for 2009 from $6,843,000 for 2008. This $1,851,000 decrease was due primarily to reductions in franchise taxes as a +48 +Table of Contents +result of the impairment mentioned in the depreciation, depletion and amortization section above which reduced our net assets used to calculate franchise taxes, a reduction in stock based +compensation expenses, reductions in payroll costs including payroll taxes and related benefits mainly due to decreases in the total number of employees partially offset by a decrease in general and administrative reimbursements from our affiliates +and a decrease in general and administrative overhead related to exploration and development activity capitalized to the full cost pool. +Accretion Expense . Accretion expense increased slightly to $582,000 for 2009 from $560,000 for 2008. +Interest Expense . Interest expense decreased to $2,309,000 for 2009 from $4,762,000 for 2008 due to a decrease in average debt outstanding and lower interest rates on amounts borrowed under our +facilities with Bank of America. Total debt outstanding under our facilities with Bank of America was $49.9 million as of December 31, 2009 and $68.1 million as of the same date in 2008. Total weighted debt outstanding under our facilities with +Bank of America was $59.9 million for 2009 and $84.2 million for 2008. As of December 31, 2009, amounts borrowed under our revolving credit facility and our two term loans with Bank of America bore interest of 3.73%, 4.23% and 3.25%, +respectively. +Income Taxes . As of December 31, 2009, we had a net operating loss carry forward of approximately +$55.7 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is +needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2009, a +valuation allowance of $73.2 million had been provided for deferred tax assets, as the Company has historically had non-taxable income and has future projections of no taxable income during the carryforward period, with the exception of $533,000 +related to alternative minimum taxes. We had $28,000 of state income tax expense for the year ended December 31, 2009. +Liquidity and +Capital Resources +Overview . Historically, our primary sources of funds have been cash flow from our producing oil +and natural gas properties, borrowings under our bank and other credit facilities and the issuance of equity securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or +our oil and gas production. During 2009, we also received proceeds from the sale of certain of our Bakken assets and, in 2010, we received net proceeds (before offering expenses) of approximately $21.6 million from the sale of our common stock in an +underwritten public offering. +Net cash flow provided by operating activities was $85,835,000 for 2010, as compared to +$53,299,000 for 2009. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 27% increase in net realized prices and an 18% increase in our net BOE production. +Net cash flow provided by operating activities was $53,299,000 for 2009, as compared to $135,323,000 for 2008. This decrease was +primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 36% decrease in net realized prices and a 5% decrease in our net BOE production. +Net cash used in investing activities for 2010 was $105,315,000, as compared to $39,246,000 for 2009. During 2010, we spent $101,644,000 +in additions to oil and natural gas properties, of which $51,356,000 was spent on our 2010 drilling and recompletion programs, $16,735,000 was spent on acquisitions in our Niobrara and Permian fields, $11,697,000 was spent on expenses attributable +to the wells drilled during 2009, $3,093,000 was spent on our 2009 recompletions, $6,838,000 was spent on compressors and other facility enhancements, $1,425,000 was spent on plugging costs, $771,000 was spent on lease related costs and $3,449,000 +was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, we paid $3,719,000 in cash calls to Grizzly during 2010. During 2010, we used cash from operations, borrowings under our +credit facilities and proceeds from our equity offering to fund our investing activities. +49 +Table of Contents +Net cash used in investing activities for 2009 was $39,246,000, as compared to $136,823,000 +for 2008. During the year ended December 31, 2009, we spent (a) $49,533,000 in additions to oil and natural gas properties, of which $20,296,000 was spent on our 2009 drilling and recompletion programs, $14,255,000 was spent on costs +attributable to the wells drilled during 2008, $3,719,000 was spent on our 2008 recompletions, $1,191,000 was spent on barges and other facility enhancements, $866,000 was spent on plugging and abandonment activities, $2,853,000 was spent on lease +related costs and $1,744,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses, and (b) $3,813,000 on our investment in Tatex III and we loaned $4,377,000 to Grizzly. In May, +September and December 2009, we received aggregate net proceeds of approximately $18,286,000 from our sale of properties in the Bakken. During the year ended December 31, 2009, we used cash from operations and proceeds from the sale of Bakken +properties to fund our investing activities. +Net cash provided by financing activities for 2010 was $20,224,000 as compared +to net cash used by financing activities of $18,273,000 for 2009. The 2010 amount provided by financing activities is primarily attributable to the net proceeds of $21,358,000 from our equity offering and borrowings of $52,200,000 under our new +credit facility, partially offset by principal payments of $49,903,000 on borrowings under our prior credit facilities with Bank of America. We used the net proceeds of our 2010 equity offering to fund the acquisition of our interests in the +Niobrara Formation, pay the purchase price for a portion of the additional acreage acquired by us in the Permian Basin in 2010 and for general corporate purposes. +The 2009 amount used by financing activities is primarily attributable to principal payments on borrowings of $18,206,000 under our credit facility with Bank of America, partially offset by $30,000 +received from the exercise of stock options. +Net cash provided by financing activities for 2008 was $4,680,000. The 2008 +amount was primarily attributable to $30,000,000 of borrowings under our line of credit, mostly offset by repayments on the line. +Credit Facility . In March 2005, we entered into a three-year secured credit agreement with Bank of America, N.A. providing for a revolving credit facility. The credit agreement was subsequently +amended and restated from time to time and, among other things, the maturity date was extended to April 1, 2011. Borrowings under the revolving credit facility were subject to a borrowing base limitation, which was initially set at $18.0 +million, subject to adjustment. Effective July 19, 2007, the credit facility was increased to $150.0 million and effective December 20, 2007, the amount available under the borrowing base limitation was increased to $90.0 million. +On August 31, 2009, the lender completed its periodic redetermination of our borrowing base giving consideration to our +year-end 2008 and mid-year 2009 reserve information and the lender’s then current pricing decks, among other factors. As a result of this redetermination, our available borrowing base was reset at $45.0 million, primarily in response to +significant declines in commodity prices. Our outstanding principal balance at the effective time of this redetermination was approximately $59.0 million. The approximately $14.0 million of outstanding borrowings under the credit facility in excess +of the new borrowing base was converted into a term loan as of August 31, 2009. An initial $2.0 million payment was made on the term loan at that time and we agreed to make additional monthly payments of $1.0 million commencing on +September 30, 2009, with all unpaid amounts due on March 31, 2010. We paid the outstanding balance of the term loan in full in February 2010. On September 30, 2010, we repaid all borrowings under the credit facility. +Outstanding borrowings under the term loan accrued interest at the Eurodollar rate (as defined in the credit agreement) plus 4.0% or, at +our option, at the base rate (which was the highest of the lender’s prime rate, the Federal funds rate plus half of 1%, and the one-month Eurodollar rate plus 1%) plus 3%. Effective August 31, 2009, we also agreed to an adjustment in the +commitment fees, interest rates for revolving loans and fees for letters of credit under the credit facility. Specifically, we agreed to pay (a) commitment fees ranging from 0.5% to 0.625% (an increase from 0.15% to 0.25%), (b) margin +interest rates ranging from 2.75% to 3.50% for +50 +Table of Contents +Eurodollar loans (an increase from 1.25% to 2.0%), (c) margin interest rates ranging from 1.75% to 2.5% for base rate loans (an increase from 1.25% to 2.0%), and (d) letter of credit +fees at the margin interest rates for Eurodollar loans, in each case based on our utilization percentage. In addition, we agreed to limitations on certain dispositions and investments and to mandatory prepayments of the loans from the net cash +proceeds of specified asset sales and other events. +Our obligations under the credit facility were collateralized by a lien +on substantially all of our Louisiana and West Texas assets and were guaranteed by our subsidiaries. The restated credit agreement contained certain affirmative and negative covenants, including, but not limited to the following financial covenants: +(a) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest expense, plus +exploration costs deducted in determining net income under full cost accounting) for a twelve-month period could not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period could not be less than +3.00 to 1.00. +On July 10, 2006, we entered into a $5.0 million term loan agreement with Bank of America, N.A. related to +the purchase of new gas compressor units. The loan began amortizing quarterly on March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. We made quarterly principal payments +of approximately $176,000. Amounts borrowed bore interest at Bank of America Prime. We made quarterly interest payments on amounts borrowed under the agreement. Our obligations under the agreement were collateralized by a lien on the compressor +units. On September 30, 2010, we repaid this loan in full with borrowings under the new revolving credit agreement discussed below. +On September 30, 2010, we entered into a new $100.0 million senior secured revolving credit facility with The Bank of Nova Scotia, or Scotia Capital, as administrative agent, letter of credit issuer +and lead arranger, and Amegy Bank National Association, which facility matures on September 30, 2013. The new revolving credit agreement provided for an initial borrowing base availability of $50.0 million, which was increased to $65.0 million +effective December 24, 2010. +As of December 31, 2010, we had an outstanding balance of $49.5 million drawn under +our new revolving credit agreement, which is included in long-term debt, net of current maturities, on our accompanying consolidated balance sheet at December 31, 2010. The amounts borrowed under our new revolving credit agreement were used to +repay our outstanding indebtedness under our prior revolving credit facility ($42.0 million) and term loan ($2.5 million), each with Bank of America, N.A., as administrative agent, and for general corporate purposes. The new revolving credit +agreement is secured by substantially all of our assets. Our wholly-owned subsidiaries guaranteed our obligations under the new revolving credit agreement. +Advances under the new revolving credit agreement may be in the form of either base rate loans or Eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which +ranges from 1.75% to 2.50%, plus (2) the highest of: (a) the federal funds rate plus 0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and +(c) the Eurodollar rate for an interest period of one month plus 1.00%. The interest rate for Eurodollar loans is equal to (1) the applicable rate, which ranges from 2.75% to 3.50%, plus (2) the London interbank offered rate that +appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in +U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At December 31, +2010, amounts borrowed under our new revolving credit agreement bore interest at the Eurodollar rate of 3.77%. +The credit +agreement contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted +51 +Table of Contents +payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions +with their affiliates. The negative covenants are subject to certain exceptions as specified in the credit agreement. The credit agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: +(1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net +income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts +attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received +from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and +acquisitions of assets, investments and debt and equity offering, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to +interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with all covenants at December 31, 2010. +In connection with our scheduled spring 2011 borrowing base redetermination completed in March 2011, Scotia Capital has advised us that it has approved an increase to our borrowing base from the current +level of $65.0 million to $85.0 million. In addition, Scotia has given us a commitment letter providing for an amendment to our credit facility which would, among other things, increase the maximum commitment to $350.0 million, provide for an $85.0 +million current borrowing base, extend the maturity date to April 2015 and reduce our average credit spread by 75 basis points per annum from current levels. Both the increase in the borrowing base to $85.0 million and the other proposed amendments +to our existing credit facility will require the approval of our other current lender and the addition of one or more additional lenders to our bank group. As a result, we cannot assure you that we will be able to amend our existing credit facility +on the terms described above. +During 2010, in conjunction with the repayment of the Bank of America revolving credit facility +on September 30, 2010, we expensed approximately $225,000 in unamortized loan fees associated with this facility, which is included in interest expense in our consolidated statements of operations for the year ended December 31, 2010. +We used the proceeds of our borrowings under the credit facilities for the development of our oil and natural gas properties +and other capital expenditures, acquisition opportunities and for other general corporate purposes. +Building Loans . In +June 2004, we purchased the office building we occupy in Oklahoma City, Oklahoma, for $3.7 million. One loan associated with this building matured in March 2006 and bore interest at the rate of 6% per annum, while the other loan matures in June +2011 and bears interest at the rate of 6.5% per annum. The remaining building loan requires monthly interest and principal payments of approximately $23,000 and is secured by the Oklahoma City office building and associated land. As of +December 31, 2010, approximately $2.4 million was outstanding on this loan. +Capital Expenditures . Our recent +capital commitments have been primarily for the execution of our drilling programs, to fund Grizzly’s delineation drilling program and for acquisitions, primarily in the Permian Basin and the Niobrara Formation. Our strategy is to continue to +(1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, and (2) explore acquisition +and disposition opportunities. We have upgraded our infrastructure and our existing facilities in Southern Louisiana with the goal of increasing operating efficiencies and volume capacities and lowering lease operating expenses. These upgrades were +also intended to better enable our facilities to withstand future hurricanes with less damage. Additionally, we completed the reprocessing of 3-D seismic data in one of our principal properties, WCBB and shot 3-D seismic for the first time +52 +Table of Contents +in our Hackberry field. The new and reprocessed data enables our geophysicists to continue to generate new prospects and enhance existing prospects in the intermediate zones in the fields, thus +creating a portfolio of new drilling opportunities. In addition, with our acquisition of strategic assets in the Permian Basin in West Texas, we are required to pay 50% of all drilling costs for drilling activity on such properties. To combat +significant declines in the commodity prices during the second half of 2008, management undertook a series of actions aimed at reducing capital spending and operating costs. As a result, we reduced our drilling and other capital activities to a +minimum in the fourth quarter of 2008, releasing all rigs in Southern Louisiana and the Permian and only selectively participating in wells in the Bakken. During 2009, we were not bound by lease obligations and long term capital commitments relating +to the exploration or development of our oil and gas properties. As a result of the then current economic conditions, we initially reduced our estimated capital activities and aggressively sought price concessions from our service providers until +such time costs were reduced to more appropriate levels. In June 2009, we restarted our drilling programs. We commenced our 2010 drilling programs during March 2010. +In our December 31, 2010 reserve reports, 63% of our net reserves were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent +that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement +activities or use third parties to accomplish those activities. +Our inventory of prospects includes approximately 29 proved +undeveloped drilling locations at WCBB. The drilling schedule used in our December 31, 2010 reserve report anticipates that all of those wells will be drilled by 2013. During 2010, we recompleted 72 wells and drilled 23 wells, all of which were +completed as producers, at WCBB for an aggregate cost of $40.9 million. From January 1, 2011 through March 11, 2011, we recompleted twelve existing wells and drilled two wells at our WCBB field. We currently intend to spend a total of +approximately $36.0 to $38.0 million to drill 20 to 24 wells and recomplete 60 wells in our WCBB field during 2011. +In our +East Hackberry field, in 2010, we recompleted ten existing wells and drilled eight wells, all of which were completed as producers, for an aggregate cost of $20.0 million. From January 1, 2011 through March 11, 2011, we recompleted three +existing wells and drilled three wells, two of which are currently drilling, at our East Hackberry field. We currently intend to drill seven to ten wells and recomplete five wells in our East Hackberry field in 2011. Total capital expenditures for +our East Hackberry field during 2011 are estimated at $24.0 to $26.0 million. +In the Permian Basin, our booked inventory of +prospects includes 226 gross (113 net) future development drilling locations. During 2010, 25 gross (11 net) wells were drilled on this acreage, of which 24 gross (10.7 net) were completed as producers and one gross (0.5 net) well was waiting on +completion. Our aggregate capital expenditures in the Permian Basin were $29.0 million in 2010, which includes acreage acquisitions. From January 1, 2011 through March 11, 2011, four gross (two net) wells were recompleted and five gross +(2.5 net) wells were drilled on this acreage, three of which are waiting on completion and two of which are currently drilling. We currently anticipate that our capital requirements to drill a total of 40 to 42 gross (19 to 20 net) wells and +recomplete ten gross (five net) wells in the Permian Basin in West Texas will be approximately $37.0 to $39.0 million. +In the +Niobrara Formation in Western Colorado, effective April 1, 2010, we acquired leasehold interests for a total of approximately $7.6 million. In addition, we recompleted one existing well and acquired additional acreage for an aggregate +cost, including acquisition costs, of approximately $8.1 million in 2010. We are in the process of permitting a 60 square mile 3-D seismic survey and expect to begin shooting in mid-2011. We currently anticipate that our total capital +expenditures in the Niobrara Formation will be approximately $4.0 million in 2011 relating to the seismic survey and drilling of four to five gross wells. +53 +Table of Contents +During the third quarter of 2006, we purchased a 24.9999% interest in Grizzly. During 2010, +we paid Grizzly $3.7 million in cash calls. As of December 31, 2010, our net investment in Grizzly was approximately $26.5 million. In addition, we have loaned Grizzly $20.0 million including interest and net of foreign currency +adjustments as of December 31, 2010. Our capital requirements in 2011 for this project are currently estimated to be approximately $25.6 million, primarily for the expenses associated with the initial preparations of the Algar Lake SAGD +facility and planned drilling activity. +Capital expenditures in 2010 relating to our interest in Thailand were approximately +$400,000. Capital expenditures in 2011 relating to our interest in Thailand are expected to be approximately $1.0 million, which we believe will be mostly funded from our share of production from the Phu Horm field. +Our total capital expenditures for 2011 are currently estimated to be $127.0 million to $133.0 million, excluding our anticipated +acquisition in the Utica Shale. This is an increase from the $85.8 million spent in 2010 due to improved commodity pricing and cost environment. We intend to continue to monitor pricing and cost developments and make adjustments to our future +capital expenditure programs as warranted. +We believe that our cash on hand and cash flow from operations will be sufficient +to meet our normal recurring operating needs and our WCBB, Hackberry, Permian Basin, Niobrara and Grizzly capital requirements for the next twelve months. Although we currently anticipate significant free cash flow during 2011, in the event we elect +to further expand or accelerate our drilling programs, complete acquisitions (including our anticipated acquisition in the Utica Shale) or accelerate our Canadian oil sands project, we may be required to obtain additional funds which we would seek +to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. +If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. +Commodity Price Risk +The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any +certainty. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market +price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. On March 7, 2011, the West Texas Intermediate posted price for crude oil was +$105.44 per barrel and the Henry Hub spot market price of natural gas was $3.93 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of +expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price fluctuations, for the period January 2010 through February 2010, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per +day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per +day at a weighted average daily price of $58.24 per barrel, before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel, before +transportation costs and differentials, for the period January 2011 through December 2011. Under the 2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contacts, we have committed to deliver approximately 30% to +33% of our estimated 2011 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contracts and fixed +price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. +54 +Table of Contents +Commitments +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through +March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment +obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2010, the plugging and abandonment trust totaled approximately +$3,129,000. At December 31, 2010, we have plugged 311 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. +Contractual and Commercial Obligations +The following table sets forth our contractual and commercial obligations at December 31, 2010. +Payment due by period (1) +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +Short-term and long-term debt +$ +51,917,000 +$ +2,417,000 +$ +49,500,000 +$ +— +$ +— +Asset retirement obligations +10,845,000 +635,000 +1,334,000 +816,000 +8,060,000 +Total +$ +62,762,000 +$ +3,052,000 +$ +50,834,000 +$ +816,000 +$ +8,060,000 +(1) +Does not include estimated interest of $1,970,000 less than one year and $3,312,000 1-3 years and short-term derivative instruments of $4,720,000 less than one year. +New Accounting Pronouncements +In December 2008, the SEC published a final rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies +have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves. In addition, the new disclosure requirements require companies to +(a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average +price based upon the prior 12-month period rather than year end prices. The new requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted in quarterly +reports prior to the first annual report in which the revised disclosures are required. We adopted this final rule as of December 31, 2009. The adoption of the rule resulted in a lower price used in reserve calculations and a decrease in 2009 +reserves. Updated disclosures are included in Item 2. “Properties—Proved Oil and Natural Gas Reserves” and Note 21 to our consolidated financial statements included in this report. +In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” +(currently codified in FASB ASC Topic 932, “Extractive Activities – Oil & Gas”), or FASB ASC 932. The purpose of the amendments in this Update is to align the oil and gas reserve estimation and disclosure requirements of FASB +ASC 932 with the requirements in the SEC’s final rule, “Modernization of Oil and Gas Reporting . ” The amendments to FASB ASC 932 are effective for annual reports on Form 10-K for fiscal years ending on or after +December 31, 2009. We adopted FASB ASC 932 effective December 31, 2009, the impact of which is noted above. +In +January 2010, the FASB issued Accounting Standards Update 2010-06, “Improving Disclosures about Fair Value Measurements,” which provides amendments to FASB ASC Topic 820, “Fair Value Measurements and Disclosure,” (FASB ASC 820). +FASB ASC 820 requires additional disclosures about (a) the different classes +55 +Table of Contents +of assets and liabilities measured at fair value, (b) the valuation techniques and inputs used, (c) the activity in Level 3 fair value measurements, and (d) significant transfers +between Levels 1, 2 and 3. The updated guidance is effective for annual and interim periods beginning after December 15, 2009. We adopted FASB ASC 820 effective January 1, 2010. The adoption did not have a material impact on our +consolidated financial statements. +In December 2010, the FASB issued Accounting Standards Update 2010-29, “Business +Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (currently codified in FASB ASC Topic 805, “ Business Combinations”), or FASB ASC 805. The purpose of the amendments in this update is to +specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination that occurred during the current year had occurred as of the +beginning of the comparable prior annual reporting period only. The amendments in this update also expand the supplemental pro forma disclosures under FASB ASC 805 to include a description of the nature and amount of material, nonrecurring pro forma +adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments to FASB ASC 805 are effective prospectively for business combinations for which the acquisition date is on or after +the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption did not have an immediate impact on our consolidated financial statements. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. +Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and +natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather +conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with +operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree +to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the +West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per +million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. On March 7, 2011, the West Texas Intermediate posted price for crude oil was $105.44 per barrel and the Henry Hub spot market price of +natural gas was $3.93 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas +reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +For the period +January 2010 through February 2010, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials. For the +period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before transportation costs and differentials. In +November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel, before transportation costs and differentials, for the period January 2011 through December 2011. Under the 2010 +contracts, we +56 +Table of Contents +delivered approximately 45% of our 2010 production. Under the 2011 contracts, we have committed to deliver approximately 30% to 33% of our estimated 2011 production. Such arrangements may expose +us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair +value pursuant to FASB ASC 815 and related pronouncements. At December 31, 2010, we had a net liability derivative position of $4.7 million related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in +underlying commodity prices would have reduced the fair value of these instruments by approximately $6.8 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by $6.8 million. However, +any realized derivative gain or loss would be substantially offset by a decrease of increase, respectively, in the actual sales value of production covered by the derivative instrument. +Our new revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either +base rate loans or Eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the Eurodollar rates are elected, the Eurodollar rates. At December 31, 2010, amounts borrowed under our new +revolving credit agreement bore interest at the Eurodollar rate of 3.77%. Based on the current debt structure, a 1% increase in interest rates would increase interest expense by approximately $495,000 per year, based on $49.5 million outstanding +under our credit facility as of December 31, 2010. As of December 31, 2010, we did not have any interest rate swaps to hedge our interest risks. +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief +Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, +processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including +our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. +As of December 31, 2010, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial +Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President +and Chief Financial Officer have concluded that as of December 31, 2010, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have +materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +57 +Table of Contents +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is +also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are +designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent +limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with +respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control +over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal +Control—Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2010. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year +ended December 31, 2010 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2010, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +58 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport +Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the +“Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The +Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s +Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material +weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting +includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with +authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material +effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control +over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as +of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010 and our report +dated March 14, 2011 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 14, 2011 +ITEM 9B. +OTHER INFORMATION +None. +59 +Table of Contents +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission +within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning Item 11—Executive Compensation, see our definitive proxy statement, which will be filed with the +Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder +Matters, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions +noted therein that are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and +Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For information concerning Item 14—Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after +the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +60 +Table of Contents +PART IV +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +List the following documents filed as part of this report: +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor +Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party +seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the +SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, +2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the +Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with +the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a +Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other +Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, +certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +61 +Table of Contents +Exhibit +Number +Description +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.5 +of Amendment No. 1 to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5+ +Summary of Oral Employment Agreement with James D. Palm (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December +7, 2010). +10.5 +Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead +arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). +10.6 +Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Pinnacle Energy Services, LLC. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +62 +Table of Contents +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the +undersigned, thereunto duly authorized. +Date: March 14, 2011 +G ULFPORT E NERGY C ORPORATION +By: +/s/ JAMES D. +PALM +James D. Palm +Chief Executive Officer +In accordance with the +Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Date: March 14, 2011 +By: +/s/ JAMES D. +PALM +James D. Palm +Chief Executive Officer and Director +(Principal Executive +Officer) +Date: March 14, 2011 +By: +/s/ MIKE +LIDDELL +Mike Liddell +Chairman of the Board and Director +Date: March 14, 2011 +By: +/s/ MICHAEL G. +MOORE +Michael G. Moore +Vice President and Chief Financial Officer +(Principal Financial and +Accounting Officer) +Date: March 14, 2011 +By: +/s/ DONALD +DILLINGHAM +Donald Dillingham +Director +Date: March 14, 2011 +By: +/s/ DAVID L. +HOUSTON +David L. Houston +Director +Date: March 14, 2011 +By: +/s/ SCOTT E. +STRELLER +Scott E. Streller +Director +S-1 +Table of Contents +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets, December 31, 2010 and December 31, 2009 +F-3 +Consolidated Statements of Operations, Years Ended December 31, 2010, 2009 and +2008 +F-4 +Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss), Years Ended December 31, +2010, 2009 and 2008 +F-5 +Consolidated Statements of Cash Flows, Years Ended December 31, 2010, 2009 and +2008 +F-6 +Notes to Financial Statements +F-7 +F-1 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated +statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s +management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in +accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of +material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates +made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation and Subsidiaries as of +December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of +America. +As discussed in Note 1, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gulfport Energy +Corporation and Subsidiaries’ internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of +the Treadway Commission (COSO) and our report dated March 14, 2011 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 14, 2011 +F-2 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +(Amounts rounded to nearest thousand) +December 31, +December 31, +2010 +2009 +Assets +Current assets: +Cash and cash equivalents +$ +2,468,000 +$ +1,724,000 +Accounts receivable—oil and gas +14,952,000 +9,492,000 +Accounts receivable—related parties +573,000 +136,000 +Prepaid expenses and other current assets +1,732,000 +2,047,000 +Total current assets +19,725,000 +13,399,000 +Property and equipment: +Oil and natural gas properties, full-cost accounting, $16,778,000 and $17,521,000 excluded from amortization in 2010 and 2009, +respectively +747,344,000 +628,849,000 +Other property and equipment +7,609,000 +7,182,000 +Accumulated depletion, depreciation, amortization and impairment +(512,822,000 +) +(473,915,000 +) +Property and equipment, net +242,131,000 +162,116,000 +Other assets: +Equity investments +33,021,000 +32,006,000 +Note receivable—related party +20,006,000 +15,920,000 +Other assets +4,182,000 +3,370,000 +Total other assets +57,209,000 +51,296,000 +Deferred tax asset +628,000 +533,000 +Total assets +$ +319,693,000 +$ +227,344,000 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +41,155,000 +$ +20,977,000 +Asset retirement obligation—current +635,000 +635,000 +Short-term derivative instruments +4,720,000 +18,735,000 +Current maturities of long-term debt +2,417,000 +2,842,000 +Total current liabilities +48,927,000 +43,189,000 +Asset retirement obligation—long-term +10,210,000 +9,518,000 +Long-term debt, net of current maturities +49,500,000 +49,586,000 +Total liabilities +108,637,000 +102,293,000 +Commitments and contingencies (Notes 18 and 19) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; +0 issued and outstanding +— +— +Stockholders' equity: +Common stock—$.01 par value, 100,000,000 authorized, 44,645,435 issued and outstanding in 2010 and 42,696,409 in +2009 +446,000 +427,000 +Paid-in capital +296,253,000 +273,901,000 +Accumulated other comprehensive income (loss) +(1,768,000 +) +(18,039,000 +) +Retained earnings (accumulated deficit) +(83,875,000 +) +(131,238,000 +) +Total stockholders' equity +211,056,000 +125,051,000 +Total liabilities and stockholders' equity +$ +319,693,000 +$ +227,344,000 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2010 +2009 +2008 +Revenues: +Oil and condensate sales +$ +121,350,000 +$ +81,587,000 +$ +131,825,000 +Gas sales +3,468,000 +1,992,000 +6,570,000 +Natural gas liquid sales +2,818,000 +1,997,000 +3,255,000 +Other income (expense) +(692,000 +) +(314,000 +) +(433,000 +) +126,944,000 +85,262,000 +141,217,000 +Costs and expenses: +Lease operating expenses +17,614,000 +16,316,000 +22,856,000 +Production taxes +13,966,000 +9,797,000 +15,813,000 +Depreciation, depletion, and amortization +38,907,000 +29,225,000 +42,472,000 +Impairment of oil and gas properties +— +— +272,722,000 +General and administrative +6,063,000 +4,992,000 +6,843,000 +Accretion expense +617,000 +582,000 +560,000 +77,167,000 +60,912,000 +361,266,000 +INCOME (LOSS) FROM OPERATIONS +49,777,000 +24,350,000 +(220,049,000 +) +OTHER (INCOME) EXPENSE: +Interest expense +2,761,000 +2,309,000 +4,762,000 +Settlement of fixed price contracts +— +— +(39,000,000 +) +Insurance proceeds +— +(1,050,000 +) +(769,000 +) +Interest income +(387,000 +) +(564,000 +) +(540,000 +) +2,374,000 +695,000 +(35,547,000 +) +INCOME (LOSS) BEFORE INCOME TAXES +47,403,000 +23,655,000 +(184,502,000 +) +INCOME TAX EXPENSE +40,000 +28,000 +— +NET INCOME (LOSS) +$ +47,363,000 +$ +23,627,000 +$ +(184,502,000 +) +NET INCOME (LOSS) PER COMMON SHARE: +Basic +$ +1.08 +$ +0.55 +$ +(4.33 +) +Diluted +$ +1.07 +$ +0.55 +$ +(4.33 +) +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS) +(Amounts rounded to nearest thousand) +Common Stock +Additional +Paid-in +Capital +Accumulated +Other +Comprehensive +Income (Loss) +Retained +Earnings +(Accumulated +Deficit) +Total +Stockholders' +Equity +Shares +Amount +Balance at January 1, 2008 +42,453,587 +$ +424,000 +$ +271,807,000 +$ +2,254,000 +$ +29,637,000 +$ +304,122,000 +Net loss +— +— +— +— +(184,502,000 +) +(184,502,000 +) +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +(7,057,000 +) +— +(7,057,000 +) +Total Comprehensive Income (Loss) +(191,559,000 +) +Stock Compensation +— +— +1,056,000 +— +— +1,056,000 +Issuance of Restricted Stock +41,493 +— +— +— +— +— +Issuance of Common Stock through exercise of options +144,121 +2,000 +480,000 +— +— +482,000 +Balance at December 31, 2008 +42,639,201 +426,000 +273,343,000 +(4,803,000 +) +(154,865,000 +) +114,101,000 +Net income +— +— +— +— +23,627,000 +23,627,000 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +5,499,000 +— +5,499,000 +Change in fair value of derivative instruments +— +— +— +(13,422,000 +) +— +(13,422,000 +) +Reclassification of derivative contracts +— +— +— +(5,313,000 +) +— +(5,313,000 +) +Total Comprehensive Income (Loss) +10,391,000 +Stock Compensation +— +— +529,000 +— +— +529,000 +Issuance of Restricted Stock +43,458 +— +— +— +— +— +Issuance of Common Stock through exercise of options +13,750 +1,000 +29,000 +— +— +30,000 +Balance at December 31, 2009 +42,696,409 +427,000 +273,901,000 +(18,039,000 +) +(131,238,000 +) +125,051,000 +Net income +— +— +— +— +47,363,000 +47,363,000 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +2,255,000 +— +2,255,000 +Change in fair value of derivative instruments +— +— +— +(4,720,000 +) +— +(4,720,000 +) +Reclassification of derivative contracts +— +— +— +18,736,000 +— +18,736,000 +Total Comprehensive Income (Loss) +63,634,000 +Stock Compensation +— +— +492,000 +— +— +492,000 +Issuance of Common Stock in public offering, net of related expenses of $210,000 +1,668,503 +17,000 +21,341,000 +— +— +21,358,000 +Issuance of Common Stock through exercise of warrants +173,109 +2,000 +204,000 +— +— +206,000 +Issuance of Restricted Stock +58,525 +— +— +— +— +— +Issuance of Common Stock through exercise of options +48,889 +— +315,000 +— +— +315,000 +Balance at December 31, 2010 +44,645,435 +$ +446,000 +$ +296,253,000 +$ +(1,768,000 +) +$ +(83,875,000 +) +$ +211,056,000 +See accompanying notes to consolidated financial statements. +F-5 +Table of Contents +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOW +(Amounts rounded to nearest thousand) +Year Ended December 31, +2010 +2009 +2008 +Cash flows from operating activities: +Net income (loss) +$ +47,363,000 +$ +23,627,000 +$ +(184,502,000 +) +Adjustments to reconcile net income (loss) to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +617,000 +582,000 +560,000 +Depletion, depreciation and amortization +38,907,000 +29,225,000 +42,472,000 +Impairment of oil and gas properties +— +272,722,000 +Stock-based compensation expense +295,000 +317,000 +634,000 +Loss from equity investments +977,000 +706,000 +656,000 +Interest income—note receivable +(267,000 +) +(547,000 +) +(410,000 +) +Deferred income tax benefit +(95,000 +) +120,000 +(653,000 +) +Changes in operating assets and liabilities: +(Increase) decrease in accounts receivable +(5,460,000 +) +3,051,000 +(2,033,000 +) +(Increase) decrease in accounts receivable—related party +(437,000 +) +965,000 +1,107,000 +Decrease (increase) in prepaid expenses +315,000 +(1,002,000 +) +301,000 +Increase in other asset +(75,000 +) +— +— +Increase (decrease) in accounts payable and accrued liabilities +4,948,000 +(3,686,000 +) +5,328,000 +Settlement of asset retirement obligation +(1,253,000 +) +(59,000 +) +(859,000 +) +Net cash provided by operating activities +85,835,000 +53,299,000 +135,323,000 +Cash flows from investing activities: +Deductions (additions) to cash held in escrow +8,000 +8,000 +(40,000 +) +Additions to other property, plant and equipment +(427,000 +) +(14,000 +) +(60,000 +) +Additions to oil and gas properties +(101,644,000 +) +(49,533,000 +) +(126,030,000 +) +Proceeds from sale of oil and gas properties +304,000 +18,286,000 +— +Advances on note receivable to related party +(2,877,000 +) +(4,377,000 +) +(10,519,000 +) +Contributions to investment in Grizzly Oil Sands ULC +(842,000 +) +— +(151,000 +) +Distributions from investment in Tatex Thailand II, LLC +565,000 +197,000 +862,000 +Contributions to investment in Tatex Thailand III, LLC +(402,000 +) +(3,813,000 +) +(885,000 +) +Net cash used in investing activities +(105,315,000 +) +(39,246,000 +) +(136,823,000 +) +Cash flows from financing activities: +Principal payments on borrowings +(52,711,000 +) +(18,303,000 +) +(25,802,000 +) +Borrowings on line of credit +52,200,000 +— +30,000,000 +Loan commitment fees +(1,144,000 +) +— +— +Proceeds from issuance of common stock, net of offering costs of $210,000 for 2010, and exercise of stock options +21,879,000 +30,000 +482,000 +Net cash provided by (used in) financing activities +20,224,000 +(18,273,000 +) +4,680,000 +Net (decrease) increase in cash and cash equivalents +744,000 +(4,220,000 +) +3,180,000 +Cash and cash equivalents at beginning of period +1,724,000 +5,944,000 +2,764,000 +Cash and cash equivalents at end of period +$ +2,468,000 +$ +1,724,000 +$ +5,944,000 +Supplemental disclosure of cash flow information: +Interest payments +$ +1,949,000 +$ +2,300,000 +$ +4,898,000 +Income tax payments +$ +40,000 +$ +543,000 +$ +135,000 +Supplemental disclosure of non-cash transactions: +Capitalized stock based compensation +$ +197,000 +$ +212,000 +$ +422,000 +Asset retirement obligation capitalized +$ +1,328,000 +$ +361,000 +$ +934,000 +Dissolution of interest in Windsor Bakken, LLC +$ +— +$ +— +$ +2,468,000 +Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC +$ +1,313,000 +$ +3,656,000 +$ +(5,281,000 +) +Foreign currency translation gain (loss) on note receivable—related party +$ +942,000 +$ +1,843,000 +$ +(1,776,000 +) +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy +Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production company with its principal properties located in the Louisiana Gulf Coast, in West Texas in the Permian Basin and in +Western Colorado in the Niobrara Formation and has investments in companies operating in Canada and Thailand. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original maturity of three months or less to be cash +equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, +Gator Marine, Inc., Gator Marine Ivanhoe, Inc. and Puma Resources, Inc. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The Company’s accounts receivable—oil and +gas primarily are from companies in the oil and gas industry. The majority of its receivables are from two purchasers of the Company’s oil and gas and one operator of certain of the Company’s properties. Credit is extended based on +evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes +collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, +the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and +the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed +necessary at December 31, 2010 and December 31, 2009. +Oil and Gas Properties +The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and +certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting, the Company is required to perform a ceiling test each +quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is +defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for 2010 and 2009, and prior to 2009, unescalated +year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement +F-7 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost +being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown +is required. +Such capitalized costs, including the estimated future development costs and site remediation costs of proved +undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such +dispositions significantly alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $16,778,000 and $17,521,000 at +December 31, 2010 and December 31, 2009, respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and +gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for +exploration and development. +The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, +“ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is +recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas +properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of +the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment is provided on a straight-line basis over estimated useful lives of the related assets, which range from 3 to 30 years. +Foreign Currency +The +U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian +investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on +net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive +income. +December 31, 2007 +$ +2,254,000 +December 31, 2008 +$ +(4,803,000 +) +December 31, 2009 +$ +696,000 +December 31, 2010 +$ +2,952,000 +F-8 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Net Income per Common Share +Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common +shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are +not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 13. +Income Taxes +Gulfport +uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and +the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are +expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which +realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. +The company adopted the provisions of FASB ASC Topic 740 as of January 1, 2007. The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s +1996 – 2009 U.S. federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2010, the Company has no unrecognized tax benefits that would have a material impact on +the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended December 31, 2010, there is no interest or penalties +associated with uncertain tax positions in the Company’s consolidated financial statements. +Revenue Recognition +Gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production +volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. There is no such liability or +asset recorded at December 31, 2010 and 2009 because the Company has no imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month produced. +Investments—Equity Method +Investments in entities greater than 20% +and less than 50% are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a +loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. There was no impairment of equity method investments at December 31, 2010 or 2009. +F-9 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Accounting for Stock-Based Compensation +The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, +“ Compensation—Stock Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options, to be recognized as equity or liabilities at the fair value +on the date of grant and to be expensed over the applicable vesting period. +Accounting for Derivative Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or +fixed-price contracts. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in +the statement of financial position, measured at fair value. +The Company estimates the fair value of all derivative +instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values +reported in the consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but +re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized +in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized +immediately in earnings. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that +affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to +these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred +tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment +of oil and gas properties. +Recent Accounting Pronouncements +In December 2008, the Securities and Exchange Commission published a Final Rule, “ Modernization of Oil and Gas Reporting .” The new rule permits the use of new technologies to determine +proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also will allow companies to disclose their probable and possible reserves. In addition, the new disclosure +requirements require companies to (a) report the independence and qualifications of its reserve +F-10 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average price based +upon the prior 12 month period rather than year end prices. The new requirements were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company adopted the Final Rule as of December 31, +2009. The adoption of the rule resulted in a lower price used in reserve calculations and a decrease in 2009 reserves. See Item 2. Properties and Note 21 for further discussion of the impact of implementation. +In January 2010, the FASB issued Accounting Standards Update 2010-03, “ Oil and Gas Reserve Estimation and Disclosures ” +(currently codified in FASB ASC Topic 932, “ Extractive Activities – Oil & Gas ”) (“FASB ASC 932”). The purpose of the amendments in this Update is to align the oil and gas reserve estimation and disclosure +requirements of FASB ASC 932 with the requirements in the Security and Exchange Commission’s Final Rule, “ Modernization of Oil and Gas Reporting. ” The amendments to FASB ASC 932 are effective for annual reports on Form 10-K for +fiscal years ending on or after December 31, 2009. The impact of the adoption of FASB ASC 932 is noted above. +In January +2010, the FASB issued Accounting Standards Update 2010-06, “ Improving Disclosures about Fair Value Measurements, ” which provides amendments to FASB ASC Topic 820, “ Fair Value Measurements and Disclosure” (“FASB +ASC 820”). FASB ASC 820 requires additional disclosures about (a) the different classes of assets and liabilities measured at fair value, (b) the valuation techniques and inputs used, (c) the activity in Level 3 fair value +measurements, and (d) significant transfers between Levels 1, 2 and 3. The updated guidance is effective for annual and interim periods beginning after December 15, 2009. The Company adopted FASB ASC 820 effective January 1, 2010. The +adoption did not have a material impact on the Company’s consolidated financial statements. +In December 2010, the FASB +issued Accounting Standards Update 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (currently codified in FASB ASC Topic 805, “Business Combinations” ) +(“FASB ASC 805”). The purpose of the amendments in this update is to specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business +combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments in this update also expand the supplemental pro forma disclosures under FASB ASC 805 to include a +description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments to FASB ASC 805 are effective +prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption did not have an immediate impact on the +Company’s consolidated financial statements. +2. +ACQUISITIONS +On +June 15, 2010, Gulfport acquired an ownership interest in certain oil and gas properties located in the Niobrara Formation of Colorado, including three gross producing wells for a cash price of approximately $7.75 million. The effective date of +the acquisition was April 1, 2010. The total purchase price for the acquired assets, as adjusted at closing on June 15, 2010, was $7.7 million, which was recorded as oil and natural gas properties on the accompanying December 31, 2010 +consolidated balance sheet. This amount includes an adjustment for the results of operations of the assets between the April 1, 2010 effective date and the June 15, 2010 closing date. The Company may adjust the purchase price for any post +closing adjustments. The results of operations from +F-11 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +these properties were included in the December 31, 2010 consolidated statement of operations for the period from June 16, 2010 through December 31, 2010. No pro forma financials +for this acquisition are disclosed as the acquisition was not deemed significant to the Company. +During May 2010, Gulfport +acquired a 50% interest in 4,979 gross (2,489 net) undeveloped acres in the Permian Basin for approximately $7.6 million. +Gulfport funded these transactions predominately through a 1.7 million common share offering completed in May of 2010. The Company +received net proceeds (before offering expenses) of approximately $21.6 million from the equity offering, as discussed below in Note 8. +3. +ACCOUNTS RECEIVABLE—RELATED PARTIES +Included in the accompanying December 31, 2010 and December 31, 2009 consolidated balance sheets are amounts receivable from related parties of the Company. These receivables represent amounts +billed by the Company for general and administrative functions, such as accounting, human resources, legal, and technical support, performed by Gulfport’s personnel on behalf of these related parties. These services are solely administrative in +nature and for entities in which the Company has no property interests. The amounts reimbursed to the Company for these services are for the purpose of Gulfport recovering costs associated with the services and do not include the assessment of any +fees or other amounts beyond the estimated costs of performing such services. At December 31, 2010 and December 31, 2009, these receivables totaled $573,000 and $136,000, respectively. The Company recorded $593,000 and $1,363,000 for the +years ended December 31, 2009 and 2008, respectively, for general and administrative functions which are reflected as a reduction of general and administrative expenses in the consolidated statements of operations and include the amounts under +service contracts discussed below. No amounts were reimbursed for general and administrative functions for the year ended December 31, 2010. +The Company is or has been a party to administrative service agreements with Caliber Development Company, LLC, Great White Energy Services LLC, and Diamondback Energy Services LLC. Under these agreements, +the Company’s services include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has +a three-year term, and upon expiration of that term the agreements will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. Each administrative service agreement is terminable (1) by +the counterparty at any time with at least 30 days prior written notice to the Company and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such +breach. +The Company is also a party to administrative service agreements with Stampede Farms LLC, Grizzly Oil Sands ULC, +Everest Operations Management LLC and Tatex Thailand III, LLC. Under these agreements, the Company’s services include professional and technical support and office space. The services provided and the fees for such services can be amended by +mutual agreement of the parties. Each of these administrative service agreements has a two-year term, and upon expiration of that term such agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at +least 60 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to the Company and (2) by either party if the other party is in material +breach and such breach has not been cured within 30 days of receipt of written notice of such breach. +F-12 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +The Company was reimbursed the following +amounts by the specified entities in consideration for its administrative services for the years ended December 31, 2010, 2009 and 2008. These amounts are reflected as a reduction of general and administrative expenses in the consolidated +statements of operations. Wexford Capital LP (“Wexford”) controls and/or owns a greater than 10% interest in each of these entities. Affiliates of Wexford own approximately 25% of Gulfport’s outstanding stock. +Agreement +Effective Date +December 31, +Entity +2010 +2009 +2008 +2/9/2005 +Caliber Development Company, LLC* +$ +— +$ +— +$ +60,000 +7/22/2006 +Great White Energy Services LLC +— +61,000 +83,000 +9/26/2006 +Diamondback Energy Services LLC* +— +— +10,000 +3/1/2008 +Stampede Farms LLC +— +— +159,000 +3/1/2008 +Grizzly Oil Sands ULC ** +— +20,000 +368,000 +3/1/2008 +Everest Operations Management LLC +— +508,000 +154,000 +3/1/2008 +Tatex Thailand III, LLC +— +— +— +* +Agreement was terminated effective December 10, 2008. +** +Agreement was terminated effective December 31, 2010. +For the year ended December 31, 2009, the Company was also reimbursed approximately $2,000 and $1,000 by Stampede Farms LLC and Everest Operations Management LLC, respectively, and approximately +$20,000 and $26,000, respectively, for the year ended December 31, 2008, for office space under the administrative service agreements, which is included in other income (expense) in the consolidated statements of operations. For the year ended +December 31, 2010, the Company was reimbursed approximately $20,000 by Orange Leaf Holdings, LLC, an affiliate of Gulfport, for office space which is included in other income (expense) in the consolidated statements of operations. +Effective July 1, 2008, the Company entered into an acquisition team agreement with Everest Operations Management LLC +(“Everest”) to identify and evaluate potential oil and gas properties in which the Company and Everest may wish to invest. Upon a successful closing of an acquisition or divestiture, the party identifying the acquisition or divestiture is +entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or divestiture consideration. The agreement may be +terminated by either party upon 30 days notice. +Effective April 1, 2010, the Company entered into an area of mutual +interest agreement with Windsor Niobrara LLC (“Windsor Niobrara”), an entity controlled by Wexford, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, exploiting and producing +oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50%/50% basis. The parties also agreed, subject to certain exceptions, to share third-party +costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, Gulfport and Windsor Niobrara also entered into a development agreement, +effective as of April 1, 2010, pursuant to which the Company and Windsor Niobrara agreed to jointly develop the contract area, and Gulfport agreed to act as the operator under the terms of a joint operating agreement. +F-13 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +4. +PROPERTY AND EQUIPMENT +The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of +December 31, 2010 and 2009 are as follows: +December 31, +2010 +2009 +Oil and natural gas properties +$ +747,344,000 +$ +628,849,000 +Office furniture and fixtures +3,277,000 +2,996,000 +Building +4,049,000 +3,926,000 +Land +283,000 +260,000 +Total property and equipment +754,953,000 +636,031,000 +Accumulated depletion, depreciation, amortization and impairment +(512,822,000 +) +(473,915,000 +) +Property and equipment, net +$ +242,131,000 +$ +162,116,000 +At December 31, 2008, the net book value of the Company’s oil and natural gas properties, less +related deferred income taxes, was above the calculated ceiling as a result of reduced commodity prices at December 31, 2008. As a result, the Company was required to record an impairment of its oil and natural gas properties under the full +cost method of accounting in the amount of $272.7 million for the year ended December 31, 2008. No impairment of oil and natural gas properties was required for the years ended December 31, 2010 and December 31, 2009. +Included in oil and natural gas properties at December 31, 2010 and December 31, 2009 is the cumulative capitalization of +$18,126,000 and $14,009,000, respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred +directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with +exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $4,117,000, $3,395,000 and $4,645,000 for the years ended December 31, 2010, 2009 and 2008, +respectively. +The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of +December 31, 2010: +Costs Incurred in +2010 +2009 +2008 +Prior to 2008 +Total +Acquisition costs +$ +9,950,000 +$ +1,163,000 +$ +5,000 +$ +638,000 +$ +11,756,000 +Exploration costs +2,692,000 +155,000 +1,069,000 +1,106,000 +5,022,000 +Development costs +— +— +— +— +— +Total oil and gas properties not subject to amortization +$ +12,642,000 +$ +1,318,000 +$ +1,074,000 +$ +1,744,000 +$ +16,778,000 +At December 31, 2010, approximately $5,022,000 of oil and gas properties related to the Company’s +Belize properties is excluded from amortization as it relates to non-producing properties. In addition, approximately +F-14 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +$8,595,000 of non-producing leasehold costs resulting from the Company’s acquisition of West Texas Permian properties, $301,000 of non-producing leasehold costs related to the Company’s +Bakken properties and $1,727,000 of non-producing leasehold costs related to the Company’s Colorado properties are excluded from amortization at December 31, 2010. Approximately $1,089,000 of non-producing leasehold costs related to the +Company’s Southern Louisiana assets and $44,000 of non-producing leasehold costs related to other projects are also excluded from amortization. At December 31, 2009, approximately $17,521,000 of non-producing leasehold costs was not +subject to amortization. +The Company evaluates the costs excluded from its amortization calculation at least annually. +Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to occur within three to five years. +A reconciliation of the asset retirement obligation for the years ended December 31, 2010 and 2009 is as follows: +December 31, +2010 +2009 +Asset retirement obligation, beginning of period +$ +10,153,000 +$ +9,269,000 +Liabilities incurred +1,328,000 +361,000 +Liabilities settled +(1,253,000 +) +(59,000 +) +Accretion expense +617,000 +582,000 +Asset retirement obligation as of end of period +10,845,000 +10,153,000 +Less current portion +635,000 +635,000 +Asset retirement obligation, long-term +$ +10,210,000 +$ +9,518,000 +5. +EQUITY INVESTMENTS +Investments accounted for by the equity method consist of the following as of December 31, 2010 and 2009: +December 31, +2010 +2009 +Investment in Tatex Thailand II, LLC +$ +1,907,000 +$ +2,485,000 +Investment in Tatex Thailand III, LLC +4,660,000 +4,482,000 +Investment in Grizzly Oil Sands ULC +26,454,000 +25,039,000 +$ +33,021,000 +$ +32,006,000 +Tatex Thailand II, LLC +During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by +Wexford. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of +concessions covering approximately two million acres which includes the Phu Horm Field. During 2010, Gulfport received $565,000 in distributions, reducing its total investment in Tatex (including previous investments) to $1,907,000. The loss on +equity investment related to Tatex was immaterial for the years ended December 31, 2010, 2009 and 2008. +F-15 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Tatex Thailand III, LLC +During the first quarter of 2008, the Company purchased a 5% ownership interest in Tatex Thailand III, LLC (“Tatex III”) at a +cost of $850,000. In December 2009, the Company purchased an additional approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing its total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2010, Gulfport paid $402,000 in cash calls, bringing its total investment in Tatex III to $4,660,000. The Company recognized a loss on equity +investment of $224,000, $207,000 and $9,000 for the years ended December 31, 2010, 2009 and 2008, respectively, which is included in other income (expense) in the consolidated statements of operations. +Grizzly Oil Sands ULC +During the third quarter of 2006, the Company, through its wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in +Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company, for approximately $8.2 million. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the +Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has drilled core holes and water supply test wells in nine separate lease blocks for feasibility of oil production and conducted a +seismic program, but has not commenced development of operations. As of December 31, 2010 and 2009, Gulfport’s net investment in Grizzly was $26,454,000 and $25,039,000, respectively. Grizzly’s functional currency is the Canadian +dollar. The Company’s investment in Grizzly was increased by $1,313,000 and $3,656,000 as a result of a currency translation gain for the years ended December 31, 2010 and 2009. The Company recognized a loss on equity investment of +$740,000, $498,000 and $639,000 for the years ended December 31, 2010, 2009 and 2008, respectively, which is included in other income (expense) in the consolidated statements of operations. +The Company, through its wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective +January 1, 2008, under which Grizzly may borrow funds from the Company. Borrowed funds initially bore interest at LIBOR plus 400 basis points and had an original maturity date of December 31, 2012. Effective April 1, 2010, the loan +agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan agreement was further amended to change the maturity date to the original maturity date of +December 31, 2012. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The Company loaned Grizzly approximately $2,877,000 during the year ended December 31, 2010. The Company recognized interest +income of approximately $267,000, $547,000 and $410,000 for the years ended December 31, 2010, 2009 and 2008, respectively, which is included in interest income in the consolidated statements of operations. The note balance was increased by +approximately $942,000 and $1,843,000 as a result of a currency translation gain for the years ended December 31, 2010 and 2009, respectively. The total $20,006,000 due from Grizzly is included in note receivable—related party on the +accompanying consolidated balance sheets. +F-16 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +The table below summarizes financial +information for Grizzly as of December 31, 2010, 2009 and 2008: +December 31, +2010 +2009 +2008 +Current assets +$ +3,277,000 +$ +2,064,000 +$ +1,481,000 +Noncurrent assets +$ +188,786,000 +$ +164,043,000 +$ +125,024,000 +Current liabilities +$ +3,708,000 +$ +1,585,000 +$ +2,663,000 +Noncurrent liabilities +$ +81,089,000 +$ +64,365,000 +$ +36,397,000 +Gross revenue +$ +— +$ +— +$ +— +Loss from continuing operations +$ +3,234,000 +$ +1,992,000 +$ +2,595,000 +Net loss +$ +3,234,000 +$ +1,991,000 +$ +2,557,000 +6. +OTHER ASSETS +Other +assets consist of the following as of December 31, 2010 and 2009: +December 31, +2010 +2009 +Plugging and abandonment escrow account on the WCBB properties (Note 18) +$ +3,129,000 +$ +3,136,000 +Certificates of Deposit securing letter of credit +275,000 +200,000 +Prepaid drilling costs +7,000 +30,000 +Loan commitment fees +767,000 +— +Deposits +4,000 +4,000 +$ +4,182,000 +$ +3,370,000 +7. +LONG-TERM DEBT +A +break-down of long-term debt as of December 31, 2010 and 2009 is as follows: +December 31, +2010 +2009 +Revolving credit agreement (1) +$ +49,500,000 +$ +45,000,000 +Term loans (1) +— +4,903,000 +Building loans (2) +2,417,000 +2,525,000 +Less: current maturities of long term debt +(2,417,000 +) +(2,842,000 +) +Debt reflected as long term +$ +49,500,000 +$ +49,586,000 +Maturities of long-term debt as of December 31, 2010 are as follows: +2011 +$ +2,417,000 +2012 +— +2013 +49,500,000 +2014 +— +2015 +— +Thereafter +— +Total +$ +51,917,000 +F-17 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +(1) In March 2005, Gulfport entered +into a three-year secured credit agreement with Bank of America, N.A. providing for a revolving credit facility. The credit agreement was subsequently amended and restated from time to time and, among other things, the maturity date was extended to +April 1, 2011. Borrowings under the revolving credit facility were subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. Effective July 19, 2007, the credit facility was increased to +$150.0 million and effective December 20, 2007, the amount available under the borrowing base limitation was increased to $90.0 million. +On August 31, 2009, the lender completed its periodic redetermination of the Company’s borrowing base giving consideration to the Company’s year-end 2008 and mid-year 2009 reserve +information and the lender’s then current pricing decks, among other factors. As a result of this redetermination, the Company’s available borrowing base was reset at $45.0 million, primarily in response to significant declines in +commodity prices. The Company’s outstanding principal balance at the effective time of this redetermination was approximately $59.0 million. The approximately $14.0 million of outstanding borrowings under the credit facility in excess of the +new borrowing base was converted into a term loan as of August 31, 2009. An initial $2.0 million payment was made on the term loan at that time and the Company agreed to make additional monthly payments of $1.0 million commencing on +September 30, 2009, with all unpaid amounts due on March 31, 2010. The Company paid the outstanding balance of the term loan in full in February 2010. +Outstanding borrowings under the term loan accrued interest at the Eurodollar rate (as defined in the credit agreement) plus 4.0% or, at the option of the Company, at the base rate (which was the highest +of the lender’s prime rate, the Federal funds rate plus half of 1%, and the one-month Eurodollar rate plus 1%) plus 3%. Effective August 31, 2009, the Company also agreed to an adjustment in the commitment fees, interest rates for +revolving loans and fees for letters of credit under the credit facility. Specifically, the Company agreed to pay (a) commitment fees ranging from 0.5% to 0.625% (an increase from 0.15% to 0.25%), (b) margin interest rates ranging from +2.75% to 3.50% for Eurodollar loans (an increase from 1.25% to 2.0%), (c) margin interest rates ranging from 1.75% to 2.5% for base rate loans (an increase from 1.25% to 2.0%), and (d) letter of credit fees at the margin interest rates for +Eurodollar loans, in each case based on the Company’s utilization percentage. In addition, the Company agreed to limitations on certain dispositions and investments and to mandatory prepayments of the loans from the net cash proceeds of +specified asset sales and other events. +The Company’s obligations under the credit facility were collateralized by a +lien on substantially all of the Company’s Louisiana and West Texas assets and were guaranteed by its subsidiaries. The restated credit agreement contained certain affirmative and negative covenants, including, but not limited to the following +financial covenants: (a) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and +interest expense, plus exploration costs deducted in determining net income under full cost accounting) for a twelve-month period could not be greater than 2.00 to 1.00; and (b) the ratio of EBITDAX to interest expense for a twelve-month period +could not be less than 3.00 to 1.00. +On September 30, 2010, the Company entered into a $100 million senior secured +revolving credit agreement with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association. The new revolving credit facility matures on September 30, 2013 and has an +initial borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24, 2010. As of December 31, 2010, the Company had an outstanding balance of $49.5 million drawn under the credit agreement, +which is included in long-term debt, net of current maturities, on the accompanying consolidated balance sheets. The amounts borrowed under the credit agreement were used to repay all of the Company’s +F-18 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +outstanding indebtedness under its prior revolving credit facility ($42.0 million) and term loan ($2.5 million), each with Bank of America, N.A., as administrative agent, and for general +corporate purposes. The new credit agreement is secured by substantially all of the Company’s assets. The Company’s wholly-owned subsidiaries guaranteed the obligations of the Company under the credit agreement. +Advances under the credit agreement may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate +loans is equal to (1) the applicable rate, which ranges from 1.75% to 2.50%, plus (2) the highest of: (a) the federal funds rate plus 0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time +by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 2.75% to 3.50%, plus +(2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers +Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” +for deposits in U.S. dollars. At December 31, 2010, amounts borrowed under the credit agreement bore interest at the Eurodollar rate (3.77%). +The credit agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: incur indebtedness; grant liens; pay +dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their +affiliates. The negative covenants are subject to certain exceptions as specified in the credit agreement. The credit agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: +(1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, +the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts +attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received +from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and +acquisitions of assets, investments and debt and equity offering, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to +interest expense for a twelve-month period may not be less than 3.00 to 1.00. The Company was in compliance with all covenants at December 31, 2010. +In conjunction with the repayment of the Bank of America credit facilities on September 30, 2010, the Company expensed approximately $225,000 in unamortized loan fees associated with the Bank of +America revolving credit facility, which is included in interest expense in the accompanying consolidated statements of operations. +On July 10, 2006, Gulfport entered into a $5 million term loan agreement with Bank of America, N.A. related to the purchase of new gas compressor units. The loan began amortizing quarterly on +March 31, 2007 on a straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. The Company made quarterly principal payments of approximately $176,000. Amounts borrowed bore interest at +F-19 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Bank of America Prime. The Company made quarterly interest payments on amounts borrowed under the agreement. The Company’s obligations under the agreement were collateralized by a lien on +the compressor units. On September 30, 2010, the Company repaid this loan in full with borrowings under the new credit agreement discussed above. +(2) In June 2004, the Company purchased the office building it occupies in Oklahoma City, Oklahoma, for $3.7 million. One loan associated with this building matured in March 2006 and bore interest at the +rate of 6% per annum, while the other loan matures in June 2011 and bears interest at the rate of 6.5% per annum. The remaining building loan requires monthly interest and principal payments of approximately $23,000 and is secured by the +Oklahoma City office building and associated land. +8. +COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the +“Plan”), which is administered by the Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be +granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are defined as all directors of the +Company, all officers of the Company and all key employees of the Company with a customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted under the Plan, as adjusted for +changes in capitalization which have taken place since the Plan’s adoption, was 883,000. The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, 2010. No +additional securities will be issued under the Plan other than upon exercise of options that are outstanding. +The Company +replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible +participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are +defined as employees, consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the +2005 Plan to (i) include (a) Incentive Stock Options, (b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights and +(ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption +of the 2005 Plan. As of December 31, 2010, the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. +Restricted Stock +On March 13, 2008, the Company granted 6,666 shares +of restricted common stock of the Company, of which 740 shares vested on April 1, 2008 with the remaining shares vesting over 36 equal monthly installments +F-20 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +beginning on May 1, 2008. On August 6, 2008, the Company granted 2,000 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments +beginning on September 17, 2008. On September 15, 2008, the Company granted 10,000 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments beginning on September 17, 2008. On +December 5, 2008, the Company granted 66,667 shares of restricted common stock of the Company. The shares vest over twelve equal quarterly installments beginning on December 17, 2008. +On November 3, 2009, the Company granted 13,332 shares of restricted common stock of the Company. The shares vest over twelve equal +quarterly installments beginning on December 17, 2009. +On March 8, 2010, the Company granted 66,667 shares of +restricted common stock of the Company to employees of the Company at a fair value of approximately $662,000. The shares vest over twelve substantially equal quarterly installments beginning on March 18, 2010. On November 3, 2010, the +Company granted 45,000 shares of restricted common stock of the Company to employees of the Company at a fair value of approximately $783,000. The shares vest annually over five years, with 3,000 vesting the first year, 6,000 vesting the second +year, 9,000 vesting the third year, 12,000 vesting the fourth year, and 15,000 vesting the fifth year. All shares of restricted common stock of the Company were granted under the amended and restated 2005 Plan. +Sale of Common Stock +On +May 19, 2010, the Company sold 1,481,481 shares of its common stock in an underwritten public offering at a public offering price of $13.50 per share less the underwriting discount. On May 25, 2010, the Company sold an additional 187,022 +shares of common stock at the public offering price less the underwriting discount in connection with the underwriters’ partial exercise of the over-allotment option granted to them by the Company. The Company received the aggregate net +proceeds of approximately $21.6 million from the sale of these shares after deducting the underwriting discount and before offering expenses. A portion of the net proceeds from the offering was used to fund the Company’s Niobrara Formation and +Permian Basin acquisitions as discussed in Note 2. The remaining net proceeds from this offering were used for general corporate purposes, including expenditures associated with the Company’s 2010 drilling programs. +Private Placement Offering +In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred Stock, Series A, of the Company (the +“Preferred”) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per share, of the Company (the “Warrants”). Holders of the Preferred were entitled to receive dividends at the rate of 12% of the +liquidation preference per annum payable quarterly in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of Preferred at the rate of 15% of the +liquidation preference per annum. All Preferred shares were redeemed in 2005. +The 2,322,962 Warrants issued have a term of +ten years and a current exercise price of $1.19 per share of common stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon +exercise of the Warrants. The Company considered the valuation of the Warrants and did not consider them materially significant. The Company had 9,050 Warrants outstanding at December 31, 2010 which can be converted into 30,420 shares of common +stock. +F-21 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +9. +STOCK-BASED COMPENSATION +During the years ended December 31, 2010, 2009 and 2008, the Company’s stock-based compensation cost was $492,000, $529,000 and +$1,056,000, respectively, of which the Company capitalized $197,000, $212,000 and $422,000, respectively, relating to its exploration and development efforts, which reduced basic and diluted earnings per share by $0.01 and $0.01 for the years ended +December 31, 2010 and December 31, 2009, respectively. +The fair value of each option award is estimated on the date +of grant using the Black-Scholes option valuation model. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon historical +experience of the Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of +the grant. The 2005 Plan provides that all options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant. +No stock options were issued during the years ended December 31, 2010, 2009 and 2008. +The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends +on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. +A summary of the status of stock options and related activity for the years ended December 31, 2010, 2009 and 2008 are presented +below: +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value +Options outstanding at December 31, 2007 +674,390 +$ +6.22 +6.97 +$ +8,098,000 +Granted +— +— +Exercised +(144,121 +) +3.34 +1,694,000 +Forfeited/expired +(7,889 +) +6.17 +Options outstanding at December 31, 2008 +522,380 +7.01 +6.24 +$ +(1,599,000 +) +Granted +— +— +Exercised +(13,750 +) +2.20 +71,000 +Forfeited/expired +— +— +Options outstanding at December 31, 2009 +508,630 +7.14 +5.38 +$ +2,192,000 +Granted +— +— +Exercised +(48,889 +) +6.46 +545,000 +Forfeited/expired +(1,500 +) +2.00 +Options outstanding at December 31, 2010 +458,241 +$ +7.23 +4.48 +$ +6,621,000 +Options exercisable at December 31, 2010 +458,241 +$ +7.23 +4.48 +$ +6,621,000 +F-22 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Unrecognized compensation expense as of +December 31, 2010 related to outstanding stock options and restricted shares was $1,329,000. The expense is expected to be recognized over a weighted average period of 2.21 years. The following table summarizes information about the stock +options outstanding at December 31, 2010: +Exercise +Price +Number +Outstanding +Weighted Average +Remaining +Life +(in years) +Number +Exercisable +$2.00 +— +0.00 +— +$3.36 +222,241 +4.06 +222,241 +$9.07 +36,000 +4.69 +36,000 +$11.20 +200,000 +4.92 +200,000 +458,241 +458,241 +The following table summarizes restricted stock activity for the twelve months ended December 31, 2010, +2009 and 2008: +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2007 +59,033 +$ +13.94 +Granted +85,333 +5.64 +Vested +(41,493 +) +11.97 +Forfeited +(9,417 +) +15.84 +Unvested shares as of December 31, 2008 +93,456 +$ +7.04 +Granted +13,332 +$ +8.08 +Vested +(43,458 +) +8.16 +Forfeited +(3,086 +) +15.77 +Unvested shares as of December 31, 2009 +60,244 +$ +6.01 +Granted +111,667 +$ +12.94 +Vested +(58,525 +) +8.17 +Forfeited +— +— +Unvested shares as of December 31, 2010 +113,386 +$ +11.72 +10. +INSURANCE PROCEEDS +In +May 2008, the Company received insurance proceeds of approximately $769,000 related to damages incurred resulting from a 2006 barge accident in its WCBB field. The costs associated with repairing the field were expensed to lease operating expenses +as incurred in 2006 and 2007. The Company recognized the insurance proceeds in other (income) expense in the accompanying consolidated statements of operations. +In March 2009, the Company received insurance proceeds of approximately $1,050,000 related to damages incurred in its WCBB field as a result of Hurricane Ike in 2008. The costs associated with repairing +the field were +F-23 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +expensed to lease operating expenses as incurred in 2008 and 2009. The Company recognized the insurance proceeds in other (income) expense in the accompanying consolidated statements of +operations. In September and October 2009, the Company received additional insurance proceeds of approximately $994,000 related to damages incurred in the WCBB field as a result of Hurricane Ike and related debris removal. As the costs related to +these repairs and debris removal were incurred in 2009 and expensed to lease operating expense, the Company recognized the insurance proceeds in lease operating expenses in the accompanying consolidated statements of operations. +11. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current and long-term debt are carried +at cost, which approximates market value. +The fair value of the derivative instruments is computed based on the difference +between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and +are subject to significant volatility. +12. +INCOME TAXES +The income +tax provision consists of the following: +2010 +2009 +2008 +Current: +State +$ +40,000 +$ +28,000 +$ +— +Federal +95,000 +32,000 +653,000 +Deferred: +State +— +— +— +Federal +(95,000 +) +(32,000 +) +(653,000 +) +Total income tax expense provision +$ +40,000 +$ +28,000 +$ +— +A reconciliation of the statutory federal income tax amount to the recorded expense follows: +2010 +2009 +2008 +Income (loss) before income taxes +$ +47,403,000 +$ +23,655,000 +$ +(184,502,000 +) +Expected income tax at statutory rate +16,591,000 +8,279,000 +(64,576,000 +) +State income taxes +2,378,000 +1,370,000 +(7,033,000 +) +Other differences +(111,000 +) +(891,000 +) +(527,000 +) +Changes in valuation allowance +(18,818,000 +) +(8,730,000 +) +72,136,000 +Income tax expense recorded +$ +40,000 +$ +28,000 +$ +— +F-24 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +The tax effects of temporary differences and +net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2010, 2009 and 2008 are estimated as follows: +2010 +2009 +2008 +Deferred tax assets: +Net operating loss carryforward +$ +20,967,000 +$ +22,268,000 +$ +23,810,000 +Oil and gas property basis difference +32,054,000 +49,638,000 +57,789,000 +FASB ASC 718 compensation expense +347,000 +341,000 +238,000 +Investment in pass through entities +722,000 +528,000 +— +AMT credit +693,000 +598,000 +718,000 +Non-oil and gas property basis difference +279,000 +316,000 +118,000 +Total deferred tax assets +55,062,000 +73,689,000 +82,673,000 +Deferred tax liabilities: +Oil and gas property basis difference +— +— +— +Investment in pass through entities +— +— +134,000 +Unrealized gain on hedging activities +— +— +— +Total deferred tax liabilities +— +— +134,000 +Total deferred tax asset +55,062,000 +73,689,000 +82,539,000 +Valuation allowance +(54,434,000 +) +(73,156,000 +) +(81,886,000 +) +Net deferred tax asset +$ +628,000 +$ +533,000 +$ +653,000 +The Company has an available tax net operating loss carryforward estimated at approximately $52,417,000 as +of December 31, 2010. This carryforward will begin to expire in the year 2018. A valuation allowance has been provided at December 31, 2010, 2009 and 2008 because it is management’s belief, based upon the Company’s past history +of no taxable income and future projections of no taxable income during the carryforward period, it is more likely than not the net deferred tax assets will not be realized. +The Company had income tax expense of $40,000 and $28,000 related to state income tax for the years ended December 31, 2010 and 2009, respectively. +13. +EARNINGS PER SHARE +A +reconciliation of the components of basic and diluted net income per common share is presented in the table below: +2010 +2009 +2008 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per +Share +Basic: +Net income (loss) +$ +47,363,000 +43,863,190 +$ +1.08 +$ +23,627,000 +42,667,581 +$ +0.55 +$ +(184,502,000 +) +42,599,611 +$ +(4.33 +) +Effect of dilutive securities: +Stock options and awards +— +392,902 +— +350,067 +— +— +Diluted: +Net income +$ +47,363,000 +44,256,092 +$ +1.07 +$ +23,627,000 +43,017,648 +$ +0.55 +$ +(184,502,000 +) +42,599,611 +$ +(4.33 +) +F-25 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +For the year ended December 31, 2009, +options to purchase 64,889 shares at $9.07 per share and 200,000 shares at $11.20 per share were excluded from the calculation of dilutive earnings per share because they were anti-dilutive. For the year ended December 31, 2008, all options +were excluded from the calculation of dilutive earnings per share because the Company had a net loss and, therefore, the effect would have been anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive for the +year ended December 31, 2010. +14. +HEDGING ACTIVITIES +Oil Price Hedging +Activities +The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant +and often volatile fluctuation, by entering into forward sales contracts or fixed price swaps. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating +cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. +The Company accounts for its oil derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related +pronouncements. All derivative contracts are marked to market each quarter end and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. +At December 31, 2010, the fair value of derivative liabilities related to the fixed price swaps is as follows: +Short-term derivative instruments – liability +$ +4,720,000 +At December 31, +2009, the fair value of derivative liabilities related to the forward sales contracts is as follows: +Short-term derivative instruments – liability +$ +18,735,000 +All forward sales +contracts and fixed price swaps have been executed in connection with the Company’s oil price hedging program. For forward sales contracts and fixed price swaps qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract +price is included in oil sales in the period for which the underlying production was hedged. +For derivatives designated as +cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Amounts reclassified out of accumulated other +comprehensive income into earnings as a component of oil and condensate sales for the years ended December 31, 2010 and 2009 are presented below. +Year ended December 31, +2010 +2009 +(Reduction) addition to oil and condensate sales +($ +18,736,000 +) +$ +5,313,000 +The Company expects +to reclassify $4,720,000 out of accumulated other comprehensive income into earnings as a component of oil and condensate sales during the year ended December 31, 2011 related to fixed price swaps. +F-26 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Hedge effectiveness is measured at least +quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company did not recognize into +earnings any amount related to hedge effectiveness for the year ended December 31, 2010 related to the 2010 hedges as these hedges were deemed to be perfectly effective. The Company did not recognize into earnings any amount related to hedge +ineffectiveness for the year ended December 31, 2010 related to the 2011 hedges, however, these hedges could be considered ineffective in future periods. +During the fourth quarter of 2010, the Company entered into fixed price swap contracts for 2011 with the purchaser of the Company’s WCBB oil and another financial institution. The Company will pay +the counterparty the excess of the oil market price over the fixed price and will receive the excess of the fixed price over the market prices as defined in each contract. The Company’s fixed price swap contracts are tied to the commodity +prices on the New York Mercantile Exchange (“NYMEX”). The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price for oil as listed on the NYMEX West Texas Index +(“WTI”). However, due to the geographic location of the Company’s assets and the cost of transporting oil to another market, the amount that the Company receives when it actually sells its oil differs from the index price. At +December 31, 2010, the Company had the following fixed price swaps in place: +Daily Volume +(Bbls/day +Weighted +Average Price +January – December 2011 +2,000 +$ +86.96 +In 2009, the Company +was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs and differentials, for the period April 2009 to August 2009. The +Company also was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period September 2009 to +December 2009. For the period January 2010 through February 2010, the Company was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation +costs and differentials. For the period March 2010 through December 2010, the Company was party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before +transportation costs and differentials. +In the first quarter of 2009, the Company terminated forward sales contracts for +3,000 barrels per day of March 2009 production for approximately $1.5 million and terminated forward sales contracts for 3,000 barrels per day in the second quarter of 2009 for $476,000. For the year ended December 31, 2009, approximately $2.0 +million related to such terminations is included in oil and condensate sales on the accompanying consolidated statements of operations. There were no contracts in place which were accounted for as hedges at December 31, 2008. +The Company delivered approximately 45% of its 2010 production under forward sales contracts. +15. +FAIR VALUE MEASUREMENTS +The Company adopted FASB ASC 820 for all financial assets and liabilities measured at fair value on a recurring basis. The Company adopted +FASB ASC 820 effective January 1, 2009 for all non-financial assets and liabilities. FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer +F-27 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +a liability (exit price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, +followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and disclosed in one of the following categories: +Level 1 – Quoted prices in active markets for identical assets and liabilities. +Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in +markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. +Level 3 – Significant inputs to the valuation model are unobservable. +Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. +The following tables summarizes the Company’s financial and nonfinancial liabilities by FASB ASC 820 valuation level as +of December 31, 2010 and 2009: +As of December 31, 2010 +Level 1 +Level 2 +Level 3 +Assets: +Fixed price swaps +$ +— +$ +— +$ +— +Liabilities: +Fixed price swaps +$ +— +$ +4,720,000 +$ +— +As of December 31, 2009 +Level 1 +Level 2 +Level 3 +Assets: +Forward sales contracts +$ +— +$ +— +$ +— +Liabilities: +Forward sales contracts +$ +— +$ +18,735,000 +$ +— +The estimated fair +value of the Company’s fixed price swap contracts was based upon forward commodity prices based on quoted market prices, adjusted for differentials. +The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”). The +initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of +the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset +retirement obligations incurred during the twelve months ended December 31, 2010 were approximately $1,328,000. +16. +OPERATING LEASES +In +October 2006, the Company began leasing the Louisiana building that it owns to an unrelated party. The cost of the building totaled approximately $217,000 and accumulated depreciation amounted to approximately +F-28 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +$97,000 as of December 31, 2010. The lease commenced on October 15, 2006 and was extended to expire on October 14, 2011, with equal monthly installments of $10,500. The future +minimum lease payments to be received are as follows: +Fiscal year ending December 31, 2011 +$ +100,000 +17. +RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business activities with certain entities affiliated with its largest +stockholder. +Windsor Energy Group, LLC (“WEG”), an entity controlled by Wexford, operates the Permian Basin wells +in West Texas. At December 31, 2010 and 2009, the Company owed WEG approximately $5,871,000 and $1,631,000, respectively, related to reimbursement for services provided. Approximately $2,386,000 and $2,368,000 of services provided by WEG are +included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2010 and 2009, respectively. Approximately $21,666,000 and $8,063,000 related to services performed by WEG are included in oil +and natural gas properties on the accompanying consolidated balance sheets at December 31, 2010 and 2009, respectively. +Athena Construction LLC (“Athena”), an entity controlled by Wexford, performs services for the Company at its WCBB and +Hackberry fields. At December 31, 2010 and December 31, 2009, the Company owed Athena approximately $791,000 and $836,000, respectively, related to these services. Approximately $438,000 and $709,000 of services provided by Athena are +included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2010 and 2009, respectively. Approximately $2,554,000 and $1,286,000 related to services performed by Athena are included in oil +and natural gas properties on the accompanying consolidated balance sheets at December 31, 2010 and 2009, respectively. +Great White Directional Services LLC (“Directional”), an entity controlled by Wexford, performs services for the Company at its +WCBB and Hackberry fields. At December 31, 2010 and December 31, 2009, the Company owed Directional approximately $952,000 and $699,000, respectively, related to these services. Approximately $3,008,000 and $1,064,000 relating to services +performed by Directional are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2010 and 2009, respectively. +Great White Pressure Control (“Pressure Control”), an entity controlled by Wexford, performs services for the Company at its WCBB field. At December 31, 2010, the Company owed Pressure +Control approximately $80,000, related to these services. No amounts were owed to Pressure Control at December 31, 2009. Approximately $80,000 of services performed by Pressure Control is included in oil and natural gas properties on the +accompanying consolidated balance sheets at December 31, 2010. No services were performed by Pressure Control in 2009. +Black Fin P&A, LLC (“Black Fin”), an entity controlled by Wexford, performs services for the Company at its WCBB field. No +amounts were owed to Black Fin at December 31, 2010. Approximately $826,000 of services performed by Black Fin is included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2010. No services +were performed by Black Fin in 2009. +F-29 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +18. +COMMITMENTS +Plugging and Abandonment +Funds +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed +the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. +Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company can access the trust for use in plugging and abandonment charges associated with +the property. As of December 31, 2010, the plugging and abandonment trust totaled approximately $3,129,000. At December 31, 2010, the Company has plugged 311 wells at WCBB since it began its plugging program in 1997, which management +believes fulfills its current minimum plugging obligation. +Texaco Global Settlement +Pursuant to the terms of a global settlement between Texaco and the State of Louisiana which includes the State Lease No. 50 portion +of Gulfport’s East Hackberry field, Gulfport was obligated to commence drilling a well or other qualifying development operation on certain non-producing acreage in the field prior to March 1998. Because of prevailing market conditions during +1998, the Company believed it was commercially impractical to shoot seismic or commence drilling operations on the subject property. As a result, Gulfport agreed to surrender approximately 440 non-producing acres in this field to the State of +Louisiana. At December 31, 2010, Gulfport was in the process of releasing these properties to the State of Louisiana. +Contributions +to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 15% +of their total compensation through salary deferrals. Also under these plans, the Company will make a contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s +participation in salary deferrals. During the years ended December 31, 2010, 2009 and 2008, Gulfport incurred $316,000, $279,000 and $651,000, respectively, in contributions expense related to this plan. +Employment Agreement +In +May 1999, Gulfport entered into an employment agreement with its Chairman of the Board. The original term of the agreement expired on May 31, 2004, but automatically renews for successive terms of one year unless Gulfport or the Chairman elects +otherwise. The employment agreement calls for an annual salary of $200,000, subject to adjustment for cost of living increases. +The Company is party to an oral agreement with the Company’s Chief Executive Officer, with respect to his compensation and benefits, +pursuant to which he is entitled to an annual salary of $200,000 and, at the discretion of the Company’s board of directors, an annual cash incentive bonus. The compensation committee of the Board of Directors may make upward adjustments to +this salary. +19. +CONTINGENCIES +The +Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 to 2007. The LDR maintains +F-30 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +that Gulfport paid approximately $1,800,000 less in severance taxes under fixed price terms than the severance taxes Gulfport would have had to pay had it paid severance taxes on the oil at the +contracted market rates only. Gulfport has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based +upon the proceeds received under those contracts. Gulfport has maintained its right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against +Gulfport seeking $2,275,729 in severance taxes, plus interest and court costs. Gulfport filed a response denying any liability to the LDR for underpayment of severance taxes and is defending itself in the lawsuit. +In December 2010, the LDR filed two identical lawsuits against Gulfport in different venues to recover allegedly underpaid severance +taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney's fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by LDR in +2009, Gulfport denies all liability and will vigorously defend the lawsuit. The cases are in the early stages, and Gulfport has not yet filed a response to the recent lawsuits. +Other Litigation +In November 2006, Cudd Pressure Control, Inc. +(“Cudd”) filed a lawsuit against Gulfport, Great White Pressure Control LLC (“Great White”) and six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United +States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White’s employment of the former Cudd employees and sought unspecified +monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007. Gulfport filed a motion for summary judgment on October 5, +2007. The court entered a final interlocutory judgment in favor of all defendants, including Gulfport, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit +vacated the district court decision finding, among other things, that the district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand +the case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition with the state court (a) alleging that Gulfport conspired with the other defendants to misappropriate, and +misappropriated, Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking unspecified monetary damages. On April 13, 2010, Gulfport’s motion to be dismissed from the proceeding for lack of +personal jurisdiction was denied. This state court proceeding is in its initial stages. In 2011, the parties have continued with written discovery and production of documents. Cudd filed a third amended petition seeking $26.5 million (based on a +report prepared by its expert) plus disgorgement of $6 million in payments by Great White to the individual defendants and punitive damages. Gulfport denies these claims with respect to itself. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for +contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al., 38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did +not name Gulfport as a defendant, alleges that the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. Plaintiffs +allege that the defendants, which in addition to BP America Production Company include ExxonMobil Corporation, Shell Oil Company, ConocoPhillips Company, Sun Oil Company and Schlumberger Technology Corporation, conducted, directed and participated +in various oil and gas +F-31 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas +and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and response costs and stigma +damages. On December 7, 2010, Gulfport was served with a copy of the plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including Gulfport, bringing the total +number of defendants to 21. It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the plaintiffs now also seek: damages +sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages +for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits +and income; attorney fees and expenses and damages for evaluation and remediation of any contamination that threatens groundwater. On January 21, 2011, Gulfport filed a pleading challenging the legal sufficiency of the petitions and requesting +that they either be dismissed or that plaintiffs be required to amend such petitions. Gulfport’s motion is currently set to be heard on March 23, 2011. +Due to the current stages of the LDR, Cudd and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that may result. Litigation is inherently uncertain. +Adverse decisions in one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations. +The Company has been named as a defendant on various other litigation matters. The ultimate resolution of these matters is not expected to have a material adverse effect on the Company’s financial +condition or results of operations for the periods presented in the consolidated financial statements. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry principally in the state of Louisiana with sales to refineries, re-sellers +such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of +credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000. At December 31, 2010, Gulfport held cash in +excess of insured limits in these banks totaling $1,986,000. +During the year ended December 31, 2010, Gulfport sold +approximately 75% and 19% of its oil production to Shell Trading Company (“Shell”) and WEG, respectively, and 50%, 32% and 10% of its natural gas production to WEG, Chevron, and Hilcorp Energy Company (“Hilcorp”), respectively. +During the year ended December 31, 2009, Gulfport sold approximately 92% and 7% of its oil production to Shell and WEG, respectively, 100% of its natural gas liquids production to WEG, and 45%, 38%, and 16% of its natural gas production to WEG, +Chevron, and Hilcorp, respectively. During the year ended December 31, 2008, Gulfport sold approximately 87% and 11% of its oil production to Shell and WEG, respectively, 100% of its natural gas liquids production to WEG, and 60%, 22%, and 16% +of its natural gas production to Chevron, WEG, and Hilcorp, respectively. +F-32 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Forward Sales Contracts +The Company was party to forward sales contracts for the sale of 3,500 barrels of production per day for the months of January 2008 +through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For June 2008, the Company had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before +transportation costs. For the month of July 2008, the Company had agreements to sell 3,500 barrels of production per day at a weighted average daily price of $85.89 per barrel before transportation costs. For August 2008, Gulfport had agreements to +sell 3,500 barrels of production per day at a weighted average daily price of $86.81 per barrel before transportation costs. For the periods September 2008 through December 2008, the Company entered into forward sales contracts for the sale of 3,500 +barrels of production per day at a weighted average daily price of $86.60 per barrel before transportation costs. For the period of January 2009 through December 2009, the Company entered into agreements to sell 3,000 barrels of production per day +at a weighted average daily price of $89.06 per barrel before transportation costs. These contracts were originally designated as normal sales of production under FASB ASC 815, based on the Company’s intent to physically deliver the production +quantities under the contract terms, and exempted from the provisions of FASB ASC 815. +In December 2008, the Company +terminated the 2009 forward sales contracts in exchange for $39.0 million cash, which is included in other (income) expense on the accompanying consolidated statements of operations. As a result of this cash settlement, beginning in 2009, the +Company is required to account for similar contracts under the provisions of FASB ASC 815 until a reasonable period passes and the Company redevelops a past history of physical delivery under fixed price contracts without net cash settlement. See +Note 14 for further discussion of the Company’s 2009 and 2010 forward sales contracts. +20. +LITIGATION TRUST ENTITY +Pursuant to the Company’s 1997 plan of reorganization, all of Gulfport’s possible causes of action against third parties (with +the exception of certain litigation related to recovery of marine and rig equipment assets and claims against Tri-Deck), existing as of the effective date of that plan, were transferred into a “Litigation Trust” controlled by an +independent party for the benefit of most of the Company’s existing unsecured creditors. The litigation related to recovery of marine and rig equipment and the Tri-Deck claims were subsequently transferred to the Litigation Trust as described +below. +The Litigation Trust was funded by a $3,000,000 cash payment from the Company, which was made on the effective date of +reorganization. Gulfport owns a 12% interest in the Litigation Trust with the other 88% being owned by the former general unsecured creditors of Gulfport. For financial statement reporting purposes, Gulfport has not recognized the potential value of +recoveries which may ultimately be obtained, if any, as a result of the actions of the Litigation Trust, treating the entire $3,000,000 payment as a reorganization cost at the time of Gulfport’s reorganization. +On January 20, 1998, Gulfport and the Litigation Trust entered into a Clarification Agreement whereby the rights to pursue various +claims reserved by Gulfport under the plan of reorganization were assigned to the Litigation Trust. In connection with this agreement, the Litigation Trust agreed to reimburse the Company $100,000 for legal fees Gulfport had incurred in connection +with these claims. As additional consideration for the contribution of this claim to the Litigation Trust, Gulfport is entitled to 20% to 80% of the net proceeds from these claims. +F-33 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +In December 2009, the Company received a +final distribution from the Litigation Trust of approximately $234,000. No proceeds were received from the Litigation Trust for the years ended December 31, 2010 or 2008. +21. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES +The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the +United States: +Capitalized Costs Related to Oil and Gas Producing Activities +2010 +2009 +Proven properties +$ +730,566,000 +$ +610,778,000 +Unproven properties +11,756,000 +15,192,000 +742,322,000 +625,970,000 +Accumulated depreciation, depletion, amortization and impairment reserve +(509,248,000 +) +(470,649,000 +) +Net capitalized costs +$ +233,074,000 +$ +155,321,000 +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +2010 +2009 +2008 +Acquisition +$ +17,627,000 +$ +1,885,000 +$ +2,468,000 +Development of proved undeveloped properties +64,652,000 +28,652,000 +64,643,000 +Exploratory +— +502,000 +9,764,000 +Recompletions +16,917,000 +8,980,000 +16,877,000 +Capitalized asset retirement obligation +1,328,000 +361,000 +934,000 +Total +$ +100,524,000 +$ +40,380,000 +$ +94,686,000 +F-34 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income +tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of +operations exclude general office overhead and interest expense attributable to oil and gas production. +2010 +2009 +2008 +Revenues +$ +127,636,000 +$ +85,576,000 +$ +141,650,000 +Production costs +(31,580,000 +) +(26,113,000 +) +(38,669,000 +) +Impairment of oil and gas assets +— +— +(272,722,000 +) +Depletion +(38,600,000 +) +(28,939,000 +) +(42,194,000 +) +57,456,000 +30,524,000 +(211,935,000 +) +Income tax expense +Current +40,000 +28,000 +— +Deferred +— +— +— +40,000 +28,000 +— +Results of operations from producing activities +$ +57,416,000 +$ +30,496,000 +$ +(211,935,000 +) +Depletion per barrel of oil equivalent (BOE) +$ +19.54 +$ +17.25 +$ +23.92 +Oil and Gas Reserves (Unaudited) +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2010, 2009 and 2008 and changes in proved reserves during the last three +years. The 2010 and 2009 reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2010 +and 2009, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009. Estimates of reserves as of year-end 2008 were prepared using constant prices and costs in accordance with previous guidelines of the +SEC based on hydrocarbon prices received on a field-by-field basis as of December 31, 2008. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The prices used for the 2010 +reserve report are $76.16 per barrel and $4.38 per MMbtu, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2009 and 2008 for reserve report +purposes are $57.90 per barrel and $3.87 per MMbtu and $41.00 per barrel and $5.71 per MMbtu, respectively. +F-35 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Gulfport emphasizes that the volumes of +reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, +either upward or downward, as warranted by additional performance data. +2010 +2009 +2008 +Oil +Gas +Oil +Gas +Oil +Gas +Proved Reserves +Beginning of the period +17,488 +14,332 +21,771 +22,235 +25,115 +24,259 +Purchases in oil and gas reserves in place +3,913 +3,482 +1,728 +1,135 +77 +26 +Extensions and discoveries +5,574 +5,303 +2,614 +2,874 +1,315 +1,965 +Sales of oil and gas reserves in place +— +— +(736 +) +(282 +) +— +— +Revisions of prior reserve estimates +(5,426 +) +(6,171 +) +(6,294 +) +(11,139 +) +(3,091 +) +(3,303 +) +Current production +(1,845 +) +(788 +) +(1,595 +) +(491 +) +(1,645 +) +(712 +) +End of period +19,704 +16,158 +17,488 +14,332 +21,771 +22,235 +Proved developed reserves +7,230 +6,068 +6,165 +4,325 +7,072 +7,187 +The Company experienced downward reserve revisions in estimated proved reserves in 2010. These downward +revisions were primarily the result of the application of the five-year schedule for the development of proved undeveloped reserves required by the SEC’s “Modernization of Oil and Gas Reporting” Final Rule, which resulted in the +elimination of proved undeveloped reserves that remained undeveloped beyond such five-year schedule. The Company experienced downward reserve revisions in estimated proved reserves in 2009. These downward revisions were primarily the result of +application of the five-year schedule for the development of proved undeveloped reserves required by the SEC’s “Modernization of Oil and Gas Reporting” Final Rule. The Company experienced downward reserve revisions in estimated proved +reserves in 2008. These downward revisions were primarily a result of year end commodity prices utilized for the reserve estimate decreasing from $92.50 per barrel and $6.80 per MMbtu at December 31, 2007 to $41.00 per barrel and $5.71 per +MMbtu at December 31, 2008. +Discounted Future Net Cash Flows (Unaudited) +The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of +December 31, 2010, 2009 and 2008 using an unweighted average first-of-the-month price for the period January through December for 2010 and 2009 and the applicable year end price for 2008. +F-36 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +Standardized Measure of Discounted Future Net Cash Flows +Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2010 +2009 +2008 +Future cash flows +$ +1,479,295,000 +$ +1,005,029,000 +$ +1,023,056,000 +Future development and abandonment costs +(301,651,000 +) +(209,975,000 +) +(299,362,000 +) +Future production costs +(305,814,000 +) +(236,003,000 +) +(376,176,000 +) +Future production taxes +(136,323,000 +) +(97,841,000 +) +(109,478,000 +) +Future income taxes +(159,171,000 +) +(50,229,000 +) +— +Future net cash flows +576,336,000 +410,981,000 +238,040,000 +10% discount to reflect timing of cash flows +(260,849,000 +) +(170,207,000 +) +(111,800,000 +) +Standardized measure of discounted future net cash flows +$ +315,487,000 +$ +240,774,000 +$ +126,240,000 +In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers +in Gulfport’s reserve report, the Company will need to spend $71,320,000, $63,100,000 and $52,038,000 during years 2011, 2012 and 2013, respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2010 +2009 +2008 +Sales and transfers of oil and gas produced, net of production costs +$ +(96,056,000 +) +$ +(59,463,000 +) +$ +(102,981,000 +) +Net changes in prices, production costs, and development costs +122,147,000 +183,426,000 +(662,004,000 +) +Acquisition of oil and gas reserves in place +63,043,000 +20,981,000 +376,000 +Extensions and discoveries +88,227,000 +32,638,000 +7,801,000 +Revisions of previous quantity estimates, less related production costs +(89,155,000 +) +(77,531,000 +) +(13,480,000 +) +Sales of reserves in place +— +(13,185,000 +) +— +Accretion of discount +24,077,000 +12,624,000 +66,830,000 +Net changes in income taxes +(54,879,000 +) +(22,238,000 +) +152,949,000 +Change in production rates and other +17,309,000 +37,282,000 +8,454,000 +Total change in standardized measure of discounted future net cash flows +$ +74,713,000 +$ +114,534,000 +$ +(542,055,000 +) +F-37 +Table of Contents +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) +DECEMBER 31, 2010, 2009 AND 2008 +(Amounts rounded to nearest thousand) +22. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The following table summarizes quarterly financial data for the years ended December 31, 2010 and 2009: +2010 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +27,355,000 +$ +28,875,000 +$ +33,181,000 +$ +37,533,000 +Income from operations +10,526,000 +11,004,000 +13,468,000 +14,779,000 +Income tax expense +— +40,000 +— +— +Net income +9,981,000 +10,389,000 +12,678,000 +14,315,000 +Income per share: +Basic +$ +0.23 +$ +0.24 +$ +0.28 +$ +0.32 +Diluted +$ +0.23 +$ +0.24 +$ +0.28 +$ +0.32 +2009 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +17,784,000 +$ +20,514,000 +$ +22,071,000 +$ +24,893,000 +Income from operations +2,214,000 +5,410,000 +7,130,000 +9,596,000 +Income tax expense +— +28,000 +— +— +Net income +2,733,000 +5,078,000 +6,674,000 +9,142,000 +Income per share: +Basic +$ +0.06 +$ +0.12 +$ +0.16 +$ +0.21 +Diluted +$ +0.06 +$ +0.12 +$ +0.16 +$ +0.21 +23. +SUBSEQUENT EVENTS (Unaudited) +In February 2011, the Company entered into an agreement to acquire certain leasehold interests located in the Utica Shale in Ohio. The agreement also grants the Company an exclusive right of first refusal +for a period of six months on certain additional tracts leased by the seller. Windsor, an affiliate of the Company, has agreed to participate with the Company on a 50/50 basis in the acquisition of all leases described above. Gulfport will be the +operator on this acreage in the Utica Shale. The purchase price for the Company’s 50% interest in the initial acreage is approximately $31,625,000, subject to certain closing adjustments. This transaction is expected to close in mid-May 2011. +F-38 +Table of Contents +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor +Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party +seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the +SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, +2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the +Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with +the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a +Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other +Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, +certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +E-1 +Table of Contents +Exhibit +Number +Description +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.5 +of Amendment No. 1 to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5+ +Summary of Oral Employment Agreement with James D. Palm (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December +7, 2010). +10.5 +Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead +arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). +10.6 +Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer +and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Pinnacle Energy Services, LLC +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Pinnacle Energy Services, LLC. +* +Filed herewith ++ +Management contract, compensatory plan or arrangement. +E-2 \ No newline at end of file diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/filing_metadata.csv b/raw/filings/0000874499/2010/0001193125-11-065894/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..a4cf43ff9aa7a23a5c43f12c90aa7377b587fdf1 --- /dev/null +++ b/raw/filings/0000874499/2010/0001193125-11-065894/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2011-03-14,2010-12-31,2011-03-14T20:49:46.000Z,0001193125-11-065894,d10k.htm,FORM 10-K,1656841,0,0,https://www.sec.gov/Archives/edgar/data/874499/000119312511065894/d10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000119312511065894/,2010,2010,1 diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/item1.txt b/raw/filings/0000874499/2010/0001193125-11-065894/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..d9c78523bcd9d66440abb1ac9197571ead4dbb00 --- /dev/null +++ b/raw/filings/0000874499/2010/0001193125-11-065894/item1.txt @@ -0,0 +1,593 @@ +ITEM 1. +DESCRIPTION OF BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties +located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. In 2010, we acquired an acreage position in the Niobrara Formation of Western Colorado. We also hold a +significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to +achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2010, at our WCBB field, we +recompleted 72 wells and drilled 23 wells for a total cost of approximately $40.9 million as of December 31, 2010. All 23 new wells drilled at WCBB in 2010 were completed as producing wells. During 2011, we currently anticipate drilling 20 to +24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $36.0 to $38.0 million. In the fourth quarter of 2010, production at WCBB was 293,372 net barrels of oil equivalent, or BOE, or an average of 3,189 BOE per day, +97% of which was from oil and 3% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average net daily production at WCBB was 2,721 BOE, 97% of which was from oil and 3% of which was from natural gas. +In 2010, at our East Hackberry field, we recompleted ten wells and drilled eight wells for a total cost of approximately +$20.0 million as of December 31, 2010. All wells drilled during 2010 were completed as producing wells. During 2011, we currently anticipate drilling seven to ten wells and recompleting five wells for an aggregate estimated cost of $24.0 to +$26.0 million. In the fourth quarter of 2010, net production at East Hackberry was 157,349 BOE, or an average of 1,710 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2011 through February 28, +2011, our average net daily production at East Hackberry was 1,899 BOE, 93% of which was from oil and 7% of which was from natural gas. +In the fourth quarter of 2010, net production at West Hackberry was 3,121 BOE, or an average of 34 BOE per day, 100% of which was from oil. From January 1, 2011 through February 28, 2011, our +average net daily production at West Hackberry was 35 BOE, 100% of which was from oil. +In 2007, we acquired approximately +4,100 net acres in West Texas in the Permian Basin with production at the time of acquisition from 32 gross (16 net) wells, predominately from the Wolfcamp formation. Subsequently, we acquired approximately 10,600 additional net acres, which brought +our total net acreage position in the Permian Basin to approximately 14,700 net acres. During the year ended December 31, 2010, 25 gross (11 net) wells were drilled and four gross (two net) wells were recompleted on this acreage. As of +March 1, 2011, 24 of the 25 wells had been completed and one well was awaiting completion. We currently anticipate that 40 to 42 gross (19 to 20 net) wells will be drilled and ten gross (five net) wells will be recompleted on this acreage in +2011 for an estimated aggregate net cost of $37.0 to $39.0 million. In the fourth quarter of 2010, net production from our Permian acreage was 72,791 BOE, or an average of 791 BOE per day, 84% of which was from oil and natural gas liquids and 16% of +which was from natural gas. From January 1, 2011 through February 28, 2011, our average daily net production from our Permian acreage was 787 BOE, 87% of which was from oil and natural gas liquids and 13% of which was from natural gas. +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Colorado and held leases for +19,172 net acres as of March 1, 2011. During the year ended December 31, 2010, we recompleted one gross (0.4 net) well on this acreage. In the fourth quarter of 2010, net production at Niobrara was 3,380 BOE, or an average of 37 BOE per day, +100% of which was from oil. From January 1, 2011 through February 28, 2011, our average net daily production at Niobrara was 36 BOE, 100% of which was from oil. We are in the process of permitting a 60 square mile 3-D seismic survey and +expect to begin shooting in mid-2011. +2 +Table of Contents +As of December 31, 2010, we held approximately 900 net acres in the Williston Basin of +western North Dakota and eastern Montana with interests in five wells and an overriding royalty interest in wells drilled prior to our sale, wells drilled subsequent to our sale and wells that might be drilled in the future. In the fourth quarter of +2010, our net production from this acreage was 6,522 BOE, or an average of 71 BOE per day, 95% of which was from oil and natural gas liquids and 5% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average +daily net production from our Bakken acreage was 64 BOE, 93% of which was from oil and 7% of which was from natural gas. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. +The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LP, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of +other existing oil sands projects. Grizzly has approximately 534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly +has drilled an aggregate of 199 core holes and three water supply test wells, tested nine separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application in Alberta, Canada for the development of an 11,300 barrel +per day oil sand SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first production. Grizzly recently received the supplemental information request, +or SIR, pertaining to its Algar Lake project application from the Alberta regulatory agencies. This is the standard process by which the Alberta regulatory agencies request additional information on all oil sands project applications. The SIR was +received in a timeframe consistent with anticipated timeline for project approval. The engineering and procurement contract for Grizzly’s proposed steam assisted gravity drainage, or SAGD, facility at Algar Lake has been awarded to SNC-Lavin. +Work on the detailed engineering design is underway out of Grizzly’s Calgary office and the detailed design of the project is expected to be complete by April 2011. Grizzly’s currently contemplated 2011 activities include the completion of +the 2010/2011 core hole drilling activity, seismic program and the initial preparations for the Algar Lake SAGD facility. +We +own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or +APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. +We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in +Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. During 2010, Tatex completed a 3-D seismic survey on this concession. The first well drilled on our concession in 2010 +was temporarily abandoned pending further scientific evaluation. A second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and +carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. Tatex III is currently in the process of completing the well. +As of December 31, 2010, we had 22.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of +estimated future net revenues, discounted at 10%, or PV-10, of approximately $392.6 million and associated standardized measure of discounted future net cash flows of approximately $315.5 million. See Item 2. “Properties—Proved Oil +and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +3 +Table of Contents +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2010 reflecting our net interest in our principal producing oil +and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in western Colorado and in the Williston Basin in western North Dakota and eastern Montana. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +Mboe +Mboe +Mboe +West Cote Blanche Bay Field (4) +80.108/100 +93 +93 +179 +179 +5,668 +5,668 +386 +4,133 +4,519 +E. Hackberry Field (5) +79.424/100 +27 +27 +74 +74 +3,291 +3,291 +291 +2,561 +2,852 +W. Hackberry Field +87.5/100 +3 +3 +22 +22 +592 +592 +— +146 +146 +Permian Basin +37.38/49.05 +82 +40 +— +— +15,888 +7,124 +1,988 +12,465 +14,453 +Niobrara Formation +36.4/44.04 +4 +2 +1 +0.4 +2,240 +628 +23 +339 +362 +Williston Basin (6) +3.2/3.9 +5 +0.2 +— +— +2,560 +127 +5 +58 +63 +Overrides/Royalty Non-operated +Various +77 +0.2 +2 +— +— +— +— +2 +2 +Total +291 +165.4 +278 +275.4 +30,239 +17,430 +2,693 +19,704 +22,397 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes nine gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten +feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in +depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the +remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 973 wells drilled as of December 31, 2010, 880 were completed as producing wells. As a result, the +field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2010, we drilled 162 new wells, 146 of which were productive, for a 90% success rate. As of December 31, +2010, estimated field cumulative gross production was 191.3 MMBOE and 236.4 billion cubic feet, or Bcf, of gas. Of the 973 wells drilled in WCBB as of December 31, 2010, 84 were producing, 179 were shut-in, nine were producing intermittently +and five were being used as salt water disposal wells. The other 696 wells have been plugged and abandoned. +4 +Table of Contents +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per +mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical +staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced +seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The +relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension +over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct +sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 973 wells that had been drilled in the field as of December 31, 2010, over 4,000 potential zones have +been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a +structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a +structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The +tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, +in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort +to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2010 included +29 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2013. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas +compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2010, we recompleted 72 gross and net wells and drilled 23 gross and net wells at WCBB. All 23 new wells were completed +as producers. As of March 11, 2011, we had drilled two wells and recompleted twelve wells during 2011. Of the 23 wells drilled in 2010, 17 were considered deep wells. The 23 productive wells, with total depths ranging from 1,800 to 9,560 feet, +have approximately 2,063 feet of aggregate apparent net pay. We currently anticipate drilling 20 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2011. +Production Status +In the fourth quarter of 2010, production at WCBB was +293,372 net BOE, or an average of 3,189 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average net daily production at WCBB was 2,721 BOE, 97% of which was +from oil and +5 +Table of Contents +3% of which was from natural gas. The decrease in production was due to operating inefficiencies with wells, machinery and equipment resulting from the sub-freezing weather conditions during +January and February 2011 in Southern Louisiana. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along +the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry +field. We hold beneficial interests in approximately 4,870 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We also hold +2,868 net acres subject to a two-year exploration agreement we entered into with an active gulf coast operator. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have +licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and are reprocessing the data. +Area History and +Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a +gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and +condensate production through 2010 was over 1,015 MBOE and 330 Bcf of casinghead gas production. A total of 201 wells have been drilled on our portion of the field. As of December 31, 2010, 27 wells had daily production, 74 were shut-in and two +had been converted to salt water disposal wells. The remaining 98 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and +west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply +dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a +field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a +per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. +Recent and Future Activity +During 2005, we completed a proprietary 42 +square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D seismic data to +identify additional drilling locations. During 2010 at East Hackberry, we recompleted ten gross and net wells and drilled six gross and net land wells and two gross and net wells on water. All of the eight wells drilled during 2010 were completed as +producing wells. As of March 11, 2011, we had recompleted three wells during 2011, drilled one well and were in the process of drilling two additional wells. We currently intend to drill seven to ten gross and net wells and recomplete five +gross and net wells at East Hackberry during 2011. +6 +Table of Contents +Production Status +In the fourth quarter of 2010, net production at East Hackberry was 157,349 BOE, or an average of 1,710 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, +2011 through February 28, 2011, our average net daily production at East Hackberry was 1,899 BOE, 93% of which was from oil and 7% of which was from natural gas. The increase in production in 2011 is a result of our 2011 drilling activities. +West Hackberry Field +Location and Land +The +West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% +NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves. +Area History +The first +discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2010 was 274 MBOE and 140 Bcf +of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 22 are shut-in and one has been converted to a saltwater disposal well. The remaining ten wells have been plugged and +abandoned. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in +the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In +the fourth quarter of 2010, net production at West Hackberry was 3,121 BOE, or an average of 34 BOE per day. From January 1, 2011 through February 28, 2011, our average net daily production at West Hackberry was 35 BOE and was 100% oil. +Facilities +We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both +the East and West Hackberry fields. +Permian Basin (West Texas) +Location and Land +We acquired approximately 4,100 net acres and 32 gross +(16 net) producing wells in West Texas (near Midland) in the Permian Basin effective November 1, 2007. Subsequently, we acquired 10,600 additional net acres, which brought our total net acreage position in the Permian Basin to approximately +14,700 net acres as of December 31, 2010. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian +Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy LLC, an entity controlled by Wexford, is the operator of this field. +7 +Table of Contents +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found +in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the +greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp +formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian +wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private +company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to +participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2010, we held interests in 82 gross (40 net) producing wells. +Geology +The +Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is +characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. +Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2010, proved reserves net to our interest in these assets were approximately 14.5 million BOE, of which 16% were classified as +proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 226 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally +characterized as long-lived, with predictable production profiles. +Production Status +In the fourth quarter of 2010, net production from the Permian field was 72,791 BOE, or an average of 791 BOE per day, 84% of which was +from oil and natural gas liquids, and 16% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average daily net production from our Permian acreage was 787 BOE, 87% of which was from oil and natural gas +liquids and 13% of which was from natural gas. The slight production decrease was the result of the unusual sub-freezing weather conditions during January and February 2011. +Facilities +There are typical land oil and gas processing facilities in the +Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2010, 25 gross (11 net) wells were drilled in our Permian acreage. As of March 11, 2011, four gross (two net) wells had been recompleted and five gross (2.5 net wells) have been drilled +on this acreage, three of which were waiting on completion and two were currently drilling. We have identified 226 gross future development drilling locations. We currently expect an estimated 40 to 42 gross (19 to 20 net) wells to be drilled +on our acreage in 2011. The wells are expected to be drilled to approximately 10,200 feet. +8 +Table of Contents +Niobrara Formation (Western Colorado) +Location and Land +Effective as of April 1, 2010, we acquired +leasehold interests in the Niobrara Formation in western Colorado, and held leases for 19,172 acres as of March 1, 2011. We are the operator on the acreage. +Area History +The Niobrara Formation is a shale oil rock formation located +in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 – 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as +another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of the earliest production +dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and +limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature. +Geology +The Niobrara +Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured +marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and +fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. The producing intervals are geologically equivalent +to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play. +Production +Status +In the fourth quarter of 2010, net production from our Niobrara acreage was 3,380 BOE, or an average of 37 BOE per +day, 100% of which was from oil. From January 1, 2011 through February 28, 2011, our average daily net production from our Niobrara acreage was 36 BOE, 100% of which was from oil. +Facilities +There are typical land oil and gas processing facilities in the +Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +We recompleted one well at Niobrara during +2010. We are in the process of permitting a 60 square mile 3-D seismic survey over our Craig Dome prospect and expect to begin shooting in mid-2011. We currently intend to drill four to five gross wells at Niobrara during 2011. +9 +Table of Contents +Bakken +Location and Land +The Bakken Shale is located in the Williston Basin areas +of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired +leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest +in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. +During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2010, we held approximately 900 net acres, interests in five wells and an overriding +royalty interest in wells drilled prior to our sale, wells drilled subsequent to our sale and wells that might be drilled in the future. +Production Status +In +the fourth quarter of 2010, net production from our Bakken acreage was 6,522 BOE, or an average of 71 BOE per day, 95% of which was from oil and natural gas liquids and 5% of which was from natural gas. From January 1, 2011 through +February 28, 2011, our average net daily production from this acreage was 64 BOE, of which 93% was from oil and 7% was from natural gas. +Facilities +There are +typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and future activities +One gross well was drilled on our acreage in 2010. We have no activities currently scheduled for 2011 in the Williston Basin. +Additional Properties +Louisiana . In addition to our interests in +the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: +Field +Parish +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Bayou Long +Iberia +3.125 +% +0 +% +0 +0 +Bayou Penchant +Terrebonne +3.125 +% +0 +% +1 +2 +Bayou Pigeon +Iberia +6.250 +% +0 +% +0 +0 +Deer Island +Terrebonne +6.250 +% +0 +% +0 +0 +Golden Meadow +Lafourche +3.125 +% +0 +% +0 +0 +Napoleonville +Assumption +0 +% +2.5 +% +3 +0 +Thailand . +During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the +1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes +the Phu Horm Field. During +10 +Table of Contents +the year ended December 31, 2010, we received $565,000 in distributions, reducing our total investment in Tatex to $1.9 million. Our investment is accounted for on the equity method. Tatex +accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet +per day. For December 2010, net gas production was approximately 98 MMcf per day and condensate production was 477 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP +(20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is +accounted for by the cost method, these reserves are not included in our year-end reserve information. +During the first +quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million +bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. Tatex III +recently completed a 3-D seismic survey on this concession. During the year ended December 31, 2010, we paid $402,000 in cash calls, bringing our total investment in Tatex III to $4.7 million. The first well drilled on our concession in 2010 +was temporarily abandoned pending further scientific evaluation. A second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried +a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. Tatex III is currently in the process of completing the well. +Grizzly Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are +owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles from other existing oil sands projects. Grizzly has approximately +534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly has drilled an aggregate of 199 core holes and three water +supply test wells, tested nine separate lease blocks and conducted a seismic program. In connection with its 2010/2011 winter drilling program, Grizzly plans to drill a total of 71 core hole locations, 68 of which have been drilled to date. Upon the +completion of the 2010/2011 drilling season, Grizzly will have drilled 32 locations at Thickwood Hills, 14 locations at Firebag River, 17 locations at Algar Lake, and eight total locations at Athabasca Rapids and Horse River. In March 2010, Grizzly +filed an application in Alberta, Canada for the development of an 11,300 barrel per day SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first +production. Grizzly recently received the supplemental information request, or SIR, pertaining to its Algar Lake project application from the Alberta regulatory agencies. This is the standard process by which the Alberta regulatory agencies request +additional information on all oil sands project applications. The SIR was received in a timeframe consistent with anticipated timeline for project approval. The engineering and procurement contract for Grizzly’s proposed steam assisted gravity +drainage facility at Algar Lake has been awarded to SNC-Lavin. Work on the detailed engineering design is underway out of Grizzly’s Calgary office and the detailed design of the project is expected to be complete by April 2011. Grizzly’s +currently contemplated 2011 activities include the completion of the 2010/2011 core hole drilling activity and the initial preparations for the Algar Lake SAGD facility. +Competition and Markets +The oil and natural gas industry is intensely +competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products +on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to +11 +Table of Contents +withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government +regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond +the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and +equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our +wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB, other than the production sold under forward sales contracts, +is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $2.70 per +barrel for transportation. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 50%, 32%, and 10% of our natural gas production to Windsor Energy Group, +Chevron and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to +Windsor Energy Group, Chevron and Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and +16% of our natural gas production to Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price +at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the +factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the +effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the +period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel +before transportation costs and differentials. We delivered approximately 45% of our 2010 production under these agreements. +In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel, +before transportation costs and differentials, for the period January 2011 through December 2011. Under the 2011 contracts, we have committed to deliver approximately 30% to 33% of our estimated 2011 production. Such arrangements may expose us to +risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contacts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value +pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation +affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our +cost of doing business and, consequently, affects our profitability. +12 +Table of Contents +We own interests in a number of producing oil and natural gas properties located along the +Louisiana Gulf Coast, West Texas and the Niobrara Formation. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new +fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production +allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the +discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly +compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, +restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying +within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or +revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The +strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly +pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that +we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and +regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and +non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, +development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste +provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future +regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations +could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal +penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, +registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any +legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state +laws, generally +13 +Table of Contents +imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a +“hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or +arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or +remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health +studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our +operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of +the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The +Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the +unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance +with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure, or SPCC, plan requirements under federal law require appropriate containment terms and similar structures to help prevent the contamination of +navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also +adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or +developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for +discharges or operations that may impact groundwater conditions. +The Oil Pollution Act, or OPA, is the primary federal law +for oil spill liability. OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore +facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects +owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well +as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. +Air +Emissions . The Federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and +continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations, +and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose +administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air +emissions regulations +14 +Table of Contents +and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas +projects. Our operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to +environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to +property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our +properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third +party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is +no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced +production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and +cash flows. +Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million +which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore West Cote Blanche Bay properties, we also have a $25.0 million property physical damage +policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $10.0 million for damages arising as a result of a named windstorm. In the event +of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $500,000 per occurrence ($1.5 million in the case of a +named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for +our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be +given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by +new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial +condition and results of operations. +At the depths and in the areas in which we operate, and in light of the vertical and +directional drilling that we undertake, we typically do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for two specific +wells we are drilling this year. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and +subcontractors hired by the service provider. +We have prepared and have in place spill prevention control and countermeasure +plans for each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and +15 +Table of Contents +updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround +drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters. This emergency +response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. It reports that it currently owns over 164 response vehicles, 65 +response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage barge sets, allowing for storage of up to 248 barrels of recovered oil +each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for the retainer and clean up services during 2009 and 2010 were +approximately $139,000. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the future, if and when needed, could be hindered or delayed +in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure at our WCBB field, we believe other companies would be +available to us in the event our primary remediation company was unable to perform. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease +a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of +finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At +December 31, 2010, we had 45 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the +estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2009 and 2008, expenses reimbursed +to us under these arrangements were $0.6 million and $1.4 million, respectively, and are reflected as a reduction in our general and administrative expenses. No amounts were reimbursed to us under these arrangements in 2010. A Louisiana well +servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. +Available Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those +reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is +electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on +Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +16 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/item13.txt b/raw/filings/0000874499/2010/0001193125-11-065894/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..07db716c566b6e68e4df43ea7be136022e880185 --- /dev/null +++ b/raw/filings/0000874499/2010/0001193125-11-065894/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and +Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/item9a.txt b/raw/filings/0000874499/2010/0001193125-11-065894/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..d38b846880e4ba71ba8eb6c8079a178b75c39864 --- /dev/null +++ b/raw/filings/0000874499/2010/0001193125-11-065894/item9a.txt @@ -0,0 +1,65 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief +Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, +processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including +our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. +As of December 31, 2010, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial +Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President +and Chief Financial Officer have concluded that as of December 31, 2010, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have +materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +57 +Table of Contents +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is +also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are +designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent +limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with +respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control +over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal +Control—Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2010. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year +ended December 31, 2010 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2010, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +58 +Table of Contents +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport +Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the +“Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The +Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s +Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable +assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material +weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a +reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable +assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting +includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable +assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with +authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material +effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control +over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as +of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010 and our report +dated March 14, 2011 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +March 14, 2011 \ No newline at end of file diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/rp_note.txt b/raw/filings/0000874499/2010/0001193125-11-065894/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2010/0001193125-11-065894/rpt_disclosure.txt b/raw/filings/0000874499/2010/0001193125-11-065894/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..78f6edae532b31f8303c4d6d254ce7ad426d19d0 --- /dev/null +++ b/raw/filings/0000874499/2010/0001193125-11-065894/rpt_disclosure.txt @@ -0,0 +1,109 @@ +Certain Relationships and Related Transactions +Review and Approval of Related Party Transactions +The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be substantively applied to each transaction +reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the Company. Further, the Company’s Code of +Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party transactions. +The Company’s policy that all of its employees and directors, as well as their family members, must avoid any activity that is or has the appearance +of conflicting with the Company’s business interest. This policy is a written policy included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform +the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the +Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give +rise to a conflict of interest. +Further, under the Audit Committee Charter, the Audit Committee is responsible for reviewing and monitoring +compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the Audit Committee, reviews and approves all +relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members, +have a direct or indirect material interest. The board of directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as +they determine in the good faith exercise of their discretion. +Administrative Services Agreements +We are a party to an administrative service agreement with Great White Energy Services LLC, which we refer to as Great White, which +agreement was entered into effective as of July 22, 2006. Under this agreement, our services include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual +agreement of the parties. This administrative service agreement had an initial three-year term, and upon expiration of that term the agreement has continued on a month-to-month basis. This administrative service agreement is terminable by either +party at any time with at least 30 days prior written notice. Great White reimburses us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing services +for such entity. Our services under this agreement ceased in January 2007, and we were not reimbursed any amounts by Great White for services provided under this agreement during the year ended December 31, 2010. However, Great White owes +continuing indemnification obligations to us in connection with the pending Cudd litigation described in more detail in our Annual Report on Form 10-K. Great White paid us $67,000 in 2010 as reimbursement for our attorneys fees and expenses in +connection with such litigation. Great White is controlled by Wexford Capital LP. Charles Davidson, who beneficially owned approximately 18.0% of our outstanding common stock as of April 15, 2011, is the Chairman and Chief Investment Officer of +Wexford Capital LP. Mike Liddell, our Chairman of the Board, is also Chairman of the Board of Great White. +We are also a party to +administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Grizzly Oil Sands ULC, which we refer to as Grizzly, Everest Operations Management LLC, +32 +Table of Contents +which we refer to as Everest, and Tatex Thailand III, LLC, which we refer to as Tatex III, which agreements were each entered into effective March 1, 2008. Under these agreements, our +services include professional and technical support. The services provided under these agreements and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements had an initial +two-year term, and has continued thereafter on a month-to-month basis. Each agreement may be cancelled by either party to such agreement with at least 60 days prior written notice and is also terminable (1) by the counterparty at any time with +at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We did not provide services under any of +these agreements in 2010 and received no reimbursements thereunder. Each of Stampede Farms, Grizzly, Everest and Tatex III is controlled by Wexford Capital LP. Our administrative service agreement with Grizzly was terminated effective +December 31, 2010. +Effective July 1, 2008, we entered into an acquisition team agreement with Everest to identify and evaluate +potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, the +party whose acquisition team identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share +of the acquisition or divestiture consideration. The agreement has a one year term unless earlier terminated by either party upon 30 days notice. +From time to time, two of our petroleum engineers provide services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to +Tatex Thailand II, LLC, or Tatex II, and Tatex III. Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities. Each +of Tatex II and Tatex III is controlled by Wexford Capital LP. We did not provide any services under these arrangements in 2010. +Services Provided to Us by Our Affiliates +We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge +services in our West Cote Blanche Bay, or WCBB, and Hackberry fields located along the Louisiana Gulf Coast. For the year ended December 31, 2010, we paid Athena $3,036,000 and owed an additional $791,000 for such services at that date. Athena +is controlled by Wexford Capital LP. +Windsor Energy Group operates our Permian Basin wells in West Texas. For the year ended +December 31, 2010, we paid Windsor Energy Group $32,641,000 and owed an additional $5,871,000 for such services at that date. Mike Liddell, our Chairman of the Board, is also Chairman of the Board of Windsor Energy Group, L.L.C. Windsor Energy +Group is controlled by Wexford Capital LP. +Effective March 1, 2008, Everest provides tax planning, preparation of supporting tax +schedules and consultation services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of the parties. Everest is controlled by Wexford Capital LP. We paid Everest $10,000 for these services +in 2010. +Caliber Development Company, LLC, or Caliber, provides building maintenance services for our headquarters in Oklahoma City, +Oklahoma. For the year ended December 31, 2010, we paid Caliber $18,000 and owed an additional $3,000 at that date. Mike Liddell, our Chairman of the Board, is Chief Executive Officer of Caliber. Caliber is an entity controlled by Wexford +Capital LP. +Great White Directional Services LLC, which we refer to as Directional, performs directional drilling services for us at our WCBB +and Hackberry fields. For the year ended December 31, 2010, we paid Directional +33 +Table of Contents +approximately $2,755,000 and owed an additional $952,000 for such services at that date. Directional is an entity controlled by Wexford Capital LP. +Great White Pressure Control, which we refer as Pressure Control, performs services for us at our WCBB field. At December 31, 2010, we owed $80,000 +to Pressure Control for such services at that date. No amounts were paid to Pressure Control in 2010. Pressure Control is an entity controlled by Wexford Capital LP. +Black Fin P&A, LLC, which we refer to as Black Fin, performs plugging and abandonment services for us at our WCBB field. For the year ended December 31, 2010, we paid $826,000 to Black Fin for +such services at that date. No additional amounts were owed to Black Fin at December 31, 2010. Black Fin is an entity controlled by Wexford Capital LP. +Our Investments in Affiliates and Related Agreements +During +2005, we purchased a 23.5% ownership interest in Tatex II at a cost of $2,400,000. The remaining interests in Tatex II are owned by other entities controlled by Wexford Capital LP. Tatex II, a privately-owned entity, holds 85,122 of the 1,000,000 +outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm Field. +During 2010, we received $565,000 in distributions, reducing our total investment in Tatex II (including previous investments) to $1,907,000. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. In December 2009, we purchased an additional +approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by other entities and individuals +affiliated with Wexford Capital LP. During 2010, we paid $402,000 in capital calls, bringing our total investment in Tatex III to $4,660,000. +During the third quarter of 2006, we purchased, through our wholly owned subsidiary Grizzly Holdings, Inc., a 24.9999% interest in Grizzly, a Canadian +unlimited liability company, for approximately $8,200,000. The remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LP. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta +Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 534,000 acres under lease and, at December 31, 2010, our net investment in Grizzly was approximately $46,460,000, including a note receivable of +$20,006,000 as discussed in the following paragraph. +We, through our wholly owned subsidiary Grizzly Holdings Inc., entered into a loan +agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow funds from us. Borrowed funds bear interest at LIBOR plus 4% and had an original maturity date of December 31, 2012. Effective April 1, 2010, the loan +agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan agreement was further amended to change the maturity date to the original maturity date of +December 31, 2012. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. We loaned Grizzly approximately $2,877,000 during the year ended December 31, 2010. The Company recognized interest income of +approximately $267,000 for the year ended December 31, 2010 under this loan agreement. The note balance was increased by approximately $942,000 as a result of a currency translation gain for the year ended December 31, 2010. +Area of Mutual Interest and Related Agreements +Effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly acquire oil and gas leases in the Permian Basin. The agreement provides that each +party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain +34 +Table of Contents +exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. +In connection with the area of mutual interest agreement, we, Windsor Permian and Windsor Energy Group, L.L.C., as the operator, entered into the joint +development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy Group, L.L.C. agreed to act as the operator +under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either party has greater than a 50% interest in a prospect, as defined in the development agreement, the majority party may designate the operator +of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. +Effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor Dakota LLC, or Windsor Dakota, to jointly acquire oil and gas leases on certain lands located +in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each party must offer the other party the right to participate in such acquisition in proportion to its +participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating +interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy Group, L.L.C., as the operator, also entered into an exploration agreement, effective as of +January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and Windsor Energy Group, L.L.C. agreed to act as the operator under the terms of a joint operating +agreement. In the event Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport as the operator. The parties agreed to pay Windsor Energy Group, L.L.C. for its services +as the operator with respect to the contract area as provided in the joint operating agreement. +Effective April 1, 2010, we entered into +an area of mutual interest agreement with Windsor Niobrara LLC, which we refer to as Windsor Niobrara, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, exploiting and producing oil +and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50/50 basis. The parties also agreed, subject to certain exceptions, to share third-party costs +and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we and Windsor Niobrara also entered into a development agreement, effective as of +April 1, 2010, pursuant to which we and Windsor Niobrara agreed to jointly develop the contract area, and we agreed to act as the operator under the terms of a joint operating agreement. Windsor Niobrara is controlled by Wexford Capital LP. +Utica Agreement +In February 2011, we entered into an agreement to acquire certain leasehold interests in 27,500 gross (13,750 net) acres located in the Utica Shale in Ohio. The agreement also grants us an exclusive right +of first refusal for a period of six months on certain additional tracts leased by the seller. Windsor Energy Group, L.L.C., directly or through one or more of its affiliates, has agreed to participate with us on a 50/50 basis in the acquisition of +all of the leases described above. We will be the operator on this acreage in the Utica Shale. The purchase price for our 50% interest in the initial acreage is approximately $31.6 million, subject to certain closing adjustments. This transaction is +expected to close in mid-May 2011. Windsor Energy Group, L.L.C. is controlled by Wexford Capital LP. +35 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/filing.txt b/raw/filings/0000874499/2011/0001193125-12-081951/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..fdc4f929bfe70dd98173399cfadd5e8f8f4a6c13 --- /dev/null +++ b/raw/filings/0000874499/2011/0001193125-12-081951/filing.txt @@ -0,0 +1,5987 @@ +10-K +1 +d268850d10k.htm +FORM 10-K +Form 10-K +Table of Contents +Index to Financial Statements +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +Form 10-K +(Mark One) +x +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2011 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from +to +Commission File Number: 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant as Specified in +Its Charter) +Delaware +73-1521290 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip code) +(405) 848-8807 +(Registrant’s Telephone Number, Including Area Code) +Securities +registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the +Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined +in Rule 405 of the Securities Act. Yes x No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the +Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the +Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 +days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such +files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is +not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an +accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check +one): +Large Accelerated +filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange +Act). Yes ¨ No x +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30, +2011, based on the closing price of the common stock on the NASDAQ Global Select Market on June 30, 2011, the last business day of the registrant’s most recently completed second fiscal quarter ($29.69 per share) was $1,134,495,605. +As of February 20, 2012, 55,621,371 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy Corporation’s Proxy Statement for the 2012 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. +Table of Contents +Index to Financial Statements +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +BUSINESS +2 +ITEM 1A. +RISK FACTORS +19 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +34 +ITEM 2. +PROPERTIES +34 +ITEM 3. +LEGAL PROCEEDINGS +40 +ITEM 4. +MINE SAFETY DISCLOSURES +42 +PART II +43 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +43 +ITEM 6. +SELECTED FINANCIAL DATA +44 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF +OPERATIONS +46 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +59 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +60 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL +DISCLOSURE +60 +ITEM 9A. +CONTROLS AND PROCEDURES +60 +ITEM 9B. +OTHER INFORMATION +63 +PART III +63 +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +63 +ITEM 11. +EXECUTIVE COMPENSATION +63 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER +MATTERS +63 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +63 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +63 +PART IV +64 +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +64 +Signatures +S-1 +Index to Consolidated Financial Statements +F-1 +Exhibit Index +E-1 +i +Table of Contents +Index to Financial Statements +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the +Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and +uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed +or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” +“plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. +All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net +revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our +business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions +reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and +uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees +of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking +statements due to the factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements +speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all +forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +Index to Financial Statements +PART I +ITEM 1. +BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the +Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. During 2010, we acquired our initial acreage position in the Niobrara Formation of northwestern Colorado and, during 2011, we +acquired our initial acreage position in the Utica Shale in Eastern Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, and have interests in entities that operate in +Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2011, at our WCBB field, we recompleted 68 wells and drilled 21 wells for a total cost of approximately $42.4 million as of December 31, 2011. Of the 21 new wells drilled at WCBB in 2011, 19 were +completed as producing wells, one was non-productive and one was waiting on completion. In the fourth quarter of 2011, production at WCBB was 362,996 net barrels of oil equivalent, or BOE, or an average of 3,946 BOE per day, 96% of which was from +oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. During 2012, we currently +anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $36.0 million to $38.0 million. +In 2011, at our East Hackberry field, we recompleted 24 wells and drilled 22 wells for a total cost of approximately $51.9 million as of December 31, 2011. Of the 22 new wells drilled at East +Hackberry during 2011, 17 were completed as producing wells, two were non-productive and three were waiting on completion. In the fourth quarter of 2011, net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of +which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas. +During 2012, we currently anticipate drilling 10 to 12 wells and recompleting 10 wells for an aggregate estimated cost of $24.0 million to $26.0 million. +In the fourth quarter of 2011, net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our +average net daily production at West Hackberry was 37 BOE, 100% of which was from oil. +In 2011, 39 gross (17 net) wells were +drilled and eight gross (four net) wells were recompleted on our Permian Basin acreage for a total net cost of $38.4 million. As of December 31, 2011, 35 of the 39 wells had been completed and four wells were awaiting completion. In the fourth +quarter of 2011, net production from our Permian Basin acreage was 93,760 BOE, or an average of 1,019 BOE per day, of which approximately 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 +through January 31, 2012, our average daily net production from our Permian Basin acreage was 1,032 BOE, of which 72% was from oil, 16% was from natural gas liquids and 12% was from natural gas. We currently anticipate that 23 to 25 gross (11.5 +to 12.5 net) wells will be drilled and five gross (2.5 net) wells will be recompleted on this acreage in 2012 for an estimated aggregate net cost of $23.0 million to $25.0 million. In an effort to facilitate the development of our Permian Basin and +other domestic acreage, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates four drilling rigs. The remaining 75% equity interest is owned by entities controlled by Wexford Capital LP, or +Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of February 20, 2012. We have also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in +Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford. +2 +Table of Contents +Index to Financial Statements +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara +Formation in northwestern Colorado and held leases for approximately 15,000 net acres as of December 31, 2011. During the year ended December 31, 2011, we drilled three gross (1.5 net) wells on this acreage. In the fourth quarter of 2011, +net production from our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average net daily production from our Niobrara acreage was 41 BOE, 100% +of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey, have received a processed version of the seismic and are selecting future drilling locations. During 2012, we currently anticipate drilling five +to seven gross wells in the Niobrara Formation for approximately $5.0 million to $6.0 million. +As of December 31, 2011, +we held approximately 800 net acres in the Williston Basin of western North Dakota and eastern Montana with interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale of certain of our Bakken acreage and +production from such acreage, wells drilled subsequent to such sale and wells that might be drilled in the future. In the fourth quarter of 2011, our net production from this acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was +from oil, 6% was from natural gas and 3% was from natural gas liquids. From January 1, 2012 through January 31, 2012, our average daily net production from our Bakken acreage was 71 BOE, of which 92% was from oil and 8% was from natural +gas. +As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in +the Utica Shale in Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We intend to continue to pursue opportunities in this area +and have commitments with various future closing dates that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We recently spud our first well on our Utica Shale +acreage. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% +interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort +McMurray within a few miles of other existing oil sands projects. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine separate lease blocks and conducted a seismic program. +In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources +Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core hole drilling and seismic program, +submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD +well pairs. +We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are +owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast +Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. +We also +own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one +million acres. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in +March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the +intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet per day of +3 +Table of Contents +Index to Financial Statements +gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic feet per day. Pressure buildup information confirmed that this wellbore lacked the +permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to +produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to +drill the first, located to the south of the TEW-E well, late this year or early 2013. +As of December 31, 2011, we had +19.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $490.5 million and associated standardized measure of discounted future +net cash flows of approximately $376.7 million, excluding reserves attributable to our interests in Grizzly, Tatex II and Tatex III. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a +non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Principal Oil +and Natural Gas Properties +The following table presents certain information as of December 31, 2011 reflecting our +net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in northwestern Colorado and in the Williston Basin in western North Dakota and +eastern Montana. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +MBOE +MBOE +MBOE +West Cote Blanche Bay Field (4) +80.108/100 +95 +95 +189 +189 +5,668 +5,668 +352 +3,617 +3,969 +E. Hackberry Field (5) +79.424/100 +30 +30 +93 +93 +3,291 +3,291 +226 +1,606 +1,832 +W. Hackberry Field +87.5/100 +2 +2 +23 +23 +592 +592 +— +76 +76 +Permian Basin +35.4/46.87 +121 +57 +— +— +8,880 +4,119 +2,008 +10,877 +12,885 +Niobrara Formation +39.7/47.9 +6 +3 +2 +1 +3,954 +1,977 +26 +500 +526 +Williston Basin (6) +2.8/3.3 +6 +.2 +— +— +1,708 +132 +7 +67 +74 +Overrides/Royalty Non-operated +Various +133 +.2 +— +— +— +— +3 +2 +5 +Total +393 +187.4 +307 +306 +24,093 +15,779 +2,622 +16,745 +19,367 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes six gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +4 +Table of Contents +Index to Financial Statements +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off +the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 +feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the +remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 994 wells drilled as of December 31, 2011, 900 were completed as producing wells. As a result, the +field has a historic success rate of 91% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2011, we drilled 183 new wells, 166 of which were productive, for a 91% success rate. As of December 31, +2011, estimated field cumulative gross production was 192.6 MMBOE and 236.6 billion cubic feet, or Bcf, of gas. Of the 994 wells drilled in WCBB as of December 31, 2011, 89 were producing, 189 were shut-in, six were producing intermittently and +five were being used as salt water disposal wells. The other 705 wells have been plugged and abandoned. +In 1991, Texaco +conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December +1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the +first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which +created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets +having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 994 wells that had been drilled in +the field as of December 31, 2011, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to +faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells +drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault +before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk +associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an +5 +Table of Contents +Index to Financial Statements +effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory +of prospects at WCBB as of December 31, 2011 included 24 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2015. +Facilities +We own and operate a production facility at WCBB that includes +four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2011, we recompleted 68 gross and net wells +and drilled 21 gross and net wells at WCBB. Nineteen of the new wells were completed as producers, one was non-productive and one was waiting on completion. As of February 20, 2012, we had drilled three wells, were in the process of drilling +two additional wells and recompleted six wells during 2012. Of the 21 wells drilled in 2011, 18 were considered deep wells. The 19 productive wells, with total depths ranging from 2,500 to 10,748 feet, have approximately 1,855 feet of aggregate +apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2012. +Production Status +In +the fourth quarter of 2011, our production at WCBB was 362,996 net BOE, or an average of 3,946 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net +daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. The decrease in production was due to normal production declines. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the +Gulf of Mexico. We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 3,291 acres, including the +Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We also hold 2,868 net acres subject to a two-year exploration agreement we entered into with an +active gulf coast operator. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have licensed approximately 54 square miles of 3-D seismic data covering a portion of the +area and are reprocessing the data. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The +massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2011 was +over 1,625 MBOE and 330 Bcf of casinghead gas production. A total of 223 wells have been drilled on our portion of the field. As of December 31, 2011, 30 wells had daily production, 93 were shut-in and two had been converted to salt water +disposal wells. The remaining 98 wells had been plugged and abandoned. +6 +Table of Contents +Index to Financial Statements +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry +acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. +These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West +Hackberry fields. In addition, we own and operate two production facilities at East Hackberry that include a land based tank battery, production barge, three natural gas compressors, dehydration units and salt water disposal systems. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at this field. We believe that this 3-D seismic data enhances our +probability of drilling success, and we continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2011 at East Hackberry, we recompleted 24 gross and net wells and drilled 13 gross and net land wells and nine gross +and net wells on water. Seventeen of the 22 wells drilled during 2011 were completed as producing wells, two were non-productive and three were waiting on completion. As of February 20, 2012, we had recompleted two wells during 2012, drilled +two wells and were in the process of drilling two additional wells. We currently intend to drill 10 to 12 gross and net wells and recomplete 10 gross and net wells at East Hackberry during 2012. +Production Status +In +the fourth quarter of 2011, our net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our +average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas. The increase in production in 2012 is a result of our 2012 drilling activities. +West Hackberry Field +Location and +Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, +approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of +one of the United States Department of Energy’s Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil +Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2011 was 286 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, two are producing, +23 are shut-in and one has been converted to a saltwater disposal well. The remaining 10 wells have been plugged and abandoned. +7 +Table of Contents +Index to Financial Statements +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in +the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In +the fourth quarter of 2011, our net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day. From January 1, 2012 through January 31, 2012, our average net daily production at West Hackberry was 37 BOE and was 100% oil. +Facilities +We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. +Permian Basin (West Texas) +Location and Land +We +acquired approximately 4,100 net acres and 32 gross (16 net) producing wells in West Texas (near Midland) in the Permian Basin effective November 1, 2007. Subsequently, we acquired approximately 11,200 additional net acres, which brought our +total net acreage position in the Permian Basin to approximately 15,300 net acres as of December 31, 2011. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing +basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Permian LLC, or Windsor, an entity controlled by Wexford, is the operator of this field. +Area History +The +Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets +occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was +revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned +interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began +acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry +Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in +enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2011, we held interests in 121 gross (57 net) producing wells. +Geology +The +Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging +8 +Table of Contents +Index to Financial Statements +Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir +rock within the section is generally found in close proximity to the Central Basin Platform. +Wolfberry well reserves are +typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Ryder Scott Company L.P., or Ryder Scott, an independent petroleum engineering firm, has estimated that at December 31, 2011, proved reserves net to our +interest in these assets were approximately 12.9 million BOE, of which 23% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 252 gross well locations on 40-acre +units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. +Production Status +In the fourth quarter of 2011, our net production from +the Permian Basin field was 93,760 BOE, or an average of 1,019 BOE per day, of which 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 through January 31, 2012, our average daily net +production from our Permian Basin acreage was 1,032 BOE, 88% of which was from oil and natural gas liquids and 12% of which was from natural gas. +Facilities +There are typical land oil and natural gas processing +facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2011, 39 gross (17 net) wells were +drilled in our Permian Basin acreage. From January 1, 2012 to February 20, 2012, two gross (one net) wells had been drilled on this acreage and were waiting on completion and at February 20, 2012 one gross (0.5 net) additional +well was being drilled. We have identified 252 gross future development drilling locations. We currently expect an estimated 23 to 25 gross (11.5 to 12.5 net) wells to be drilled on our acreage in 2012. The wells are expected to be drilled to +approximately 11,200 feet. In an effort to facilitate the drilling of these and future wells, in 2011 we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates four drilling rigs. We acquired our +interest in Bison from Windsor Permian LLC, or Windsor. Windsor is the operator of our Permian Basin properties and is controlled by Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of February 20, +2012. During 2011, we also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford. +Niobrara Formation (Northwestern Colorado) +Location and Land +Effective as of April 1, 2010, we acquired +leasehold interests in the Niobrara Formation in northwestern Colorado, and held leases for 14,993 acres as of December 31, 2011. We are the operator on the acreage. +Area History +The Niobrara Formation is a shale oil rock formation located +in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as +another +9 +Table of Contents +Index to Financial Statements +potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional +technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, +conventional production has been very localized and limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally +mature. +Geology +The Niobrara Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, +calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated +with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. +The producing intervals are geologically equivalent to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play. +Production Status +In the fourth quarter of 2011, our net production from +our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average daily net production from our Niobrara acreage was 41 BOE, 100% of which was from +oil. +Facilities +There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping +units. +Recent and Future Activity +We drilled three gross (1.5 net) wells at Niobrara during 2011. We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect, have received a processed version of the seismic and are +selecting future drilling locations. We currently intend to drill five to seven gross wells at Niobrara during 2012. +Bakken +Location and Land +The Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining +interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of +its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 +net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of +December 31, 2011, we held approximately 800 net acres, interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale, wells drilled subsequent to such sale and wells that might be drilled in the future. +10 +Table of Contents +Index to Financial Statements +Production Status +In the fourth quarter of 2011, our net production from our Bakken acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was from oil, 3% was from natural gas liquids and 6% was from natural +gas. From January 1, 2012 through January 31, 2012, our average net daily production from this acreage was 71 BOE, of which 92% was from oil and 8% was from natural gas. +Facilities +There are typical land oil and gas processing facilities in the +Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and future activities +One gross (.01 net) well was drilled on our acreage in 2011. There are no new activities currently scheduled for 2012 for our Bakken acreage. +Utica Shale (Eastern Ohio) +Location and Land +As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in +Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We intend to continue to pursue opportunities in this area and have commitments +with various future closing dates that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We recently spud our first well on our Utica Shale acreage. +Area History +Based on +the estimates published by the Ohio Department of Natural Resources, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas. During 2011, a number of oil and gas +companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio and applied for drilling permits with the Ohio Department of Natural Resources. +During 2011, most of the drilling activity in the Utica Shale occurred in Eastern Ohio, where our acreage is located. Based on the initial drilling results, the Utica Shale is prospective for oil and +natural gas liquids. Specifically, early wells drilled in the Utica Shale indicated potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than natural gas. +Geology +The +Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late +Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. +Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from +wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has +potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. +11 +Table of Contents +Index to Financial Statements +The Utica Shale is estimated to be thicker and more geographically extensive than the +Marcellus Shale and, based on early drilling results, has the potential to support commercial production. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West +Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and part of Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 +feet. Over the rock unit as a whole, there is a general thinning from east to west. +The Utica Shale is also significantly +deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio +and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. +The Utica Shale is +estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica +Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers +have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale. +Facilities +There are typical land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well +locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and future activities +We recently spud our first well on our Utica Shale acreage and expect to drill approximately 20 gross (ten net) wells +during 2012. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas +and Oklahoma as described in the following table: +Field +State +Parish/County +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Deer Island +Louisiana +Terrebonne +3.125 +% +0 +% +1 +0 +Napoleonville +Louisiana +Assumption +0 +% +2.5 +% +3 +0 +Crest +Texas +Ochiltree +2.000 +% +0 +% +1 +0 +Eagle City South +Oklahoma +Dewey +1.040 +% +0 +% +1 +0 +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex +II, at a cost of $2.4 million. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. During the year ended December 31, 2011, we received +$870,000 in distributions, reducing our total investment in Tatex II to $1.0 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were +achieved at the Phu Horm field located in +12 +Table of Contents +Index to Financial Statements +northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. For 2011, net gas production was approximately 83 MMcf per day and condensate +production was 380 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a +member of APICO) in the Phu Horm field is 0.7%. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex II’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve +information. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, +at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the year ended December 31, +2011, we paid $3.8 million in cash calls, bringing our total investment in Tatex III to $8.3 million. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second +well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout +drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet per day of gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic +feet per day. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in +place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the +application process for two more drilling locations. Tatex III currently expects to drill the first, located to the south of the TEW-E well, late this year or early 2013. +Grizzly Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are +owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands +projects. Our total net investment in Grizzly was approximately $69.0 million as of December 31, 2011. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine separate lease +blocks and conducted a seismic program. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council +authorizing the Alberta Energy Resources Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core +hole drilling and seismic program, submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction of a central processing facility +and the drilling of ten initial SAGD well pairs. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these +companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to +take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control +of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of +13 +Table of Contents +Index to Financial Statements +skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural +gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our +production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average +differential less $2.70 per barrel for transportation. During 2011, we sold 93% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 22%, 27% and 50% of our natural gas production to Windsor, +Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 50%, 32%, and 10% of our natural gas production to Windsor, Chevron +and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor, Chevron and +Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price at which the oil and natural gas we produce may be sold is +uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is +impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, we were party to +forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period +March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November +2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps +for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per +barrel. For the period from January 2013 through June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45% of our 2010 +production. Under the 2011 contracts, we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. Such arrangements may expose us to risk of +financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contacts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant +to FASB ASC 815, “ Derivatives and Hedging, “ and related pronouncements. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation +affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our +cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and +natural gas properties located along the Louisiana Gulf Coast, West Texas and the Niobrara Formation in northwestern Colorado. The states in which our fields are located in regulate the production and sale of oil and natural gas, including +requirements for obtaining drilling +14 +Table of Contents +Index to Financial Statements +permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas +resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development +and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental +Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws +and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production +activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former +operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for +pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws +and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial +position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from +compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . +The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding +the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, +more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” +that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous +wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as +“hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to +waste handling, and that we hold all necessary and up-to- date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of +managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as +amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes +15 +Table of Contents +Index to Financial Statements +of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated +facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed +“responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property +contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury +and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental +agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the +Safe Drinking Water Act or SDWA, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and +other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill +prevention, control and countermeasure, or SPCC, plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank +spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas +exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention +plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. +The OPA,is the primary federal law for oil spill liability. OPA contains numerous requirements relating to the prevention of +and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency +plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs +and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the +requirements of each of these laws. +Air Emissions . The Federal Clean Air Act, as amended, and comparable state laws +and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for +our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified +sources. In particular, on August 23, 2011, the EPA published in the Federal Register a proposed rule to establish new air emission controls for oil and natural gas production and natural gas processing operations. The new emission +standards seek to reduce volatile organic compound, or VOC, emissions, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells. The EPA received public comment and conducted public +hearing regarding the proposed rules and must take final action on them by April 3, 2012. These laws and regulations may increase the costs of compliance for some +16 +Table of Contents +Index to Financial Statements +facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the +federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our +operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Our operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide +and methane, which are emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures +and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be +required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to +which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas +properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. +Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could +cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a +material adverse affect on our financial position, results of operations and cash flows. +Currently, we have general liability +insurance coverage with an annual aggregate limit of up to $21.0 million which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore West Cote +Blanche Bay properties, we also have a $25.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to +$10.0 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage +includes deductibles of up to $1,000,000 per occurrence ($1.5 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of +insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or +unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. +We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant +event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. +At the depths and in the areas in which we operate, and in light of the vertical and directional drilling that we undertake, we typically +do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for five specific Southern Louisiana wells. In addition, it is +currently anticipated that we will carry control of well coverage for all of our Utica Shale wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the +service provider’s employees as well as contractors and subcontractors hired by the service provider. +17 +Table of Contents +Index to Financial Statements +We have prepared and have in place spill prevention control and countermeasure plans for +each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we +own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as +a result of spills, blow-outs and natural disasters. This emergency response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. +It has previously reported that it owns over 164 response vehicles, 65 response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage +barge sets, allowing for storage of up to 248 barrels of recovered oil each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for +the retainer and clean up services during 2011 were approximately $220,000. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the +future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure +at our WCBB field, we believe other companies would be available to us in the event our primary remediation company was unable to perform. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of this office space to certain of our affiliates. We +also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a +building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2011, we had 50 employees. An unrelated Louisiana well servicing company provides all necessary field +personnel needed to operate the WCBB and the Hackberry fields. In addition, in the past, certain of our employees performed management and administrative services for affiliated companies. We were reimbursed by these affiliates for the salaries and +benefits of these individuals based on the estimated time they spent working for those affiliates. For the year ended December 31, 2009, expenses reimbursed to us under these arrangements were $0.6 million, respectively, and are reflected as a +reduction in our general and administrative expenses. No amounts were reimbursed to us under these arrangements in 2011 or 2010. +Available +Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments +to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such +material is electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual +report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +18 +Table of Contents +Index to Financial Statements +ITEM 1A. +RISK FACTORS +Risks Related to our +Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas +properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety +of additional factors that are beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +• +weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +speculative trading in crude oil and natural gas derivative contracts; +• +political instability or armed conflict in oil and natural gas producing regions; and +• +the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the +West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per +million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. On February 15, 2012, the West Texas Intermediate posted price for crude oil was $101.80 per bbl and the Henry Hub spot market price of +natural gas was $2.43 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas +reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +Declining general economic, +business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition. +Concerns over global economic conditions, energy costs, geopolitical issues, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States +have contributed +19 +Table of Contents +Index to Financial Statements +to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business +and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic +climate in the United States or abroad continues to deteriorate, demand for petroleum products could continue to diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect our vendors, suppliers +and customers ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition. +Our success depends on finding, developing or acquiring additional reserves. +Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically +recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves +and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations +for the development, production, exploration and acquisition of oil and natural gas reserves. Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our +bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the level of oil and natural gas we are able to produce from existing wells; +• +the prices at which oil and natural gas are sold; and +• +our ability to acquire, locate and produce new reserves. +We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and natural gas reserves, our exploratory projects or other replacement +activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices +increase significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and +integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense +competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our +ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and +difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with +regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such +additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to +effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may +fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +20 +Table of Contents +Index to Financial Statements +Our Canadian oil sands project is a complex undertaking and may not be completed at our estimated cost +or at all. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a +24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near +Fort McMurray within a few miles of other existing oil sands projects. Our total net investment in Grizzly was approximately $69.0 million as of December 31, 2011. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes +and four water supply test wells, tested nine separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the +Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Fabrication and onsite construction on the +first phase of development at Algar Lake is currently underway. This is a complex project and financing has not been secured. There can be no assurance that financing can be obtained on commercially reasonable terms or at all. +Shortage of rigs, equipment, raw materials, supplies or personnel may restrict our operations. +The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand +and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in the number of +active rigs in service. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. Shortages of drilling rigs, equipment, raw materials +(particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our +financial condition and results of operations. +We rely on a few key employees whose absence or loss could disrupt our operations resulting +in a loss of revenues. +Many key responsibilities within our business have been assigned to a small number of employees. +The loss of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists could disrupt our operations resulting +in a loss of revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Liddell’s written employment agreement and Mr. Palm’s oral employment agreement, and our executives are not +restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key +person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees. +We may be limited in our ability to book additional proved undeveloped reserves under the recent SEC rules. +One of the impacts of the recent SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be +drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production. +There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information herein represents +estimates +21 +Table of Contents +Index to Financial Statements +prepared by Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields at December 31, 2011, with respect to our WCBB and Niobrara +fields at December 31, 2010, and with respect to our WCBB field at December 31, 2009; by Ryder Scott Company L.P., or Ryder Scott, at December 31, 2011, and by Pinnacle Energy Services, LLC, or Pinnacle, at December 31, 2010 and +2009, with respect to our assets in the Permian Basin in West Texas; and by our personnel with respect to our overriding royalty and non-operated interests at December 31, 2011 and with respect to our Hackberry fields, overriding royalty and +non-operated interests at December 31, 2010 and 2009. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil +and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and +abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, +all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based +on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our +reserves will likely vary from estimates, and such variances may be material. +Estimates of reserves as of year-end 2011, 2010 +and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2011, 2010 and 2009, +respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for +undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. +The present value of future +net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2011, 2010 and 2009 on +average price equal to the unweighted average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2011, 2010 and 2009, respectively, in accordance with the revised guidelines +of the SEC applicable to reserves estimates for such years. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from +proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time +and risks associated with us or the oil and natural gas industry in general. +As of December 31, 2011, approximately 56% +of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures and +conduct these operations successfully, but these assumptions may not be accurate, and this may not occur. +22 +Table of Contents +Index to Financial Statements +There are numerous uncertainties in estimating quantities of bitumen reserves and resources in +connection with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be realized. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of +economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and +engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, +to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of +recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. +Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than +upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the +estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil +prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly’s lands cannot be determined at this time. +The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. When these facilities are +unavailable, our operations can be interrupted and our revenues reduced. +The marketability of our oil and natural gas +production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or +denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a +significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field, which is our largest producing field. In October 2006, for example, a natural gas line in this field operated by +our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to +transport our oil production from the WCBB field. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we will +be required to again shut in or curtail production from the field. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from the field, would adversely affect our financial +condition and results of operations. +A substantial portion of our producing properties is located in Louisiana, making us vulnerable to +risks associated with operating in this region. +Our largest field by production, WCBB, is located approximately five miles +off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions such as +fog or rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at +rates we consider reasonable or that any particular types of coverage will be available. +23 +Table of Contents +Index to Financial Statements +Our identified drilling locations, which are part of our anticipated future drilling plans, are +susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified +over 600 drilling locations on our Louisiana, West Texas and Western Colorado properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of +uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the numerous potential drilling locations we have +identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could +adversely affect our business. +Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing +profits. +Our operations are subject to all of the hazards and operating risks associated with drilling for and production +of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, and +environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, +natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and repairs to resume operations +In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not +all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its +purchase. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may not be able to secure additional +insurance of bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners +of properties purchased by us, which liabilities may not be covered by insurance. +Our development and exploratory drilling efforts and our +well operations may not be profitable or achieve our targeted returns. +We acquire significant amounts of unproved property +in order to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties +and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. +Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all +or any portion of our investment in such unproved property or wells. +Drilling for oil and natural gas may involve +unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is +often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of +equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, +expected +24 +Table of Contents +Index to Financial Statements +costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain +than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries +will be ultimately successful when used in newly developed shale formations. +We are not the operator of all of our oil and natural gas +properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties. +Approximately 67% of our proved reserves at December 31, 2011 are attributable to our acreage position in the Permian Basin. We are +not the operator of these properties and may have limited ability to exercise influence over the operations of these and our other non-operated properties or their associated costs. Dependence on the operator and other working interest owners for +these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities +on properties operated by others depend upon a number of factors that will be largely outside of our control, including: +• +the timing and amount of capital expenditures; +• +the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; +• +the operator’s expertise and financial resources; +• +approval of other participants in drilling wells; +• +selection of technology; and +• +the rate of production of the reserves. +In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when +required by the majority owner or operator, our interests in these projects may be reduced or forfeited. +Our undeveloped acreage in our +Niobrara Formation must be drilled before lease expiration this year and within the next three years in order to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could +result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, +2011, we had leases in our Niobara Formation representing approximately 13,000 net acres, 32%, 35%, 12%, 1% and 20% of which were scheduled to expire in 2012, 2013, 2014, 2015 and thereafter, respectively. The cost to renew such leases may increase +significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. +We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them. +Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable +reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review +will not reveal all existing or potential problems. In the course of our due +25 +Table of Contents +Index to Financial Statements +diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion, when an inspection is made. We may not be +able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may +not perform in accordance with our expectations. +Our operations are subject to various governmental regulations which require compliance +that can be burdensome and expensive. +Our oil and natural gas operations are subject to various federal, state and local +governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the +spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual +production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other substances and materials produced or used in +connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may +result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed +increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and +stricter environmental legislation and regulations will continue. +Federal and state legislative and regulatory initiatives relating to +hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing +is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to +fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is +exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel +fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the +U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing +activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, both the EPA and the House committee have requested that certain companies provide +them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +In March 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2009 were reintroduced in +the United States Senate and House of Representatives. These bills, which are currently under consideration by Congress, would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate +regulations requiring permits and implementing potential new requirements on hydraulic fracturing under the SDWA. This could, in turn, require state regulatory agencies in states with programs delegated under the SDWA to impose additional +requirements on hydraulic fracturing operations. In addition, the bills would require persons using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas, of their fracturing fluids to a regulatory +26 +Table of Contents +Index to Financial Statements +agency, which would make the information public via the internet. Additionally, fracturing companies would be required to disclose specific chemical contents of fluids, including proprietary +chemical formulas, to state authorities or to a requesting physician or nurse if deemed necessary by the physician or nurse in connection with a medical emergency. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental +Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal +agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In addition, the U.S. Department of Energy is conducting an investigation of practices the EPA could recommend to +better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public +lands and disclosure of fracturing fluid constituents. Also, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to +investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information +Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. On August 11, 2011, the Shale +Gas Subcommittee of the Secretary of Energy Advisory Board released a report proposing recommendations to reduce the potential environmental impacts from shale gas production. +In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale +formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. +These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur +initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. +Some states in which we +operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing +fluids. For example, in September 2011, the Ohio legislature began consideration of legislation that would impose a temporary moratorium on drilling involving hydraulic fracturing pending the delivery of the EPA study regarding the relationship +between hydraulic fracturing and drinking water resources. On May 31, 2011, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. It was signed +into law on June 17, 2011, effective as of September 1, 2011. The Texas Railroad Commission will adopt rules and regulations implementing this legislation in two phases by July 1, 2012 and 2013, respectively. The new law requires that +the well operator disclose the list of chemical ingredients subject to the requirements of federal OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The +total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which +well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana +Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Number, subject to certain trade secret protections. In September 2011, the North Dakota +Industrial Commission proposed new regulations for hydraulic fracturing activities that could require well operators, under certain circumstances, to disclose the hydraulic fluid +27 +Table of Contents +Index to Financial Statements +composition, including the trade name, supplier, ingredients, Chemical Abstracts Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. We plan to +use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore +drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts +on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing +practices. If new laws or regulations that significantly restrict hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as +well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if +hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, +reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or +the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal +or state legislation governing hydraulic fracturing. +The recent adoption of derivatives legislation by the U.S. Congress could have an +adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. +The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and +other risks associated with our business. The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter +derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and +regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major +energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these +regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application +of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as +creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available +liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and +increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and its cash flows may be less +predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the +28 +Table of Contents +Index to Financial Statements +volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could +therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash +flows. +Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of +operations and cash flows. +The U.S. President’s Fiscal Year 2012 Budget Proposal includes provisions that would, if +enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for +domestic production activities relating to oil and natural gas exploration and development and (iii) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, could adversely affect our business, +financial condition, results of operations and cash flows. +The adoption of climate change legislation by Congress could result in +increased operating costs and reduced demand for the oil and natural gas we produce. +Many nations have agreed to limit +emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the +burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic +regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide +emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the +environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of +regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other +of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not +require immediate reductions in GHG emissions. The EPA adopted the stationary source rule in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in +September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 +for emissions occurring in 2010. More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage, and distribution +facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. +Furthermore, in +July 2011, the EPA proposed several new emissions standards to reduce volatile organic compound, or VOC, emissions from several types of processes and equipment used in the oil and natural gas industry, including a 95 percent reduction in VOCs +emitted during the construction or modification of hydraulically-fractured wells. Additionally, on August 23, 2011, the EPA published a proposed rule in the Federal Register that would establish new air emission controls for oil and natural gas +production and natural gas processing operations. The EPA received public comment an conducted public hearings regarding the proposed rules and must take final action on them by April 3, 2012. +In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security (ACES) Act that, among other things, would +have established a cap-and-trade system to regulate greenhouse gas +29 +Table of Contents +Index to Financial Statements +emissions and would have required an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. The ACES Act did not pass the Senate, however, and so was not +enacted by the 111th Congress. The United States Congress is likely to again consider a climate change bill in the future. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the +planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as +refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal +is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG +monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations +addressing greenhouse gas emissions would impact our business. +Any failure by us to comply with applicable environmental laws +and regulations may result in governmental authorities taking actions that could adversely impact our operations and financial condition, including the: +• +issuance of administrative, civil and criminal penalties; +• +denial, suspension or revocation of necessary permits, licenses or other authorizations; +• +imposition of injunctive obligations or limitations on our operations; +• +requirement for additional pollution controls; and +• +required performance of site investigatory, remedial or other corrective actions. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense +hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some +areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at +this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +We face extensive competition in our industry. +The oil and natural gas +industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market +petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural +gas prices and production, the availability of alternative energy sources and the application of government regulation. +We depend upon two +customers for the sale of most of our oil and natural gas production. +The availability of a ready market for any oil +and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of +skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of +30 +Table of Contents +Index to Financial Statements +gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell +Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus +Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI differential less $2.70 per barrel for transportation. During 2011, we sold 93% and 7% of our oil production to Shell and Windsor, respectively and 22%, 27%, and 50% +of our natural gas production to Windsor, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor, respectively and 50%, 32%, and 10% of our natural gas production to Windsor, +Chevron and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor, Chevron and Hilcorp Energy Company, +respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Our method of +accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of +accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are +capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such +capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. +Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each +quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is +defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month prices for 2011, 2010 and 2009 and prior to 2009, +unescalated year-end prices, adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on +the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the +book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a +significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. If prices of oil, natural gas and natural gas liquids decrease, we may be +required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of operations. +Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling +operations. +Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools +used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other +advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. +31 +Table of Contents +Index to Financial Statements +We have entered into forward sales contracts and fixed price swaps and may in the future enter into +additional contracts for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. +To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB +production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward +sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of +oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of +$108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from January 2013 through June 2013, we +entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, we delivered approximately +31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances +where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges +and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging ,” and related pronouncements. +A terrorist +attack or armed conflict could harm our business. +Terrorist activities, anti-terrorist efforts and other armed conflicts +involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and +societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of +terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some +insurance coverage may become more difficult to obtain, if available at all. +Conservation measures and technological advances could reduce +demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer demand for +alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material +adverse effect on our business, financial condition, results of operations and cash flows. +Risks Related to Our Common Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it +may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: +• +changes in oil and natural gas prices; +• +changes in production levels; +• +changes in governmental regulations and taxes; +32 +Table of Contents +Index to Financial Statements +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary +significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some +future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders. +As of February 20, 2012, Charles E. Davidson, our largest stockholder, beneficially owned approximately 13.3% of our +outstanding common stock. As a result, this stockholder acting alone is able to exercise significant influence over most matters requiring approval by our stockholders, including the election of directors and the approval of significant corporate +transactions. Such a concentration of ownership may have the effect of delaying or preventing a change in control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices. +We do not currently pay dividends on our common stock and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to +retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders +of our common stock. +A change of control could limit our use of net operating losses. +As of December 31, 2011, we had a net operating loss, or NOL, carry forward of approximately $116.8 million for federal income tax +purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax +year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +Future sales of our common stock may depress our stock price. +We and +certain of our stockholders have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market or the perception that these sales may +occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of February 20, +2012, there were 55,621,371 shares of our common stock issued and outstanding, excluding 203,348 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan, 29,832 shares issuable upon exercise of +outstanding warrants and 356,241 shares issuable upon exercise of outstanding options to purchase our common stock granted under our Amended and Restated 2005 Stock Incentive Plan. +We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover +effects. +We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of +preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or +33 +Table of Contents +Index to Financial Statements +resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and +the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of +incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special +rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce +the value of our common stock. +In addition, specific rights granted to future holders of preferred stock could be used to +restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current +stockholders. +The existence of some provisions in our organizational documents could delay or prevent a change in control of +our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +IT EM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Proved Oil and Natural Gas +Reserves +SEC Rule-Making Activity +In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, +using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the +following: +• +Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis. +• +Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities +will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. +• +Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production +history. +• +Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees +the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. +• +Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method +of extraction. +We adopted the rules effective December 31, 2009, as required by the SEC. +Evaluation and Review of Reserves. +Reserve estimates at December 31, 2011 were prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields (33% of our proved reserves at December 31, 2011), by Ryder Scott with +respect to our assets in +34 +Table of Contents +Index to Financial Statements +the Permian Basin in West Texas (67% of our proved reserves at December 31, 2011) and by our personnel with respect to our overriding royalty and non-operated interests (less than 1% of our +proved reserves at December 31, 2011). +NSAI and Ryder Scott are independent petroleum engineering firms. Copies of their +summary reserve reports are included as Exhibit 99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, +independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not +own an interest in any of our properties and are not employed by us on a contingent basis. +We maintain an internal staff of +petroleum engineers and geoscience professionals who work closely with NSAI and Ryder Scott to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our WCBB, Hackberry and Niobrara fields and +our assets in the Permian Basin, respectively. Our internal technical team members meet with NSAI and Ryder Scott periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide +historical information to NSAI and Ryder Scott for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our proved reserves attributable to our other minority +interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our chief reserve engineer is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum +engineer with over 30 years of reservoir and operations experience and our geophysical staff has over 60 years combined industry experience. Our technical staff uses historical information for our properties such as ownership interest, oil and gas +production, well test data, commodity prices and operating and development costs. +The preparation of our proved reserve +estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: +• +review and verification of historical production data, which data is based on actual production as reported by us; +• +preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision; +• +review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all +significant reserve changes and all new proved undeveloped reserves additions; +• +direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; and +• +verification of property ownership by our land department. +35 +Table of Contents +Index to Financial Statements +The following table sets forth our estimated proved reserves at December 31, +2011, 2010 and 2009: +Year Ended December 31, +2011 +2010 +2009 +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Proved developed +7,485 +6,152 +7,230 +6,068 +6,165 +4,325 +Proved undeveloped +9,260 +9,576 +12,474 +10,090 +11,323 +10,007 +Total (1) +16,745 +15,728 +19,704 +16,158 +17,488 +14,332 +Year Ended December 31, +2011 +2010 +2009 +Total net proved oil and natural gas reserves (MBOE) (1) +19,367 +22,397 +19,877 +PV-10 value (in millions) (2) +$ +490.5 +$ +392.6 +$ +263.0 +Standardized measure (in millions) (3) +$ +376.7 +$ +315.5 +$ +240.8 +(1) +Estimates of reserves as of year-end 2011, 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received +on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2011, 2010 and 2009, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2011, +2010 and 2009. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although +we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. +(2) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net +revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our +reserve reports for the years ended December 31, 2011, 2010 and 2009 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $96.19 +per barrel and $4.12 per MMBtu, $76.16 per barrel and $4.38 per MMBtu and $57.90 per barrel and $3.87 per MMBtu, respectively, and in each case adjusted by lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of +the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating +performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure—standardized measure of +discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value: +December 31, +2011 +2010 +2009 +Standardized measure of discounted future net cash flows +$ +376,681,000 +$ +315,487,000 +$ +240,774,000 +Add: Present value of future income tax discounted at 10% +113,791,000 +77,117,000 +22,237,000 +PV-10 value +$ +490,472,000 +$ +392,604,000 +$ +263,011,000 +(3) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, +production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure +includes the effect of future income taxes. +36 +Table of Contents +Index to Financial Statements +The above table does not include proved reserves net to our interest in Tatex II, Tatex III +or Grizzly. For further discussion of our interest in Tatex II, Tatex III and Grizzly, see Item 1. “Description of Business—Additional Properties.” +The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that +cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, +the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil +and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors” +contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. +Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves, or PUDs, at +December 31, 2011, 2010 and 2009 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 20 to +our consolidated financial statements included in this report. Also contained in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves. Additional information regarding +our proved reserves can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” and “—Critical Accounting Policies and Estimates” included in this +report. +Proved Undeveloped Reserves (PUDs) +As of December 31, 2011, our proved undeveloped reserves totaled 9,260 MBOE of oil and 9,576 MMcf of natural gas, for a total of 10,856 MBOE. Approximately 88% of our PUDs at year-end 2011 were +located in the Permian Basin, 6% of our PUDs were located in WCBB, 3% were located in our East Hackberry field and 3% of our PUDs were located in our Niobrara field. PUDs will be converted from undeveloped to developed as the applicable wells begin +production. Changes in PUDs that occurred during 2011 were primarily due to: +• +Additions of 531 MBOE attributable to 2011 acquisitions and extensions; +• +Conversion of approximately 2,502 MBOE attributable to PUDs into proved developed reserves; +• +Positive revisions of approximately 331 MBOE in PUDs due to changes in commodity prices; and +• +Downward revisions to estimates of approximately 1,660 MBOE +Costs incurred relating to the development of PUDs were approximately $41.2 million in 2011. Estimated future development costs relating to the development of PUDs are projected to be approximately $52.6 +million in 2012, $49.9 million in 2013, $55.4 million in 2014, $51.4 million in 2015 and $58.3 in 2016. +All PUD drilling +locations are scheduled to be drilled prior to the end of 2016. +As of December 31, 2011, 16% of our total proved +reserves were classified as proved developed non-producing. +37 +Table of Contents +Index to Financial Statements +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2011 +2010 +2009 +Production Volumes: +Oil (MBbls) +2,128 +1,777 +1,531 +Gas (MMcf) +878 +788 +491 +Natural gas liquids (MGal) +2,468 +2,821 +2,719 +Oil equivalents (MBOE) +2,333 +1,976 +1,677 +Average Prices: +Oil (per Bbl) +$ +104.33 +(1) +$ +68.29 +(1) +$ +53.29 +(1) +Gas (per Mcf) +$ +4.37 +$ +4.40 +$ +4.06 +Natural gas liquids (per Gal) +$ +1.25 +$ +1.00 +$ +0.73 +Oil equivalents (per BOE) +$ +98.13 +$ +64.61 +$ +51.01 +Production Costs: +Average production costs (per BOE) +$ +8.96 +$ +8.92 +$ +9.73 +Average production taxes (per BOE) +$ +11.29 +$ +7.07 +$ +5.84 +Total production costs and production taxes (per BOE) +$ +20.25 +$ +15.99 +$ +15.57 +(1) +Includes various derivative contracts at a weighted average price of: +January – December 2009 +$ +55.01 +January – December 2010 +$ +57.55 +January – December 2011 +$ +86.96 +Excluding the effect of fixed price swap contracts, the average oil price for 2011 would have been $107.13 +per barrel of oil and $100.68 per BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the effect of forward sales contracts, the average oil price for 2010 would have been $78.12 per +barrel of oil and $73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. Excluding the effect of forward sales contracts, the average oil price for 2009 would have been $57.98 per +barrel of oil and $55.29 per BOE. The total volume hedged for 2009 represented approximately 49% of our total sales volumes for the year. +38 +Table of Contents +Index to Financial Statements +The following table provides a summary of our production, average sales prices and average +production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2011: +Year Ended December 31, +2011 +2010 +2009 +WCBB +Net Production +Oil (MBbls) +1,258 +1,176 +1,209 +Gas (MMcf) +237 +410 +192 +NGL (Mgal) +— +— +— +Total (MBOE) +1,298 +1,244 +1,241 +Average Sales Price: +Oil (per Bbl) +$ +104.49 +$ +62.57 +$ +52.39 +Gas (per Mcf) +$ +4.16 +$ +4.44 +$ +4.44 +NGL (per Gal) +$ +— +$ +— +$ +— +Average Production Cost (per BOE) +$ +8.71 +$ +8.90 +$ +8.54 +Permian Basin +Net Production +Oil (MBbls) +208 +134 +118 +Gas (MMcf) +272 +256 +236 +NGL (Mgal) +2,436 +2,797 +2,694 +Total (MBOE) +312 +243 +221 +Average Sales Price: +Oil (per Bbl) +$ +90.86 +$ +76.48 +$ +55.19 +Gas (per Mcf) +$ +3.94 +$ +4.21 +$ +3.72 +NGL (per Gal) +$ +1.25 +$ +1.00 +$ +0.73 +Average Production Cost (per BOE) +$ +17.59 +$ +9.78 +$ +10.71 +Productive Wells and Acreage +The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the total gross and net developed and undeveloped acres as of +December 31, 2011. +NRI/WI (1) +Productive +Oil Wells (2) +Productive +Gas Wells +Non-Productive +Oil Wells +Non-Productive +Gas Wells +Developed +Acreage (3) +Undeveloped +Acreage +(4) +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +West Cote Blanche Bay Field (5) +80.1/100 +94 +94 +1 +1 +171 +171 +18 +18 +5,668 +5,668 +— +— +E. Hackberry Field (6) +79.4/100 +30 +30 +— +— +93 +93 +— +— +3,291 +3,291 +— +— +W. Hackberry Field +87.5/100 +2 +2 +— +— +23 +23 +— +— +592 +592 +— +— +Permian Basin +35.4/46.87 +121 +57 +— +— +— +— +— +— +8,880 +4,119 +26,786 +11,190 +Niobrara Formation (7) +39.7/47.9 +6 +3 +— +— +2 +1 +— +— +3,954 +1,977 +26,033 +13,016 +Williston Basin (8) +2.8/3.3 +6 +.2 +— +— +— +— +— +— +1,708 +132 +3,659 +685 +Overrides/Royalty Non-operated +Various +133 +.2 +— +— +— +— +— +— +— +— +— +Total +392 +186.4 +1 +1 +289 +288 +18 +18 +24,093 +15,779 +56,478 +24,891 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes six gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been perpetuated by production. +39 +Table of Contents +Index to Financial Statements +(4) +E. Hackberry acreage does not include 2,868 net acres subject to a two-year exploration agreement. +(5) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(6) +NRI shown is for producing wells. +(7) +The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed or extended, we +have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. +Leases representing 32%, 35%, 12%, 1% and 20% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2012, 2013, 2014, 2015 and thereafter, respectively. +(8) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +Completed and Present Drilling and Recompletion Activities +The following +table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the +number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +2011 +2010 +2009 +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +100 +96 +87 +84 +64 +62.5 +Dry +— +— +— +— +— +— +Total +100 +96 +87 +84 +64 +62.5 +Development: +Productive +82 +57 +57 +42 +25 +18 +Dry +3 +3 +— +— +1 +1 +Total +85 +60 +57 +42 +26 +19 +Exploratory: +Productive +1 +1 +— +— +1 +1 +Dry +— +— +— +— +— +— +Total +1 +1 +— +— +1 +1 +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title +examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas +properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management’s opinion, will in the aggregate materially restrict our operations. +ITEM 3. +LEGAL PROCEEDINGS +The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR +maintains that we paid approximately $1.8 million less in severance taxes under fixed price terms than the +40 +Table of Contents +Index to Financial Statements +severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any liability to the LDR for underpayment of severance taxes +and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. We have maintained our right to contest any final +assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15th Judicial District Court, Lafayette Parish, in Louisiana against our company seeking $2,275,729 in severance taxes, plus interest +and court costs. We filed a response denying any liability to the LDR for underpayment of severance taxes and are defending our company in the lawsuit. The LDR had taken no further action on this lawsuit since filing its petition two years ago until +recently when it propounded discovery requests to which we have responded. We recently served discovery requests on the LDR and are awaiting the LDR’s response. +In December 2010, the LDR filed two identical lawsuits against us in different venues to recover allegedly underpaid severance taxes on crude oil for the period January 1, 2007 through +December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, we have denied all liability and will vigorously +defend the lawsuit. The cases are in the very early stages, and we have not yet filed a response to these lawsuits. Recently, the LDR filed motions to stay the lawsuits before we filed any responsive pleadings. The LDR has advised us that it intends +to pursue settlement discussions with us and other similarly situated defendants in separate proceedings. +In November 2006, +Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us, Great White Pressure Control LLC, or Great White, and six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United +States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White’s employment of the former Cudd employees and sought unspecified +monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007. We filed a motion for summary judgment on October 5, 2007. +The Court entered a final interlocutory judgment in favor of all defendants, including us, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the +district court decision finding, among other things, that the district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the case to +the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition with the state court (a) alleging that we conspired with the other defendants to misappropriate, and misappropriated +Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking unspecified monetary damages. On April 13, 2010, our motion to be dismissed from the proceeding for lack of personal jurisdiction was +denied. This state court proceeding is in its initial stages. In 2011, the parties have continued with written discovery and production of documents. On February 15, 2011, Cudd filed a third amended petition seeking $26.5 million (based on a +report prepared by its expert) plus disgorgement of $6.0 million in payments by Great White to the individual defendants and punitive damages. Gulfport denies these claims with respect to itself. Recently, the parties began the process of scheduling +and taking depositions and it is anticipated that the case will remain in the discovery phase for at least the next several months. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for contamination across the surface of where the defendants operated in +an action entitled Reeds et al. v. BP American Production Company et al., 38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name us as a defendant, alleges that the plaintiffs’ property +located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. Plaintiffs allege that the defendants conducted, directed and participated in various oil +and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged +negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and +41 +Table of Contents +Index to Financial Statements +response costs and stigma damages. On December 7, 2010, we were served with a copy of the plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and +six additional defendants, including us, bringing the total number of defendants to 21. It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original +petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property +to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; +damages for loss of use of land and lost profits and income; attorney fees and expenses; and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to us, current defendants include ExxonMobil Oil +Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil +Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, we filed a pleading challenging the +legal sufficiency of the petitions on several grounds and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by us and similar pleadings filed by other defendants, the +plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue. In response, we and numerous defendants re-urged their +pleadings challenging the legal sufficiency of the petitions. Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the court on May 25, 2011 and were denied. The court signed the written judgment on +December 9, 2011. We noticed our intent to seek supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application. We filed our supervisory writ and the matter +is currently pending before the Louisiana Third Circuit Court of Appeal. We have served discovery requests and are currently responding to discovery requests from the plaintiffs. +Due to the current stages of the above litigation, the outcomes are uncertain and management cannot determine the amount of loss, if any, +that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse affect on our financial condition or results of operations. +In addition to the above, we have been named as a defendant in various other lawsuits related to our business. The ultimate resolution of +such other matters is not expected to have a material adverse effect on our financial condition or results of operations. +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +42 +Table of Contents +Index to Financial Statements +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market under the +symbol “GPOR.” The following table sets forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2010 +First Quarter +$ +12.68 +$ +8.89 +Second Quarter +15.25 +10.60 +Third Quarter +14.71 +10.37 +Fourth Quarter +22.92 +13.59 +2011 +First Quarter +$ +36.38 +$ +20.00 +Second Quarter +38.09 +23.84 +Third Quarter +37.49 +22.00 +Fourth Quarter +37.80 +18.72 +2012 +First Quarter (through February 15, 2012) +$ +36.54 +$ +29.63 +On February 15, 2012, the last reported sale price of our common stock on The NASDAQ Global Select +Market was $35.34. +Unregistered Sales of Equity Securities and Use of Proceeds +None, except that we issued 566 shares of our common stock upon exercise of certain outstanding warrants to purchase our common stock in +transactions exempt from registration under the Securities Act of 1933, as amended. +Holders of Record +At the close of business on February 15, 2012, there were 332 stockholders of record holding 55,621,371 shares of our outstanding +common stock. There were approximately 21,921 beneficial owners of our common stock as of February 15, 2012. +Dividend Policy +We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our operations. +Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends to the holders of our common stock. +43 +Table of Contents +Index to Financial Statements +ITEM 6. +SELECTED FINANCIAL DATA +You should read the following selected consolidated financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the +consolidated financial statements and the related notes appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2011, December 31, 2010 and December 31, +2009 and the selected consolidated balance sheet data at December 31, 2011 and December 31, 2010 are derived from our audited consolidated financial statements appearing elsewhere in this report. The selected consolidated statements of +operations data for the fiscal years ended December 31, 2008 and December 31, 2007 and the selected consolidated balance sheet data at December 31, 2009, December 31, 2008 and December 31, 2007 are derived from our +audited consolidated financial statements that are not included in this report. The historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during any of the periods set forth in the +following table. +Fiscal Year Ended December 31, +2011 +2010 +2009 +2008 +2007 +Selected Consolidated Statements of Operations Data: +Revenues +$ +229,254,000 +$ +127,921,000 +$ +85,968,000 +$ +141,873,000 +$ +106,315,000 +Costs and expenses: +Lease operating expenses +20,897,000 +17,614,000 +16,316,000 +22,856,000 +16,670,000 +Production taxes +26,333,000 +13,966,000 +9,797,000 +15,813,000 +12,667,000 +Depreciation, depletion and amortization +62,320,000 +38,907,000 +29,225,000 +42,472,000 +29,681,000 +Impairment of oil and natural gas properties +— +— +— +272,722,000 +— +General and administrative +8,074,000 +6,063,000 +4,992,000 +6,843,000 +5,802,000 +Accretion expense +666,000 +617,000 +582,000 +560,000 +554,000 +118,290,000 +77,167,000 +60,912,000 +361,266,000 +65,374,000 +Income (Loss) from Operations +110,964,000 +50,754,000 +25,056,000 +(219,393,000 +) +40,941,000 +Other (Income) Expense: +Interest expense +1,400,000 +2,761,000 +2,309,000 +4,762,000 +3,091,000 +Insurance recoveries +— +— +(1,050,000 +) +(769,000 +) +— +Settlement of fixed price contracts +— +— +— +(39,000,000 +) +— +Interest income +(186,000 +) +(387,000 +) +(564,000 +) +(540,000 +) +(523,000 +) +Loss from equity method investments +1,418,000 +977,000 +706,000 +656,000 +477,000 +2,632,000 +3,351,000 +1,401,000 +(34,891,000 +) +3,045,000 +Income (Loss) before Income Taxes +108,332,000 +47,403,000 +23,655,000 +(184,502,000 +) +37,896,000 +Income Tax Expense (Benefit) +(90,000 +) +40,000 +28,000 +— +121,000 +Net Income (Loss) +108,422,000 +47,363,000 +23,627,000 +(184,502,000 +) +37,775,000 +Net Income (Loss) Available to Common Stockholders +$ +108,422,000 +$ +47,363,000 +$ +23,627,000 +$ +(184,502,000 +) +$ +37,775,000 +Net Income (Loss) Per Common Share—Basic: +$ +2.22 +$ +1.08 +$ +0.55 +$ +(4.33 +) +$ +1.03 +Net Income (Loss) Per Common Share—Diluted: +$ +2.20 +$ +1.07 +$ +0.55 +$ +(4.33 +) +$ +1.01 +44 +Table of Contents +Index to Financial Statements +At December 31, +2011 +2010 +2009 +2008 +2007 +Selected Consolidated Balance Sheet Data: +Total assets +$ +691,158,000 +$ +319,693,000 +$ +227,344,000 +$ +221,873,000 +$ +419,137,000 +Total debt, including current maturity +$ +2,283,000 +$ +51,917,000 +$ +52,428,000 +$ +70,731,000 +$ +66,533,000 +Total liabilities +$ +58,808,000 +$ +108,637,000 +$ +102,293,000 +$ +107,772,000 +$ +115,015,000 +Stockholders’ equity +$ +632,350,000 +$ +211,056,000 +$ +125,051,000 +$ +114,101,000 +$ +304,122,000 +45 +Table of Contents +Index to Financial Statements +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes +included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating +results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk +Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. +Overview +We are an +independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. +During 2010, we acquired an acreage position in the Niobrara Formation of northwestern Colorado and, during 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio and have commitments to acquire additional acreage there. +We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to +achieve reserve growth and increase our cash flow through our annual drilling programs. +2011 Highlights +• +Oil and natural gas revenues increased 79% to $229.0 million for the year ended December 31, 2011 from $127.6 million for the year ended +December 31, 2010. +• +Net income increased 129% to $108.4 million for the year ended December 31, 2011 from $47.4 million for the year ended December 31, 2010. +• +Production increased 18% to approximately 2,333,208 barrels of oil equivalent, or BOE, for the year ended December 31, 2011 from approximately +1,975,576 BOE for the year ended December 31, 2010. +• +During 2011, we drilled 86 gross (61 net) wells, which includes 40 gross (17 net) wells drilled by our operators in the Permian Basin and Bakken, and +recompleted 100 gross (96 net) wells. Of our 86 new wells drilled, 75 were completed as producing wells, three were non-productive and eight were waiting on completion. +• +During 2011, we acquired approximately 600 additional net acres in the Permian Basin, which brought our total net acreage position in the Permian Basin +to approximately 15,300 net acres. +• +During 2011, we acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in Eastern Ohio. We intend to continue +to pursue additional opportunities in this area and have commitments with various future closing dates which could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We +recently spud our first well on our Utica Shale acreage in February 2012. +• +In March, July and December of 2011, we completed a series of underwritten public offerings of an aggregate of 10,810,000 shares of our common stock +and received approximately $307.1 million in aggregate net proceeds, which we used to repay then outstanding balances under our revolving credit facility, fund acquisitions of certain of our Utica Shale properties and for general corporate purposes, +which include future capital expenditures associated with drilling, development and infrastructure, principally in the Utica Shale in Ohio. +Critical Accounting Policies and Estimates +Our discussion and analysis of +our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in +46 +Table of Contents +Index to Financial Statements +the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, +liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our +management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that +we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates +used in the preparation of our consolidated financial statements: +Oil and Natural Gas Properties . We use the full cost +method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas +properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas +properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at +10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period 2011, 2010 and 2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions +or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being +amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If +the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped +properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such +dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled $138.6 million +at December 31, 2011 and $16.8 million at December 31, 2010. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. +Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development. +Ceiling Test . Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling +test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center +ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period January – December of +the applicable year beginning with 2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated +abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost +being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown +is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as +a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural +gas and natural gas liquids decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. No ceiling test impairment was required for the year ended +December 31, 2011. +47 +Table of Contents +Index to Financial Statements +Asset Retirement Obligations . We have obligations to remove equipment and restore +land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. +We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value +of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially +recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the +related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation +requirements. +The fair value of the liability associated with these retirement obligations is determined using significant +assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment +risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount +of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural +gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates. +Oil and Gas +Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future +under current operating and economic parameters. Netherland, Sewell & Associates, Inc., Ryder Scott Company and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2011 on a +well-by-well basis for our properties. +Reserves and their relation to estimated future net cash flows impact our depletion +and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in +accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities +of oil and natural gas eventually recovered. +Income Taxes . We use the asset and liability method of accounting for +income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and +(2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a +change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. +48 +Table of Contents +Index to Financial Statements +Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative +factors. A valuation allowance for our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2011, a valuation allowance of $12.3 million had been +provided for deferred tax assets based on the uncertainty of future taxable income. +Revenue Recognition . We derive +almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from +one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior +months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. +Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred +and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent +payment of legal liabilities. +Derivative Instruments and Hedging Activities . We seek to reduce our exposure to +unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, “ Derivatives and Hedging ,” as amended. It requires that all derivative instruments be +recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures +prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or +other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and +the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value +are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged +item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. +To mitigate the +effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the +period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel +before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 +through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of +oil per day at a weighted average price of $109.73 per barrel. For the period from January 2013 through June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 +contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 +production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contracts and fixed price swaps are accounted for +as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. +49 +Table of Contents +Index to Financial Statements +RESULTS OF OPERATIONS +Results of Operations +The markets for oil and natural gas have +historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2011 +2010 +2009 +Production Volumes: +Oil (MBbls) +2,128 +1,777 +1,531 +Gas (MMcf) +878 +788 +491 +Natural gas liquids (MGal) +2,468 +2,821 +2,719 +Oil equivalents (MBOE) +2,333 +1,976 +1,677 +Average Prices: +Oil (per Bbl) +$ +104.33 +(1) +$ +68.29 +(1) +$ +53.29 +(1) +Gas (per Mcf) +$ +4.37 +$ +4.40 +$ +4.06 +Natural gas liquids (per Gal) +$ +1.25 +$ +1.00 +$ +0.73 +Oil equivalents (per BOE) +$ +98.13 +$ +64.61 +$ +51.01 +Production Costs: +Average production costs (per BOE) +$ +8.96 +$ +8.92 +$ +9.73 +Average production taxes (per BOE) +$ +11.29 +$ +7.07 +$ +5.84 +Total production costs and production taxes (per BOE) +$ +20.25 +$ +15.99 +$ +15.57 +(1) +Includes various derivative contracts at a weighted average price of: +January – December 2009 +$ +55.01 +January – December 2010 +$ +57.55 +January – December 2011 +$ +86.96 +Excluding the net effect of fixed price swap contracts, the average oil price for 2011 would have been +$107.13 per barrel of oil and $100.68 BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the net effect of forward sales contracts, the average oil price for 2010 would have been +$78.12 per barrel of oil and $73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. Excluding the effect of forward sales contracts, the average oil price for 2009 would have been +$57.98 per barrel of oil and $55.29 per BOE. The total volume hedged for 2009 represented approximately 49% of our total sales volumes for the year. +From 2010 to 2011, our net equivalent oil production increased 18% from 1,975,576 BOE to 2,333,208 BOE due to the results of our 2011 drilling and recompletion activities. From 2009 to 2010, our net +equivalent oil production also increased 18% from 1,677,000 BOE to 1,976,000 BOE due to increased drilling activity, the success of our drilling activities and our acquisitions of additional properties in the Permian Basin and the Niobrara +Formation. We currently estimate that our 2012 production will be between 3,000,000 and 3,200,000 BOE. However, such estimate may change based on a change in our expected drilling and recompletion activities or the changing economic climate and +unforeseen events, such as hurricanes. +50 +Table of Contents +Index to Financial Statements +Comparison of the Years Ended December 31, 2011 and December 31, 2010 +We reported net income of $108,422,000 for the year ended December 31, 2011 as compared to net income of $47,363,000 for the year +ended December 31, 2010. This 129% increase in period-to-period net income was due primarily to an 18% increase in net production to 2,333,208 BOE and a 52% increase in realized BOE prices to $98.13 for the year ended December 31, 2011, +partially offset by a 19% increase in lease operating expenses, a 33% increase in general and administrative expenses and an 89% increase in production taxes. +Oil and Gas Revenues . For the year ended December 31, 2011, we reported oil and natural gas revenues of $228,953,000 as compared to oil and natural gas revenues of $127,636,000 during 2010. +This $101,317,000, or 79%, increase in revenues was primarily attributable to an 18% increase in net production to 2,333,208 BOE from 1,975,576 BOE and a 52% increase in realized BOE prices to $98.13 from $64.61, in each case for the year ended +December 31, 2011 as compared to the year ended December 31, 2010. +The following table summarizes our oil and +natural gas production and related pricing for the years ended December 31, 2011 and December 31, 2010: +Year Ended +December 31, +2011 +2010 +Oil production volumes (MBbls) +2,128 +1,777 +Gas production volumes (MMcf) +878 +788 +Natural gas liquids production volumes (MGal) +2,468 +2,821 +Oil equivalents (MBOE) +2,333 +1,976 +Average oil price (per Bbl) +$ +104.33 +$ +68.29 +Average gas price (per Mcf) +$ +4.37 +$ +4.40 +Average natural gas liquids (per Gal) +$ +1.25 +$ +1.00 +Oil equivalents (per BOE) +$ +98.13 +$ +64.61 +Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes +increased to $20,897,000 for the year ended December 31, 2011 from $17,614,000 for 2010. This increase was mainly the result of an increase in expenses related to chemicals and fuel, equipment repairs and maintenance, field supervision, +overhead, property taxes, rentals, salt water disposal and well workovers. +Production Taxes . Production taxes +increased to $26,333,000 for the year ended December 31, 2011 from $13,966,000 for 2010. This increase was primarily related to an 18% increase in production and a 52% increase in the average realized BOE price received resulting in a 79% +increase in oil and gas revenues. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, +or DD&A, expense increased to $62,320,000 for the year ended December 31, 2011, and consisted of $61,965,000 in depletion of oil and natural gas properties and $355,000 in depreciation of other property and equipment, as compared to total +DD&A expense of $38,907,000 for 2010. This increase was due to an increase in our full cost pool as a result of our capital activities, an increase in our production and a decrease in our total proved reserves volume used to calculate our total +DD&A expense. +General and Administrative Expenses . Net general and administrative expenses increased to $8,074,000 +for the year ended December 31, 2011 from $6,063,000 for 2010. This $2,011,000 increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in legal expenses, +franchise taxes and bank fees, partially offset by an increase in administrative services reimbursements under the acquisition team agreement and an increase in general and administrative costs related to exploration and development activity +capitalized to the full cost pool. +Accretion Expense . Accretion expense increased slightly to $666,000 for the year +ended December 31, 2011 from $617,000 for the same period in 2010. +51 +Table of Contents +Index to Financial Statements +Interest Expense . Interest expense decreased to $1,400,000 for the year ended +December 31, 2011 from $2,761,000 for 2010 due to a decrease in the interest rate paid and the repayment of all of our outstanding debt under our revolving credit facility during the fourth quarter of 2011 so that no amounts were outstanding as +of December 31, 2011, as compared to $49,500,000 outstanding as of the same date in 2010. Further, during 2010, in conjunction with the repayment of our prior revolving credit facility on September 30, 2010, we expensed approximately +$225,000 in unamortized loan fees associated with this facility, which is included in interest expense in our consolidated statements of operations for the year ended December 31, 2010. Total weighted debt outstanding under our revolving credit +facility was $21,084,000 for the year ended December 31, 2011 and $46,931,000 for 2010. As of December 14, 2011 (the latest date during the year ended December 31, 2011 on which we had borrowings outstanding), amounts borrowed under +our credit facility bore interest at the Eurodollar rate of 2.26%. +Income Taxes . As of December 31, 2011, we had +a net operating loss carry forward of approximately $116.8 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is +more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion +will not be realized. At December 31, 2011, a valuation allowance of $12,347,000 had been provided for deferred tax assets, with the exception of $1,000,000 related to alternative minimum taxes. We recognized an income tax benefit of $90,000 +for the year ended December 31, 2011. +Comparison of the Years Ended December 31, 2010 and December 31, 2009 +We reported net income of $47,363,000 for the year ended December 31, 2010, as compared to net income of $23,627,000 for the year +ended December 31, 2009. This 100% increase in 2010 was due primarily to a 27% increase in realized BOE prices to $64.61 from $51.01 and an 18% increase in net production to 1,976,000 BOE, partially offset by an 8% increase in lease operating +expenses, a 21% increase in general and administrative expenses and a 43% increase in production taxes. +Oil and Gas +Revenues . For the year ended December 31, 2010, we reported oil and natural gas revenues of $127,636,000 as compared to oil and natural gas revenues of $85,576,000 during 2009. This $42,060,000, or 49%, increase in revenues is primarily +attributable to a 27% increase in realized BOE prices to $64.61 from $51.01 and an 18% increase in net production to 1,975,576 BOE for the year ended December 31, 2010 from 1,677,474 BOE for the year ended December 31, 2009. +The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2010 and +December 31, 2009: +Year Ended +December 31, +2010 +2009 +Oil production volumes (MBbls) +1,777 +1,531 +Gas production volumes (MMcf) +788 +491 +Natural gas liquids production volumes (MGal) +2,821 +2,719 +Oil equivalents (MBOE) +1,976 +1,677 +Average oil price (per Bbl) +$ +68.29 +$ +53.29 +Average gas price (per Mcf) +$ +4.40 +$ +4.06 +Average natural gas liquids (per Gal) +$ +1.00 +$ +0.73 +Oil equivalents (per BOE) +$ +64.61 +$ +51.01 +Lease Operating Expenses . Lease operating expenses not including production taxes increased to +$17,614,000 for 2010 from $16,316,000 for 2009. This increase is mainly a result of an increase in ad valorem taxes and expenses related to well workovers. +52 +Table of Contents +Index to Financial Statements +Production Taxes . Production taxes increased to $13,966,000 for 2010 from $9,797,000 +for 2009. This increase was primarily related to a 49% increase in oil and gas revenues as a result of a 27% increase in average realized BOE price received and an 18% increase in production. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $38,907,000 +for 2010, and consisted of $38,600,000 in depletion on oil and natural gas properties and $307,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $29,225,000 for 2009. This +increase was due to an increase in our full cost pool as a result of our capital activities and an increase in our production used to calculate our total DD&A expense. +General and Administrative Expenses . Net general and administrative expenses increased to $6,063,000 for 2010 from $4,992,000 for 2009. This $1,071,000 increase was primarily due to a $450,000 +increase in franchise taxes, a $200,000 increase in legal expenses and increases related to salaries, benefits expenses partially offset by an increase in general and administrative overhead related to exploration and development activity +capitalized to the full cost pool. +Accretion Expense. Accretion expense increased slightly to $617,000 for 2010 from +$582,000 for 2009. +Interest Expense . Interest expense increased to $2,761,000 for 2010 from $2,309,000 for 2009. This +increase was due to an increase in the interest rate paid as well as the recognition of approximately $225,000 in unamortized loan fees associated with the termination of the Bank of America revolving credit facility. Effective September 30, +2010, this facility, along with the term loan with Bank of America, were repaid with borrowings under our new senior secured revolving credit facility with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead +arranger, and Amegy Bank National Association, entered into on September 30, 2010. This increase in interest expense was partially offset by a decrease in average debt outstanding for the year ended December 31, 2010, as compared to the +year ended December 31, 2009. Total debt outstanding under our new revolving credit facility was $49.5 million as of December 31, 2010, as compared to $49.9 million outstanding under our prior facilities with Bank of America as of the same +date in 2009. Total weighted debt outstanding under our facilities was $46.9 million for 2010 and $59.9 million for 2009. Until September 30, 2010, amounts borrowed under our term loan and revolving credit facility with Bank of America bore +interest of 3.76% and 3.25%, respectively. At December 31, 2010, amounts borrowed under our new revolving credit agreement bore interest at the Eurodollar rate of 3.77%. +Income Taxes . As of December 31, 2010, we had a net operating loss carry forward of approximately $52.4 million, in addition to numerous temporary differences, which gave rise to a deferred +tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred +tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At December 31, 2010, a valuation allowance of $54.4 million had been provided for deferred tax assets, with the +exception of $628,000 for alternative minimum taxes. We paid $40,000 of state income tax for the year ended December 31, 2010. +Liquidity and Capital Resources +Overview . Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our bank and other credit facilities and the issuance of +equity securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or our oil and natural gas production. During 2011, we received aggregate net proceeds (before offering +expenses) of approximately $307.1 million from the sale of shares of our common stock. During 2010, we received net proceeds (before offering expenses) of approximately $21.6 million from the sale of shares of our common stock. +53 +Table of Contents +Index to Financial Statements +Net cash flow provided by operating activities was $158,138,000 for the year ended +December 31, 2011 as compared to net cash flow provided by operating activities of $85,835,000 for 2010. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 52% increase in net +realized BOE prices and an 18% increase in our net BOE production. +Net cash flow provided by operating activities was +$85,835,000 for 2010, as compared to $53,299,000 for 2009. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 27% increase in net realized prices and an 18% increase in our net BOE +production. +Net cash used in investing activities for the year ended December 31, 2011 was $323,248,000 as compared to +$105,315,000 for 2010. During the year ended December 31, 2011, we spent $287,292,000 in additions to oil and natural gas properties, of which $106,947,000 was spent on our 2011 drilling and recompletion programs, $31,872,000 was spent on +expenses attributable to the wells drilled and recompleted during 2010, $8,320,000 was spent on compressors and other facility enhancements, $177,000 was spent on plugging costs, $124,713,000 was spent on lease related costs, primarily the +acquisition of leases in the Utica Shale and $3,651,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, $3,182,000 was loaned to, and $22,676,000 was invested in, Grizzly +during the year ended December 31, 2011, and $3,794,000, $6,009,000 and $2,142,000 was invested in our investments in Tatex III, Bison and Muskie, respectively, during the year ended December 31, 2011. During the year ended +December 31, 2011, we used cash from operations and proceeds from our equity offering for our investing activities. +Net +cash used in investing activities for 2010 was $105,315,000, as compared to $39,246,000 for 2009. During 2010, we spent $101,644,000 in additions to oil and natural gas properties, of which $51,356,000 was spent on our 2010 drilling and recompletion +programs, $16,735,000 was spent on acquisitions in our Niobrara and Permian fields, $11,697,000 was spent on expenses attributable to the wells drilled during 2009, $3,093,000 was spent on our 2009 recompletions, $6,838,000 was spent on compressors +and other facility enhancements, $1,425,000 was spent on plugging costs, $771,000 was spent on lease related costs and $3,449,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In +addition, we paid $3,719,000 in cash calls to Grizzly during 2010. During 2010, we used cash from operations, borrowings under our credit facilities and proceeds from our equity offering to fund our investing activities. +Net cash provided by financing activities for the year ended December 31, 2011 was $256,539,000 as compared to $20,224,000 for 2010. +The 2011 amount provided by financing activities was primarily attributable to the net proceeds of $307,154,000 from our equity offerings and exercise of stock options, partially offset by net principal payments of $49,500,000 on borrowings under +our credit facility. The 2010 amount provided by financing activities was primarily attributable to the net proceeds from our equity offerings of $21,358,000. +Net cash provided by financing activities for 2010 was $20,224,000 as compared to net cash used by financing activities of $18,273,000 for 2009. The 2010 amount provided by financing activities is +primarily attributable to the net proceeds of $21,358,000 from our equity offering and borrowings of $52,200,000 under our new credit facility, partially offset by principal payments of $49,903,000 on borrowings under our prior credit facilities +with Bank of America. We used the net proceeds of our 2010 equity offering to fund the acquisition of our interests in the Niobrara Formation, pay the purchase price for a portion of the additional acreage acquired by us in the Permian Basin in 2010 +and for general corporate purposes. +The 2009 amount used by financing activities was primarily attributable to principal +payments on borrowings of $18,206,000 under our credit facility with Bank of America, partially offset by $30,000 received from the exercise of stock options. +Credit Facility . On September 30, 2010, we entered into a $100.0 million senior secured revolving credit facility with The Bank of Nova Scotia, as administrative agent and letter of credit +issuer and lead arranger, and Amegy Bank National Association, or Amegy Bank, which revolving credit facility initially matured on +54 +Table of Contents +Index to Financial Statements +September 30, 2013 and had a borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24, 2010. On May 3, 2011, we entered into a first +amendment to the revolving credit facility with the Bank of Nova Scotia, Amegy Bank, KeyBank National Association, or KeyBank, and Société Générale. Pursuant to the terms of the first amendment, KeyBank and +Société Générale were added as additional lenders, the maximum amount of the revolving credit facility was increased to $350.0 million, the borrowing base was increased to $90.0 million, certain fees and rates payable by +us under the credit facility were decreased, and the maturity date was extended until May 3, 2015. On October 31, 2011, we entered into additional amendments to our revolving credit facility pursuant to which, among other things, the +borrowing base under this facility was increased to $125.0 million. On December 14, 2011, we repaid all outstanding borrowings under this credit facility with a portion of the net proceeds of our equity offering completed on December 5, +2011 pending the application of such proceeds to fund our additional Utica Shale lease acquisitions and for general corporate purposes. Our revolving credit facility is secured by substantially all of our assets. Our wholly-owned subsidiaries +guaranteed our obligations under the revolving credit facility. +Advances under our revolving credit facility, as amended, may +be in the form of either base rate loans or Eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.50%, plus (2) the highest of: (a) the federal funds rate plus 0.5%, +(b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the Eurodollar rate for an interest period of one month plus 1.00%. The interest rate for Eurodollar +loans is equal to (1) the applicable rate, which ranges from 2.00% to 3.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the +offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center +banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 14, 2011 (the latest date during the year ended December 31, 2011 on which we had borrowings outstanding), +amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate (2.26%). +Our revolving credit +facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make +fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as +specified in the credit facility. The credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash +revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such +period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or +writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, +expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offering, and less non-cash income +attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in +compliance with all covenants at December 31, 2011. +In connection with our scheduled spring 2012 borrowing base +redetermination completed in February 2012, Scotia Capital has advised us that it has recommended an increase to our borrowing base from the current level of $125.0 million to $150.0 million, subject to the approval of the other banks in the +syndicate. +Building Loans . In June 2004, we purchased the office building we occupy in Oklahoma City, Oklahoma, for +$3.7 million. One loan associated with this building matured in March 2006 and bore interest at the rate of 6% per annum, while a second loan was scheduled to mature in June 2011. We entered into a new building loan +55 +Table of Contents +Index to Financial Statements +in March 2011 to refinance the $2.4 million outstanding at that time. The new agreement extends the maturity date of the building loan to February 2016 and reduces the interest rate from +6.5% per annum to 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. As of December 31, +2011, approximately $2.3 million was outstanding on this loan. +Capital Expenditures . Our recent capital commitments +have been primarily for the execution of our drilling programs, to fund Grizzly’s delineation drilling program and initial preparation of the Algar Lake facility and for acquisitions, primarily in the Permian Basin, the Niobrara Formation and +Utica Shale. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry +conditions, and (2) explore acquisition and disposition opportunities. +Of our net reserves at December 31, 2011, +56% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed +reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities. +At December 31, 2011, our booked inventory of prospects included approximately 24 drilling locations at WCBB. The drilling schedule +used in our December 31, 2011 reserve report anticipates that all of those wells will be drilled by 2015. During 2011, we recompleted 68 wells and drilled 21 wells, of which 19 were completed as producers, one was non-productive and one was +waiting on completion, for an aggregate cost of $42.4 million. From January 1, 2012 through February 20, 2012, we recompleted six existing wells and drilled three new wells at our WCBB field, and at February 20, 2012 we were in the +process of drilling two additional wells. We currently intend to recomplete 60 wells and drill 22 to 24 new wells during 2012. Our aggregate drilling and recompletion expenditures for our WCBB field during 2012 are estimated to be approximately +$36.0 million to $38.0 million. +In our East Hackberry field, in 2011, we recompleted 24 existing wells and drilled 22 wells, +of which 17 were completed as producers, two were non-productive and three were waiting on completion for an aggregate cost of $51.9 million. From January 1, 2012 through February 20, 2012, we recompleted two existing wells and drilled two +new wells at our East Hackberry field, and at February 20, 2012 we were in the process of drilling two additional wells. We currently intend to drill 10 to 12 wells and recomplete 10 wells in our East Hackberry field in 2012. Total capital +expenditures for our East Hackberry field during 2012 are estimated to be approximately $24.0 million to $26.0 million. +In +the Permian Basin, our booked inventory of prospects at December 31, 2011 included 252 gross (124 net) future development drilling locations. During 2011, 39 gross (17 net) wells were drilled on this acreage, of which 35 were completed as +producers and four were waiting on completion for an aggregate cost of $38.4 million. From January 1, 2012 through February 20, 2012, two gross (one net) wells were drilled on this acreage and were waiting on completion and at +February 20, 2012 one gross (0.5 net) additional well was being drilled. We currently anticipate that our capital requirements to drill a total of 23 to 25 gross (11.5 to 12.5 net) wells and recomplete five gross (2.5 net) wells in the Permian +Basin in West Texas will be approximately $23.0 million to $25.0 million in 2012. In an effort to facilitate the development of our Permian Basin and other domestic acreage, in 2011 we acquired a 25% equity interest in Bison Drilling and Field +Services LLC, or Bison, which owns and operates four drilling rigs. Our purchase price for this interest was approximately $6.0 million, subject to adjustment. The remaining 75% equity interest is owned by entities controlled by Wexford. Also in +2011, we acquired a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand, for $2.1 million. Muskie is controlled by Wexford. The 2012 +budgets for Bison and Muskie have not yet been established. +56 +Table of Contents +Index to Financial Statements +In the Niobrara Formation in northwestern Colorado, in 2011, we completed a 60 square mile +3-D seismic survey, have received a processed version of the seismic and are selecting future drilling locations. Our total capital expenditures in the Niobrara Formation were approximately $6.8 million in 2011 relating to the seismic survey, +drilling three gross (1.5 net) wells and leasehold acquisitions. We currently anticipate that our total capital expenditures in the Niobrara Formation will be approximately $5.0 million to $6.0 million in 2012 to drill five to seven gross wells. +In the Utica shale in Ohio, in 2011, we acquired approximately 98,000 gross (49,000 net) acres for $118.4 million. During +2012, we expect to spend up to an additional $30.0 million to $35.0 million to acquire up to another 27,000 gross (13,500 net) acres. In addition, during 2012, we currently anticipate spending another $72.0 million to $76.0 million to drill 20 gross +(ten net) wells. +During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2011, +our net investment in Grizzly was approximately $69.0 million. Our capital requirements in 2012 for this project are estimated to be approximately $40.0 million to $43.0 million, primarily for the expenses associated with the construction of the +Algar Lake facility and drilling activity during the 2011-2012 winter drilling season. In addition, in January 2012, Grizzly entered into an agreement to purchase approximately 46,700 acres of oil sands leases in the Athabasca oil sands area for +$225.0 million CAD. Our capital contribution obligation to Grizzly for our portion of the purchase price is approximately $56.3 million and will be due at closing of the transaction. We expect to fund this amount with borrowings under our revolving +credit facility. +Net capital expenditures in 2011 relating to our interest in Thailand were approximately $2.9 million. +Capital expenditures in 2012 relating to our interests in Thailand are expected to be approximately $6.0 million, which we believe will be partially funded from our share of production from the Phu Horm field. +Our total capital expenditures for 2012 are currently estimated to be in the range of $215.0 million to $225.0 million, excluding the +acquisition costs of our Utica Shale acreage, Grizzly May River acquisition and any other potential acquisitions. This is up from the $130.0 million spent on 2011 activities due to improved commodity pricing and cost environment. We intend to +continue to monitor pricing and cost developments and make adjustments to our future capital expenditure programs as warranted. +We believe that our cash on hand, cash flow from operations and borrowings under our revolving credit facility will be sufficient to meet +our normal recurring operating needs and capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling programs, pursue additional acquisitions or accelerate our Canadian oil sands project, we +may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed +capital may not be available to us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions +that may be favorable to us. +Commodity Price Risk +The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the West Texas +Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million +British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. On February 15, 2012, the West Texas Intermediate posted price for crude oil was $101.80 per barrel and the Henry Hub spot market price of natural +gas was $2.43 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, +and may result in write downs of oil and natural gas properties due to ceiling test limitations. +57 +Table of Contents +Index to Financial Statements +To mitigate the effects of commodity price fluctuations, we were party to forward sales +contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 +through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we +entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 +barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For +the period from January 2013 through June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45% of our 2010 production. +Under the 2011 contracts, we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. Such arrangements may expose us to risk of financial +loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB +ASC 815 and related pronouncements. +Commitments +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through +March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment +obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2011, the plugging and abandonment trust totaled approximately +$3.1 million. At December 31, 2011, we have plugged 320 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. +Contractual and Commercial Obligations +The following table sets forth our contractual and commercial obligations at December 31, 2011. +Payment due by period (1) +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +Short-term and long-term debt +$ +2,283,000 +$ +141,000 +$ +476,000 +$ +1,666,000 +$ +— +Asset retirement obligations +12,653,000 +620,000 +1,361,000 +792,000 +9,880,000 +Total +$ +14,936,000 +$ +761,000 +$ +1,837,000 +$ +2,458,000 +$ +9,880,000 +(1) +Does not include estimated interest of $129,000 less than one year, $335,000 1-3 years and $16,000 3-5 years and short-term derivative instruments of $1,601,000 less +than one year. +New Accounting Pronouncements +In December 2008, the SEC published a final rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies +have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also allow companies to disclose their probable and possible reserves. In addition, the new disclosure requirements require companies to +(a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average +price based upon the prior 12-month period rather than year end prices. The new requirements were effective for +58 +Table of Contents +Index to Financial Statements +annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We adopted this final rule as of December 31, 2009. The adoption of the rule resulted in a lower price +used in reserve calculations and a decrease in 2009 reserves. Updated disclosures are included in Item 2. “Properties—Proved Oil and Natural Gas Reserves” and Note 20 to our consolidated financial statements included in this +report. +In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and +Disclosures” (currently codified in FASB ASC Topic 932, “Extractive Activities – Oil & Gas”), or FASB ASC 932. The purpose of the amendments in this Update was to align the oil and gas reserve estimation and disclosure +requirements of FASB ASC 932 with the requirements in the SEC’s final rule, “Modernization of Oil and Gas Reporting . “ The amendments to FASB ASC 932 were effective for annual reports on Form 10-K for fiscal years ending on +or after December 31, 2009. We adopted FASB ASC 932 effective December 31, 2009, the impact of which is noted above. +In May 2011, the FASB issued Accounting Standards Update No. 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and +IFRS,” which provides amendments to FASB ASC Topic 820, “Fair Value Measurements and Disclosure”, or FASB ASC 820. The purpose of the amendments in this update is to create common fair value measurement and disclosure requirements +between GAAP and IFRS. The amendments change certain fair value measurement principles and enhance the disclosure requirements. The amendments to FASB ASC 820 are effective for interim and annual periods beginning after December 15, 2011. +In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of +Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income”, or FASB ASC 220. The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions +that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive +income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The amendments to FASB ASC 220 are effective for interim and annual periods +beginning after December 15, 2011 and should be applied retrospectively. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend +primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional +factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the +expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical +advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members +of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements +with any certainty. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot +market price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in +59 +Table of Contents +Index to Financial Statements +January 2006. On February 15, 2012, the West Texas Intermediate posted price for crude oil was $101.80 per barrel and the Henry Hub spot market price of natural gas was $2.43 per MMBtu. Any +substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write +downs of oil and natural gas properties due to ceiling test limitations. +For the period January 2010 through February 2010, +we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials. For the period March 2010 through December 2010, +we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price +swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at +a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from January +2013 through June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, +we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. Such arrangements may expose us to risk of financial loss in certain +circumstances, including instances where production is less than expected or oil prices increase. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and +related pronouncements. At December 31, 2011, we had a net asset derivative position of $1.6 million related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have +reduced the fair value of these instruments by approximately $7.7 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by $7.7 million. However, any realized derivative gain or loss +would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. +Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or Eurodollar loans. As such, our interest expense is +sensitive to fluctuations in the prime rates in the U.S. or, if the Eurodollar rates are elected, the Eurodollar rates. At December 14, 2011 (the latest date during the year ended December 31, 2011 on which we had borrowings outstanding), +amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 2.26%. Based on the current debt structure, a 1% increase in interest rates would increase interest expense by approximately $130,000 per year, based on +$13.0 million outstanding under our revolving credit facility as of December 14, 2011. As of December 31, 2011, we did not have any interest rate swaps to hedge our interest risks. +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief +Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the +60 +Table of Contents +Index to Financial Statements +Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are +also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required +disclosures. +As of December 31, 2011, an evaluation was performed under the supervision and with the participation of +management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities +Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2011, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial +reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is +also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are +designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent +limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with +respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control +over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal +Control—Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2011. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year +ended December 31, 2011 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2011, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +61 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over +financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an +opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the +standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in +all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control +based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial +statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, +in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject +to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria +established in Internal Control—Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of +the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, +stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 27, 2012 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 27, 2012 +62 +Table of Contents +Index to Financial Statements +ITEM 9B. +OTHER INFORMATION +None. +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission +within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning Item 11—Executive Compensation, see our definitive proxy statement, which will be filed with the +Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12—Security Ownership of Certain Beneficial Owners and Management and Related Stockholder +Matters, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions +noted therein that are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and +Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For information concerning Item 14—Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after +the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +63 +Table of Contents +Index to Financial Statements +PART IV +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +List the following documents filed as part of this report: +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and +Windsor Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a +party seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the +SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, +2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the +Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with +the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a +Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other +Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding +LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on +April 26, 2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.5 +of Amendment No. 1 to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +10.5+ +Summary of Oral Employment Agreement with James D. Palm (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on +December 7, 2010). +64 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +10.6 +Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead +arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). +10.7 +Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). +10.8 +First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative +agent, letter of credit issuer and lead arranger, Amegy Bank National Association, KeyBank National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by +the Company with the SEC on May 9, 2011). +10.9 +Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. +000-19514, filed by the Company with the SEC on November 4, 2011). +10.10 +Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders party thereto (incorporated by +reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Ryder Scott Company. +23.4* +Consent of Pinnacle Energy Services, LLC. +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Ryder Scott Company. +101.INS** +XBRL Instance Document. +101.SCH** +XBRL Taxonomy Extension Schema Document. +65 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +101.CAL** +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF** +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB** +XBRL Taxonomy Extension Labels Linkbase Document. +101.PRE** +XBRL Taxonomy Extension Presentation Linkbase Document. +* +Filed herewith. +** +Furnished herewith, not filed. ++ +Management contract, compensatory plan or arrangement. +66 +Table of Contents +Index to Financial Statements +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the +undersigned, thereunto duly authorized. +Date: February 27, 2012 +GULFPORT ENERGY CORPORATION +By: +/s/ JAMES D. PALM +James D. Palm +Chief Executive Officer +In accordance with the Exchange Act, this report has been signed below by the following persons on +behalf of the registrant and in the capacities and on the dates indicated. +Date: February 27, 2012 +By: +/s/ JAMES D. PALM +James D. Palm +Chief Executive Officer and Director +(Principal Executive +Officer) +Date: February 27, 2012 +By: +/s/ MIKE LIDDELL +Mike Liddell +Chairman of the Board and Director +Date: February 27, 2012 +By: +/s/ MICHAEL G. MOORE +Michael G. Moore +Vice President and Chief Financial Officer +(Principal Financial and +Accounting Officer) +Date: February 27, 2012 +By: +/s/ DONALD DILLINGHAM +Donald Dillingham +Director +Date: February 27, 2012 +By: +/s/ CRAIG GROESCHEL +Craig Groeschel +Director +Date: February 27, 2012 +By: +/s/ DAVID L. HOUSTON +David L. Houston +Director +Date: February 27, 2012 +By: +/s/ SCOTT E. STRELLER +Scott E. Streller +Director +S-1 +Table of Contents +Index to Financial Statements +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets, December 31, 2011 and December 31, 2010 +F-3 +Consolidated Statements of Operations, Years Ended December 31, 2011, 2010 and +2009 +F-4 +Consolidated Statements of Stockholders’ Equity and Comprehensive Income, Years Ended December +31, 2011, 2010 and 2009 +F-5 +Consolidated Statements of Cash Flows, Years Ended December 31, 2011, 2010 and +2009 +F-6 +Notes to Financial Statements +F-7 +F-1 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated +statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. +Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in accordance with the +standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material +misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by +management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation and Subsidiaries as of +December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of +America. +As discussed in Note 1, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s +internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and +our report dated February 27, 2012 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 27, 2012 +F-2 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +(Amounts rounded to nearest thousand) +December 31, +2011 +December 31, +2010 +Assets +Current assets: +Cash and cash equivalents +$ +93,897,000 +$ +2,468,000 +Accounts receivable—oil and gas +28,019,000 +14,952,000 +Accounts receivable—related parties +4,731,000 +573,000 +Prepaid expenses and other current assets +1,327,000 +1,732,000 +Short-term derivative instruments +1,601,000 +— +Total current assets +129,575,000 +19,725,000 +Property and equipment: +Oil and natural gas properties, full-cost accounting, $138,623,000 and $16,778,000 excluded from amortization in 2011 and 2010, +respectively +1,035,754,000 +747,344,000 +Other property and equipment +8,024,000 +7,609,000 +Accumulated depletion, depreciation, amortization and impairment +(575,142,000 +) +(512,822,000 +) +Property and equipment, net +468,636,000 +242,131,000 +Other assets: +Equity investments +86,824,000 +33,021,000 +Note receivable—related party +— +20,006,000 +Other assets +5,123,000 +4,182,000 +Total other assets +91,947,000 +57,209,000 +Deferred tax asset +1,000,000 +628,000 +Total assets +$ +691,158,000 +$ +319,693,000 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +43,872,000 +$ +41,155,000 +Asset retirement obligation—current +620,000 +635,000 +Short-term derivative instruments +— +4,720,000 +Current maturities of long-term debt +141,000 +2,417,000 +Total current liabilities +44,633,000 +48,927,000 +Asset retirement obligation—long-term +12,033,000 +10,210,000 +Long-term debt, net of current maturities +2,142,000 +49,500,000 +Total liabilities +58,808,000 +108,637,000 +Commitments and contingencies (Notes 17 and 18) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; +0 issued and outstanding +— +— +Stockholders’ equity: +Common stock—$.01 par value, 100,000,000 authorized, 55,621,371 issued and outstanding in 2011 and 44,645,435 in +2010 +556,000 +446,000 +Paid-in capital +604,584,000 +296,253,000 +Accumulated other comprehensive income (loss) +2,663,000 +(1,768,000 +) +Retained earnings (accumulated deficit) +24,547,000 +(83,875,000 +) +Total stockholders’ equity +632,350,000 +211,056,000 +Total liabilities and stockholders’ equity +$ +691,158,000 +$ +319,693,000 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2011 +2010 +2009 +Revenues: +Oil and condensate sales +$ +222,025,000 +$ +121,350,000 +$ +81,587,000 +Gas sales +3,838,000 +3,468,000 +1,992,000 +Natural gas liquid sales +3,090,000 +2,818,000 +1,997,000 +Other income (expense) +301,000 +285,000 +392,000 +229,254,000 +127,921,000 +85,968,000 +Costs and expenses: +Lease operating expenses +20,897,000 +17,614,000 +16,316,000 +Production taxes +26,333,000 +13,966,000 +9,797,000 +Depreciation, depletion, and amortization +62,320,000 +38,907,000 +29,225,000 +General and administrative +8,074,000 +6,063,000 +4,992,000 +Accretion expense +666,000 +617,000 +582,000 +118,290,000 +77,167,000 +60,912,000 +INCOME FROM OPERATIONS +110,964,000 +50,754,000 +25,056,000 +OTHER (INCOME) EXPENSE: +Interest expense +1,400,000 +2,761,000 +2,309,000 +Insurance proceeds +— +— +(1,050,000 +) +Interest income +(186,000 +) +(387,000 +) +(564,000 +) +Loss from equity method investments +1,418,000 +977,000 +706,000 +2,632,000 +3,351,000 +1,401,000 +INCOME BEFORE INCOME TAXES +108,332,000 +47,403,000 +23,655,000 +INCOME TAX EXPENSE (BENEFIT) +(90,000 +) +40,000 +28,000 +NET INCOME +$ +108,422,000 +$ +47,363,000 +$ +23,627,000 +NET INCOME PER COMMON SHARE: +Basic +$ +2.22 +$ +1.08 +$ +0.55 +Diluted +$ +2.20 +$ +1.07 +$ +0.55 +Weighted average common shares outstanding—Basic +48,754,840 +43,863,190 +42,667,581 +Weighted average common shares outstanding—Diluted +49,206,963 +44,256,092 +43,017,648 +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME +(Amounts rounded to nearest thousand) +Additional +Paid-in +Capital +Accumulated +Other +Comprehensive +Income(Loss) +Retained +Earnings +(Accumulated +Deficit) +Total +Stockholders’ +Equity +Common Stock +Shares +Amount +Balance at January 1, 2009 +42,639,201 +$ +426,000 +$ +273,343,000 +$ +(4,803,000 +) +$ +(154,865,000 +) +$ +114,101,000 +Net income +— +— +— +— +23,627,000 +23,627,000 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +5,499,000 +— +5,499,000 +Change in fair value of derivative instruments +— +— +— +(13,422,000 +) +— +(13,422,000 +) +Reclassification of settled contracts +— +— +— +(5,313,000 +) +— +(5,313,000 +) +Total Comprehensive Income +10,391,000 +Stock Compensation +— +— +529,000 +— +— +529,000 +Issuance of Restricted Stock +43,458 +— +— +— +— +— +Issuance of Common Stock +through exercise of options +13,750 +1,000 +29,000 +— +— +30,000 +Balance at December 31, 2009 +42,696,409 +427,000 +273,901,000 +(18,039,000 +) +(131,238,000 +) +125,051,000 +Net income +— +— +— +— +47,363,000 +47,363,000 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +2,255,000 +— +2,255,000 +Change in fair value of derivative instruments +— +— +— +(4,720,000 +) +— +(4,720,000 +) +Reclassification of settled contracts +— +— +— +18,736,000 +— +18,736,000 +Total Comprehensive Income +63,634,000 +Stock Compensation +— +— +492,000 +— +— +492,000 +Issuance of Common Stock in public offering, net of related expenses +1,668,503 +17,000 +21,341,000 +— +— +21,358,000 +Issuance of Common Stock through exercise of warrants +173,109 +2,000 +204,000 +— +— +206,000 +Issuance of Restricted Stock +58,525 +— +— +— +— +— +Issuance of Common Stock through exercise of options +48,889 +— +315,000 +— +— +315,000 +Balance at December 31, 2010 +44,645,435 +446,000 +296,253,000 +(1,768,000 +) +(83,875,000 +) +211,056,000 +Net income +— +— +— +— +108,422,000 +108,422,000 +Other Comprehensive Income (Loss): +Foreign currency translation adjustment +— +— +— +(1,865,000 +) +— +(1,865,000 +) +Change in fair value of derivative instruments +— +— +— +1,576,000 +— +1,576,000 +Reclassification of settled contracts +— +— +4,720,000 +— +4,720,000 +Total Comprehensive Income +112,853,000 +Stock Compensation +— +— +1,287,000 +— +— +1,287,000 +Issuance of Common Stock in public offering, net of related expenses +10,810,000 +108,000 +306,053,000 +— +— +306,161,000 +Issuance of Common Stock through exercise of warrants +566 +— +— +— +— +— +Issuance of Restricted Stock +63,370 +1,000 +(1,000 +) +— +— +— +Issuance of Common Stock through exercise of options +102,000 +1,000 +992,000 +— +— +993,000 +Balance at December 31, 2011 +55,621,371 +$ +556,000 +$ +604,584,000 +$ +2,663,000 +$ +24,547,000 +$ +632,350,000 +F-5 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2011 +2010 +2009 +Cash flows from operating activities: +Net income +$ +108,422,000 +$ +47,363,000 +$ +23,627,000 +Adjustments to reconcile net income to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +666,000 +617,000 +582,000 +Depletion, depreciation and amortization +62,320,000 +38,907,000 +29,225,000 +Stock-based compensation expense +772,000 +295,000 +317,000 +Loss from equity investments +1,418,000 +977,000 +706,000 +Interest income—note receivable +(147,000 +) +(267,000 +) +(547,000 +) +Unrealized gain on derivative instruments +(25,000 +) +— +— +Deferred income tax benefit +(372,000 +) +(95,000 +) +120,000 +Amortization of loan commitment fees +540,000 +— +— +Changes in operating assets and liabilities: +(Increase) decrease in accounts receivable +(13,067,000 +) +(5,460,000 +) +3,051,000 +(Increase) decrease in accounts receivable—related party +(4,158,000 +) +(437,000 +) +965,000 +Decrease (increase) in prepaid expenses +405,000 +315,000 +(1,002,000 +) +Increase in other assets +— +(75,000 +) +— +Increase (decrease) in accounts payable and accrued liabilities +1,612,000 +4,948,000 +(3,686,000 +) +Settlement of asset retirement obligation +(248,000 +) +(1,253,000 +) +(59,000 +) +Net cash provided by operating activities +158,138,000 +85,835,000 +53,299,000 +Cash flows from investing activities: +Deductions to cash held in escrow +8,000 +8,000 +8,000 +Additions to other property, plant and equipment +(415,000 +) +(427,000 +) +(14,000 +) +Additions to oil and gas properties +(287,292,000 +) +(101,644,000 +) +(49,533,000 +) +Proceeds from sale of oil and gas properties +1,384,000 +304,000 +18,286,000 +Advances on note receivable to related party +(3,182,000 +) +(2,877,000 +) +(4,377,000 +) +Contributions to investment in Grizzly Oil Sands ULC +(22,676,000 +) +(842,000 +) +— +Distributions from investment in Tatex Thailand II, LLC +870,000 +565,000 +197,000 +Contributions to investment in Tatex Thailand III, LLC +(3,794,000 +) +(402,000 +) +(3,813,000 +) +Contributions to investment in Bison Drilling and Field Services LLC +(6,009,000 +) +— +— +Contributions to investment in Muskie Holdings LLC +(2,142,000 +) +— +— +Net cash used in investing activities +(323,248,000 +) +(105,315,000 +) +(39,246,000 +) +Cash flows from financing activities: +Principal payments on borrowings +(97,634,000 +) +(52,711,000 +) +(18,303,000 +) +Borrowings on line of credit +48,000,000 +52,200,000 +— +Loan commitment fees +(981,000 +) +(1,144,000 +) +— +Proceeds from issuance of common stock, net of offering costs, and exercise of stock options +307,154,000 +21,879,000 +30,000 +Net cash provided by (used in) financing activities +256,539,000 +20,224,000 +(18,273,000 +) +Net increase (decrease) in cash and cash equivalents +91,429,000 +744,000 +(4,220,000 +) +Cash and cash equivalents at beginning of period +2,468,000 +1,724,000 +5,944,000 +Cash and cash equivalents at end of period +$ +93,897,000 +$ +2,468,000 +$ +1,724,000 +Supplemental disclosure of cash flow information: +Interest payments +$ +991,000 +$ +1,949,000 +$ +2,300,000 +Income tax payments +$ +1,000 +$ +40,000 +$ +543,000 +Supplemental disclosure of non-cash transactions: +Capitalized stock based compensation +$ +515,000 +$ +197,000 +$ +212,000 +Asset retirement obligation capitalized +$ +1,390,000 +$ +1,328,000 +$ +361,000 +Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC +$ +(855,000 +) +$ +1,313,000 +$ +3,656,000 +Foreign currency translation gain (loss) on note receivable—related party +$ +(1,085,000 +) +$ +942,000 +$ +1,843,000 +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2011, 2010 AND 2009 +(Amounts rounded to nearest thousand) +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production company with its principal properties located in the +Louisiana Gulf Coast, in West Texas in the Permian Basin and in Western Colorado in the Niobrara Formation and has investments in companies operating in Canada and Thailand. The Company recently acquired leasehold interests in the Utica Shale in +Eastern Ohio. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc. and Puma Resources, +Inc. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its +receivables are from two purchasers of the Company’s oil and gas and one operator of certain of the Company’s properties. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not +required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment +terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to +pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when +they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2011 and December 31, 2010. +Oil and Gas Properties +The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and +certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting, the Company is required to perform a ceiling test each +quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is +defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for 2011, 2010 and 2009, and prior to 2009, +unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s +F-7 +Table of Contents +Index to Financial Statements +oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not +being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas +properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. +Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting +gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and +gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $138,623,000 and $16,778,000 at December 31, 2011 and December 31, 2010, respectively. These costs are reviewed +quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment +assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. +The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, “ Asset Retirement and +Environmental Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the +obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the +original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the +well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment +is provided on a straight-line basis over estimated useful lives of the related assets, which range from 3 to 30 years. +Foreign Currency +The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity +investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. +Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table +presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive income. +December 31, 2008 +$ +(4,803,000 +) +December 31, 2009 +$ +696,000 +December 31, 2010 +$ +2,952,000 +December 31, 2011 +$ +1,087,000 +Net Income per Common Share +Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common +share +F-8 +Table of Contents +Index to Financial Statements +reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if +their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 13. +Income +Taxes +Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and +liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit +carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax +assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax +assets when it is more likely than not the deferred tax assets will not be realized. +The Company is subject to U.S. federal +income tax as well as income tax of multiple jurisdictions. The Company’s 1996 – 2010 U.S. federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2011, the +Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. +For the year ended December 31, 2011, there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements. +Revenue Recognition +Gas revenues are recorded in the month produced and +delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, +the underproduction is recorded as a receivable. There is no such liability or asset recorded at December 31, 2011 and 2010 because the Company has no imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month +produced. +Investments—Equity Method +Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in +the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. There was no impairment +of equity method investments at December 31, 2011 or 2010. +Accounting for Stock-Based Compensation +The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, +“ Compensation—Stock Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options and restricted stock, to be recognized as equity or +liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. +Accounting for Derivative +Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil prices by +utilizing energy swaps and collars, or fixed-price contracts. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be +recognized as assets or liabilities in the statement of financial position, measured at fair value. +F-9 +Table of Contents +Index to Financial Statements +The Company estimates the fair value of all derivative instruments using established index +prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values reported in the consolidated financial +statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. +Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in +accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any +change in fair value resulting from ineffectiveness is recognized immediately in earnings. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America +requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ +materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount +and timing of asset retirement obligations, the realization of deferred tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves +is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. +Reclassification +Certain reclassifications have been made to prior period financial statements to conform to current period presentation. +Recent Accounting Pronouncements +In December 2008, the Securities and Exchange Commission published a Final Rule, “ Modernization of Oil and Gas Reporting .” The new rule permits the use of new technologies to determine +proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserve volumes. The new requirements also allow companies to disclose their probable and possible reserves. In addition, the new disclosure +requirements require companies to (a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil +and gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new requirements were effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The Company +adopted the Final Rule as of December 31, 2009. The adoption of the rule resulted in a lower price used in reserve calculations and a decrease in 2009 reserves. See Item 2. Properties and Note 20 for further discussion of the impact of +implementation. +In January 2010, the FASB issued Accounting Standards Update 2010-03, “ Oil and Gas Reserve Estimation +and Disclosures ” (currently codified in FASB ASC Topic 932, “ Extractive Activities—Oil & Gas ”) (“FASB ASC 932”). The purpose of the amendments in this Update was to align the oil and gas reserve +estimation and disclosure requirements of FASB ASC 932 with the requirements in the Security and Exchange Commission’s Final Rule, “ Modernization of Oil and Gas Reporting. ” The amendments to FASB ASC 932 were effective for +annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The impact of the adoption of FASB ASC 932 is noted above. +F-10 +Table of Contents +Index to Financial Statements +In May 2011, the FASB issued Accounting Standards Update No. 2011-04, “Fair +Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides amendments to FASB ASC Topic 820, “Fair Value Measurements and Disclosure” +(“FASB ASC 820”) . The purpose of the amendments in this update is to create common fair value measurement and disclosure requirements between GAAP and IFRS. The amendments change certain fair value measurement principles and enhance +the disclosure requirements. The amendments to FASB ASC 820 are effective for interim and annual periods beginning after December 15, 2011. +In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, +“Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments +eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive income, the components of net income and the components +of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The amendments to FASB ASC 220 are effective for interim and annual periods beginning after December 15, 2011 and should be +applied retrospectively. +2. +ACQUISITIONS +Beginning in February 2011, the Company entered into agreements to acquire certain leasehold interests located in the +Utica Shale in Ohio. Certain of the agreements also grant the Company an exclusive right of first refusal for a period of six months on certain additional tracts leased by the seller. Affiliates of Gulfport have participated with the Company on a +50/50 basis in the acquisition of all leases described above. Gulfport is the operator on this acreage in the Utica Shale. As of December 31, 2011, the Company had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in +the Utica Shale for approximately $118.1 million. Gulfport funded these transactions with a portion of the proceeds from public offerings of an aggregate of 6.2 million shares of the Company’s common stock completed in March and July of +2011. The Company received aggregate net proceeds (before offering expenses) of approximately $179.0 million from these equity offerings, as discussed below in Note 8. The Company also has commitments which could increase its acreage +F-11 +Table of Contents +Index to Financial Statements +position in the Utica Shale to approximately 125,000 gross (62,500 net) leasehold acres. The Company intends to continue to pursue opportunities in this area. +On June 15, 2010, Gulfport acquired an ownership interest in certain oil and gas properties located in the Niobrara Formation of +Colorado, including three gross producing wells. The effective date of the acquisition was April 1, 2010. The total purchase price for the acquired assets, as adjusted at closing on June 15, 2010, was $7.7 million, which was recorded as +oil and natural gas properties on the accompanying December 31, 2010 consolidated balance sheet. This amount includes an adjustment for the results of operations of the assets between the April 1, 2010 effective date and the June 15, +2010 closing date. The results of operations from these properties were included in the December 31, 2010 consolidated statement of operations for the period from June 16, 2010 through December 31, 2010. No pro forma financials for +this acquisition are disclosed as the acquisition was not deemed significant to the Company. +During May 2010, Gulfport +acquired a 50% interest in 4,979 gross (2,489 net) undeveloped acres in the Permian Basin for approximately $7.6 million. +Gulfport funded the 2010 transactions predominately with proceeds from a 1.7 million common share offering completed in May of 2010. +The Company received net proceeds (before offering expenses) of approximately $21.6 million from the equity offering, as discussed below in Note 8. +3. +ACCOUNTS RECEIVABLE—RELATED PARTIES +Included in the accompanying December 31, 2011 and December 31, 2010 consolidated balance sheets are amounts +receivable from related parties of the Company. These receivables consist primarily of amounts billed by the Company to related parties as operator of the Company’s Colorado and Ohio oil and gas properties. At December 31, 2011 and +December 31, 2010, these receivables totaled $4,731,000 and $573,000, respectively. The Company recorded $1,184,000 and $593,000 for the years ended December 31, 2011 and 2009, for general and administrative functions performed under +various agreements by Gulfport’s personnel on behalf of the related parties, which are reflected as a reduction of general and administrative expenses in the consolidated statements of operations. These services are solely administrative in +nature and for entities in which the Company has no property interests. No amounts were reimbursed for general and administrative functions for the year ended December 31, 2010. The 2011 amount was billed under the acquisition team agreement +discussed below. No amounts were recorded in 2011 or 2010 under the services agreements discussed below. +The Company is a +party to an administrative service agreement with Oilfield Management Services, LLC (formerly known as Great White Energy Services LLC). Under the agreement, the Company’s services include accounting, human resources, legal and technical +support. The services provided and the fees for such services can be amended by mutual agreement of the parties. The administrative service agreement had an initial three-year term, and upon expiration of that term the agreement has continued on a +month-to-month basis. The administrative service agreement is terminable by either party at any time with at least 30 days prior written notice. +The Company is also a party to administrative service agreements with Stampede Farms LLC, Grizzly Oil Sands ULC (“Grizzly”), Everest Operations Management LLC and Tatex Thailand III, LLC. Under +the agreements, the Company’s services include professional and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements had an +initial two-year term, and has continued thereafter on a month-to-month basis. Each agreement may be cancelled by either party to such agreement with at least 60 days prior written notice and is also terminable (1) by the counterparty at any +time with at least 30 days prior written notice to the Company and +F-12 +Table of Contents +Index to Financial Statements +(2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. The Company’s administrative +agreement with Grizzly was terminated effective December 31, 2010. +The Company was reimbursed the following amounts by +the specified entities in consideration for its administrative services for the years ended December 31, 2011, 2010 and 2009. These amounts are reflected as a reduction of general and administrative expenses in the consolidated statements of +operations. Wexford Capital LP (“Wexford”) controls and/or owns a greater than 10% interest in each of these entities. An affiliate of Wexford owns approximately 13% of Gulfport’s outstanding common stock. +Agreement +Effective Date +December 31, +Entity +2011 +2010 +2009 +7/22/2006 +Oilfield Management Services, LLC +$ +— +$ +— +$ +61,000 +3/1/2008 +Stampede Farms LLC +— +— +— +3/1/2008 +Grizzly Oil Sands ULC* +— +— +20,000 +3/1/2008 +Everest Operations Management LLC +— +— +508,000 +3/1/2008 +Tatex Thailand III, LLC +— +— +— +* +Agreement was terminated effective December 31, 2010. +For the year ended December 31, 2009, the Company was also reimbursed approximately $2,000 and $1,000 by Stampede Farms LLC and Everest Operations Management LLC, respectively, for office space under +the administrative service agreements, which is included in other income (expense) in the consolidated statements of operations. For the years ended December 31, 2011 and 2010, the Company was reimbursed approximately $66,000 and $20,000, +respectively, by Orange Leaf Holdings, LLC, an affiliate of Gulfport, for office space which is included in other income (expense) in the consolidated statements of operations. +Effective July 1, 2008, the Company entered into an acquisition team agreement with Everest Operations Management LLC +(“Everest”) to identify and evaluate potential oil and gas properties in which the Company and Everest may wish to invest. Upon a successful closing of an acquisition or divestiture, the party identifying the acquisition or divestiture is +entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or divestiture consideration. The agreement may be +terminated by either party upon 30 days notice. +Effective April 1, 2010, the Company entered into an area of mutual +interest agreement with Windsor Niobrara LLC (“Windsor Niobrara”), an entity controlled by Wexford, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, exploiting and producing +oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50%/50% basis. The parties also agreed, subject to certain exceptions, to share third-party +costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, Gulfport and Windsor Niobrara also entered into a development agreement, +effective as of April 1, 2010, pursuant to which the Company and Windsor Niobrara agreed to jointly develop the contract area, and Gulfport agreed to act as the operator under the terms of a joint operating agreement. +F-13 +Table of Contents +Index to Financial Statements +4. +PROPERTY AND EQUIPMENT +The major categories of property and equipment and related accumulated depletion, depreciation, amortization and +impairment as of December 31, 2011 and 2010 are as follows: +December 31, +2011 +2010 +Oil and natural gas properties +$ +1,035,754,000 +$ +747,344,000 +Office furniture and fixtures +3,692,000 +3,277,000 +Building +4,049,000 +4,049,000 +Land +283,000 +283,000 +Total property and equipment +1,043,778,000 +754,953,000 +Accumulated depletion, depreciation, amortization and impairment +(575,142,000 +) +(512,822,000 +) +Property and equipment, net +$ +468,636,000 +$ +242,131,000 +No impairment of oil and natural gas properties was required under the ceiling test for the years ended +December 31, 2011, 2010 and 2009. +Included in oil and natural gas properties at December 31, 2011 and +December 31, 2010 is the cumulative capitalization of $23,494,000 and $18,126,000, respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost +pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All +general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $5,368,000, $4,117,000 and $3,395,000 +for the years ended December 31, 2011, 2010 and 2009, respectively. +The following is a summary of Gulfport’s oil +and gas properties not subject to amortization as of December 31, 2011: +Costs Incurred in +2011 +2010 +2009 +Prior to 2009 +Total +Acquisition costs +$ +123,721,000 +$ +8,144,000 +$ +915,000 +$ +132,000 +$ +132,912,000 +Exploration costs +689,000 +2,692,000 +155,000 +2,175,000 +5,711,000 +Development costs +— +— +— +— +— +Total oil and gas properties not subject to amortization +$ +124,410,000 +$ +10,836,000 +$ +1,070,000 +$ +2,307,000 +$ +138,623,000 +At December 31, 2011, approximately $5,711,000 of oil and gas properties related to the +Company’s Belize properties is excluded from amortization as it relates to non-producing properties. In addition, approximately $9,831,000 of non-producing leasehold costs resulting from the Company’s West Texas Permian Basin properties, +$303,000 of non-producing leasehold costs related to the Company’s Bakken properties and $4,163,000 of non-producing leasehold costs related to the Company’s Colorado properties are excluded from amortization at December 31, 2011. +Approximately $161,000 of non-producing leasehold costs related to the Company’s Southern Louisiana assets, $118,420,000 of non-producing leasehold costs related to the Company’s Ohio leasehold costs and $34,000 of non-producing leasehold +costs related to other projects are also excluded from amortization. At December 31, 2010, approximately $16,778,000 of non-producing leasehold costs was not subject to amortization. +F-14 +Table of Contents +Index to Financial Statements +The Company evaluates the costs excluded from its amortization calculation at least +annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to occur within three to five years. +A reconciliation of the asset retirement obligation for the years ended December 31, 2011 and 2010 is as follows: +December 31, +2011 +2010 +Asset retirement obligation, beginning of period +$ +10,845,000 +$ +10,153,000 +Liabilities incurred +1,390,000 +1,328,000 +Liabilities settled +(248,000 +) +(1,253,000 +) +Accretion expense +666,000 +617,000 +Asset retirement obligation as of end of period +12,653,000 +10,845,000 +Less current portion +620,000 +635,000 +Asset retirement obligation, long-term +$ +12,033,000 +$ +10,210,000 +5. +EQUITY INVESTMENTS +Investments accounted for by the equity method consist of the following as of December 31, 2011 and 2010: +December 31, +2011 +2010 +Investment in Tatex Thailand II, LLC +$ +1,030,000 +$ +1,907,000 +Investment in Tatex Thailand III, LLC +8,282,000 +4,660,000 +Investment in Grizzly Oil Sands ULC +69,008,000 +26,454,000 +Investment in Bison Drilling and Field Services LLC +6,366,000 +— +Investment in Muskie Holdings LLC +2,138,000 +— +$ +86,824,000 +$ +33,021,000 +Tatex Thailand II, LLC +During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by +Wexford. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of +concessions covering two million acres which includes the Phu Horm Field. During 2011, Gulfport received $870,000 in distributions, reducing its total net investment in Tatex to $1,030,000. The loss on equity investment related to Tatex was +immaterial for the years ended December 31, 2011, 2010 and 2009. +Tatex Thailand III, LLC +During the first quarter of 2008, the Company purchased a 5% ownership interest in Tatex Thailand III, LLC (“Tatex III”) at a +cost of $850,000. In December 2009, the Company purchased an additional approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing its total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2011, Gulfport paid $3,794,000 in cash calls, increasing its total net investment in Tatex III to $8,282,000. The Company recognized a loss +on equity investment of $172,000, $224,000 and $207,000 for the years ended December 31, 2011, 2010 and 2009, respectively, which is included in loss from equity method investments in the consolidated statements of operations. +F-15 +Table of Contents +Index to Financial Statements +Grizzly Oil Sands ULC +During the third quarter of 2006, the Company, through its wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for +approximately $8,199,000. The remaining interests in Grizzly are owned by entities controlled by Wexford. Since 2006, Grizzly has continued to acquire leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil +sands development projects. Grizzly has drilled core holes and water supply test wells in nine separate lease blocks for feasibility of oil production and conducted a seismic program. In March 2010, Grizzly filed an application in Alberta, Canada +for the development of a SAGD facility at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources Conservation (ERCB) to issue formal regulatory approval of the project. +Fabrication and onsite construction on the first phase of development at Algar Lake is currently underway. As of December 31, 2011 and 2010, Gulfport’s net investment in Grizzly was $69,008,000 and $26,454,000, respectively. Grizzly’s +functional currency is the Canadian dollar. The Company’s investment in Grizzly was decreased by $855,000 as a result of a currency translation loss for the year ended December 31, 2011 and increased by $1,313,000 as a result of a currency +translation gain for the year ended December 31, 2010. The Company recognized a loss on equity investment of $1,592,000, $740,000 and $498,000 for the years ended December 31, 2011, 2010 and 2009, respectively, which is included in loss +from equity method investments in the consolidated statements of operations. +The Company, through its wholly owned subsidiary +Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly borrowed funds from the Company. Borrowed funds initially bore interest at LIBOR plus 400 basis points and had an original maturity +date of December 31, 2012. Effective April 1, 2010, the loan agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan agreement was further +amended to change the maturity date to December 31, 2012. Interest was paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The Company loaned Grizzly approximately $3,182,000 during the year ended December 31, +2011. The Company recognized interest income of approximately $147,000, $267,000 and $547,000 for the years ended December 31, 2011, 2010 and 2009, respectively, which is included in interest income in the consolidated statements of operations. +The note balance was decreased by approximately $1,085,000 as a result of a currency translation loss for the year ended December 31, 2011 and increased by $942,000 as a result of a currency translation gain for the year ended December 31, +2010. Effective December 7, 2011, Grizzly Holdings Inc. entered into a debt settlement agreement with Grizzly under which Grizzly agreed to satisfy the entire outstanding debt by issuing additional common shares of Grizzly with no effect to the +composition of ownership structure of Grizzly. At such date, the Company’s investment in Grizzly increased by the total $22,325,000 outstanding advances and accrued interest due from Grizzly, the cumulative $75,000 currency translation loss for +the note receivable was adjusted through accumulated other comprehensive income and the note receivable was considered paid in full. +The table below summarizes financial information for Grizzly as of December 31, 2011, 2010 and 2009: +December 31, +2011 +2010 +2009 +Current assets +$ +21,247,000 +$ +3,277,000 +$ +2,064,000 +Noncurrent assets +$ +284,361,000 +$ +188,786,000 +$ +164,043,000 +Current liabilities +$ +25,984,000 +$ +3,708,000 +$ +1,585,000 +Noncurrent liabilities +$ +1,780,000 +$ +81,089,000 +$ +64,365,000 +Gross revenue +$ +— +$ +— +$ +— +Loss from continuing operations +$ +6,605,000 +$ +3,234,000 +$ +1,992,000 +Net loss +$ +6,605,000 +$ +3,234,000 +$ +1,991,000 +Bison Drilling and Field Services LLC +During the third quarter of 2011, the Company purchased a 25% ownership interest in Bison Drilling and Field Services LLC (“Bison”) at a cost of $6,009,000, subject to adjustment. The remaining +interests in Bison are +F-16 +Table of Contents +Index to Financial Statements +owned by entities controlled by Wexford. Bison owns and operates four drilling rigs. The Company recognized income on equity investment of $357,000 for the year ended December 31, 2011, +which is included in loss from equity method investments in the consolidated statements of operations. +Muskie Holdings LLC +During the fourth quarter of 2011, the Company purchased a 25% ownership interest in Muskie Holdings LLC (“Muskie”) at a cost of +$2,142,000, subject to adjustment. The remaining interests in Muskie are owned by entities controlled by Wexford. Muskie holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. The loss on +equity investment related to Muskie was immaterial for the year ended December 31, 2011. +6. +OTHER ASSETS +Other assets consist of the following as of December 31, 2011 and 2010: +December 31, +2011 +2010 +Plugging and abandonment escrow account on the WCBB properties (Note 17) +$ +3,121,000 +$ +3,129,000 +Certificates of Deposit securing letter of credit +275,000 +275,000 +Prepaid drilling costs +228,000 +7,000 +Loan commitment fees +1,495,000 +767,000 +Deposits +4,000 +4,000 +$ +5,123,000 +$ +4,182,000 +7. +LONG-TERM DEBT +A break-down of long-term debt as of December 31, 2011 and 2010 is as follows: +December 31, +2011 +2010 +Revolving credit agreement (1) +$ +— +$ +49,500,000 +Building loans (2) +2,283,000 +2,417,000 +Less: current maturities of long term debt +(141,000 +) +(2,417,000 +) +Debt reflected as long term +$ +2,142,000 +$ +49,500,000 +Maturities of long-term debt as of December 31, 2011 are as follows: +2012 +$ +141,000 +2013 +150,000 +2014 +159,000 +2015 +168,000 +2016 +1,665,000 +Thereafter +— +Total +$ +2,283,000 +(1) On September 30, 2010, the Company entered into a $100 million senior secured revolving credit +agreement with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association. The revolving credit facility initially matured on September 30, 2013 +F-17 +Table of Contents +Index to Financial Statements +and had an initial borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24, 2010. The amounts borrowed under the credit agreement were used +to repay all of the Company’s outstanding indebtedness under its prior revolving credit facility ($42.0 million) and term loan ($2.5 million), each with Bank of America, N.A., as administrative agent, and for general corporate purposes. The +credit agreement is secured by substantially all of the Company’s assets. The Company’s wholly-owned subsidiaries guaranteed the obligations of the Company under the credit agreement. +On May 3, 2011, the Company entered into a first amendment to the revolving credit agreement with The Bank of Nova Scotia, Amegy +Bank, Key Bank National Association (“Key Bank”) and Société Générale. Pursuant to the terms of the first amendment, Key Bank and Société Générale were added as additional lenders, +the maximum amount of the facility was increased to $350.0 million, the borrowing base was increased to $90.0 million, certain fees and rates payable by the Company under the credit agreement were decreased, and the maturity date was extended until +May 3, 2015. On October 31, 2011, the Company entered into additional amendments to its revolving credit facility pursuant to which, among other things, the borrowing base under this facility was increased to $125.0 million. As of +December 31, 2011, the Company had no balance outstanding under the credit agreement. +Advances under the credit +agreement, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.50%, plus (2) the highest of: (a) the +federal funds rate plus 0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The +interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 2.00% to 3.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate +is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major +New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At December 14, 2011 (the latest date during the year ended December 31, 2011 on which the Company +had borrowings outstanding), amounts borrowed under the credit agreement bore interest at the Eurodollar rate (2.26%). +The +credit agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make +investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain +exceptions as specified in the credit agreement. The credit agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income, excluding +any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest +expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or +goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually +reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offering, +and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than +3.00 to 1.00. The Company was in compliance with all covenants at December 31, 2011. +F-18 +Table of Contents +Index to Financial Statements +In conjunction with the repayment of the Bank of America credit facilities on +September 30, 2010, the Company expensed approximately $225,000 in unamortized loan fees associated with the Bank of America revolving credit facility, which is included in interest expense in the accompanying consolidated statements of +operations. +(2) In March 2011, the Company entered into a new building loan agreement for the office building it occupies in +Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement extends the maturity date of the building loan to February 2016 and reduces the interest rate +from 6.5% per annum to 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. +8. +COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is administered by the Compensation Committee (the +“Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or +exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are defined as all directors of the Company, all officers of the Company and all key employees of the Company with a +customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted under the Plan, as adjusted for changes in capitalization which have taken place since the Plan’s adoption, +was 883,000. The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, 2011. No additional securities will be issued under the Plan other than upon exercise of +options that are outstanding. +The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 +Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible participants options shall be granted, the number of shares covered by such options, +the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) Incentive Stock Options, +(b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights and (ii) increase the maximum aggregate amount of common stock +that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 2011, the Company has +granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. +Sale of Common Stock +On May 19, 2010, the Company sold 1,481,481 shares of its common stock in an underwritten public offering at a public +offering price of $13.50 per share less the underwriting discount. On May 25, 2010, the Company sold an additional 187,022 shares of common stock at the public offering price less the underwriting discount in connection with the +underwriters’ partial exercise of the over-allotment option granted to them by the +F-19 +Table of Contents +Index to Financial Statements +Company. The Company received the aggregate net proceeds of approximately $21.6 million from the sale of these shares after deducting the underwriting discount and before offering expenses. A +portion of the net proceeds from the offering was used to fund the Company’s Niobrara Formation and Permian Basin acquisitions as discussed in Note 2. The remaining net proceeds from this offering were used for general corporate purposes, +including expenditures associated with the Company’s 2010 drilling programs. +On March 30, 2011, the Company +completed the sale of an aggregate of 2,760,000 shares of its common stock in an underwritten public offering at a public offering price of $32.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately +$84.3 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as +discussed in Note 2 and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. +On July 15, 2011, the Company completed the sale of an aggregate of 3,450,000 shares of its common stock in an underwritten public +offering at a public offering price of $28.75 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $94.7 million from the sale of these shares after deducting the underwriting discount and before +offering expenses. The Company used a portion of the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending the application of the +Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. +On December 5, 2011, the Company completed the sale of an aggregate of 4,600,000 shares of its common stock in an underwritten public offering at a public offering price of $29.00 per share less the +underwriting discount. The Company received aggregate net proceeds of approximately $128.0 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company will continue to use the proceeds to +fund capital expenditures associated with drilling, development and infrastructure, principally in the Utica Shale in Ohio and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company +repaid all of its outstanding indebtedness under its revolving credit agreement. +Private Placement Offering +In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative +Preferred Stock, Series A, of the Company (the “Preferred”) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per share, of the Company (the “Warrants”). Holders of the Preferred were entitled +to receive dividends at the rate of 12% of the liquidation preference per annum payable quarterly in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares +of Preferred at the rate of 15% of the liquidation preference per annum. All Preferred shares were redeemed in 2005. +F-20 +Table of Contents +Index to Financial Statements +The 2,322,962 Warrants issued have a term of ten years and a current exercise price of +$1.19 per share of common stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the Warrants. The Company +considered the valuation of the Warrants and did not consider them materially significant. The Company had 8,875 Warrants outstanding at December 31, 2011 which can be converted into 29,832 shares of common stock. +9. +STOCK-BASED COMPENSATION +During the years ended December 31, 2011, 2010 and 2009, the Company’s stock-based compensation cost was +$1,287,000, $492,000 and $529,000, respectively, of which the Company capitalized $515,000, $197,000 and $212,000, respectively, relating to its exploration and development efforts. +The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. Expected +volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon historical experience of the Company, the expected term of options granted is equal to +the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have an exercise +price not less than the fair value of the Company’s common stock on the date of the grant. +No stock options were issued +during the years ended December 31, 2011, 2010 and 2009. +The Company has not declared dividends and does not intend to +do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance +that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. +A summary +of the status of stock options and related activity for the years ended December 31, 2011, 2010 and 2009 are presented below: +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value +Options outstanding at December 31, 2008 +522,380 +$ +7.01 +6.24 +$ +(1,599,000 +) +Granted +— +— +Exercised +(13,750 +) +2.20 +71,000 +Forfeited/expired +— +— +Options outstanding at December 31, 2009 +508,630 +7.14 +5.38 +$ +2,192,000 +Granted +— +— +Exercised +(48,889 +) +6.46 +545,000 +Forfeited/expired +(1,500 +) +2.00 +Options outstanding at December 31, 2010 +458,241 +7.23 +4.48 +$ +6,621,000 +Granted +— +— +Exercised +(102,000 +) +9.74 +2,308,000 +Forfeited/expired +— +— +Options outstanding at December 31, 2011 +356,241 +$ +6.51 +3.41 +$ +8,172,000 +Options exercisable at December 31, 2011 +356,241 +$ +6.51 +3.41 +$ +8,172,000 +F-21 +Table of Contents +Index to Financial Statements +Unrecognized compensation expense as of December 31, 2011 related to outstanding stock +options and restricted shares was $4,819,000. The expense is expected to be recognized over a weighted average period of 2.10 years. +The following table summarizes information about the stock options outstanding at December 31, 2011: +Exercise +Price +Number +Outstanding +Weighted Average +Remaining +Life +(in years) +Number +Exercisable +$3.36 +206,241 +3.06 +206,241 +$9.07 +25,000 +3.69 +25,000 +$11.20 +125,000 +3.92 +125,000 +356,241 +356,241 +The following table summarizes restricted stock activity for the twelve months ended December 31, +2011, 2010 and 2009: +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2008 +93,456 +$ +7.04 +Granted +13,332 +8.08 +Vested +(43,458 +) +8.16 +Forfeited +(3,086 +) +15.77 +Unvested shares as of December 31, 2009 +60,244 +$ +6.01 +Granted +111,667 +$ +12.94 +Vested +(58,525 +) +8.17 +Forfeited +— +— +Unvested shares as of December 31, 2010 +113,386 +$ +11.72 +Granted +153,332 +$ +31.15 +Vested +(63,370 +) +12.87 +Forfeited +— +— +Unvested shares as of December 31, 2011 +203,348 +$ +26.02 +10. +INSURANCE PROCEEDS +In March 2009, the Company received insurance proceeds of approximately $1,050,000 related to damages incurred in its +WCBB field as a result of Hurricane Ike in 2008. The costs associated with repairing the field were expensed to lease operating expenses as incurred in 2008 and 2009. The Company recognized the insurance proceeds in other (income) expense in the +accompanying consolidated statements of operations. In September and October 2009, the Company received additional insurance proceeds of approximately $994,000 related to damages incurred in the WCBB field as a result of Hurricane Ike and related +debris removal. As the costs related to these repairs and debris removal were incurred in 2009 and expensed to lease operating expense, the Company recognized the insurance proceeds in lease operating expenses in the accompanying consolidated +statements of operations. +11. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, +accounts payable and accrued liabilities, and current and long-term debt are carried at cost, which approximates market value. +F-22 +Table of Contents +Index to Financial Statements +The fair value of the derivative instruments is computed based on the difference between +the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and are +subject to significant volatility. +12. +INCOME TAXES +The income tax provision consists of the following: +2011 +2010 +2009 +Current: +State +$ +— +$ +40,000 +$ +28,000 +Federal +282,000 +95,000 +32,000 +Deferred: +State +— +— +— +Federal +(372,000 +) +(95,000 +) +(32,000 +) +Total income tax expense (benefit) provision +$ +(90,000 +) +$ +40,000 +$ +28,000 +A reconciliation of the statutory federal income tax amount to the recorded expense follows: +2011 +2010 +2009 +Income before federal income taxes +$ +108,332,000 +$ +47,403,000 +$ +23,655,000 +Expected income tax at statutory rate +37,916,000 +16,591,000 +8,279,000 +State income taxes +4,227,000 +2,378,000 +1,370,000 +Other differences +(146,000 +) +(111,000 +) +(891,000 +) +Changes in valuation allowance +(42,087,000 +) +(18,818,000 +) +(8,730,000 +) +Income tax expense (benefit) recorded +$ +(90,000 +) +$ +40,000 +$ +28,000 +The tax effects of temporary differences and net operating loss carryforwards, which give rise to +deferred tax assets and liabilities at December 31, 2011, 2010 and 2009 are estimated as follows: +2011 +2010 +2009 +Deferred tax assets: +Net operating loss carryforward +$ +40,880,000 +$ +20,967,000 +$ +22,268,000 +Oil and gas property basis difference +— +32,054,000 +49,638,000 +FASB ASC 718 compensation expense +520,000 +347,000 +341,000 +Investment in pass through entities +78,000 +722,000 +528,000 +AMT credit +1,000,000 +693,000 +598,000 +Non-oil and gas property basis difference +103,000 +279,000 +316,000 +Charitable contributions carryover +3,000 +— +— +State net operating loss carryover +6,410,000 +— +— +Total deferred tax assets +48,994,000 +55,062,000 +73,689,000 +Deferred tax liabilities: +Oil and gas property basis difference +35,637,000 +— +— +Investment in pass through entities +— +— +— +Unrealized gain on hedging activities +10,000 +— +— +Total deferred tax liabilities +35,647,000 +— +— +Total deferred tax asset +13,347,000 +55,062,000 +73,689,000 +Valuation allowance +(12,347,000 +) +(54,434,000 +) +(73,156,000 +) +Net deferred tax asset +$ +1,000,000 +$ +628,000 +$ +533,000 +F-23 +Table of Contents +Index to Financial Statements +The Company has an available tax net operating loss carryforward estimated at approximately +$116,800,000 as of December 31, 2011. This carryforward will begin to expire in the year 2013. A valuation allowance has been provided at December 31, 2011, 2010 and 2009 because it is management’s belief, based upon the +Company’s past history of no taxable income and future projections of no taxable income during the carryforward period, it is more likely than not the net deferred tax assets will not be realized. +The Company had income tax expense of $40,000 related to state income tax for the year ended December 31, 2010. +13. +EARNINGS PER SHARE +A reconciliation of the components of basic and diluted net income per common share is presented in the table below: +2011 +2010 +2009 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per +Share +Basic: +Net income +$ +108,422,000 +48,754,840 +$ +2.22 +$ +47,363,000 +43,863,190 +$ +1.08 +$ +23,627,000 +42,667,581 +$ +0.55 +Effect of dilutive securities: +Stock options and awards +— +452,123 +— +392,902 +— +350,067 +Diluted: +Net income +$ +108,422,000 +49,206,963 +$ +2.20 +$ +47,363,000 +44,256,092 +$ +1.07 +$ +23,627,000 +43,017,648 +$ +0.55 +For the year ended December 31, 2009, options to purchase 64,889 shares at $9.07 per share and +200,000 shares at $11.20 per share were excluded from the calculation of dilutive earnings per share because they were anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive for the years ended +December 31, 2011 and 2010. +14. +HEDGING ACTIVITIES +Oil Price Hedging Activities +The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by entering into fixed price swaps and forward sales +contracts. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in +the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. +The Company accounts for its oil derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related pronouncements. All derivative contracts are marked to market each +quarter end and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. +During the +fourth quarter of 2010, the Company entered into fixed price swap contracts for 2011 with the purchaser of the Company’s WCBB oil and with a financial institution. The Company’s 2011 fixed price swap contracts were tied to the commodity +prices on the New York Mercantile Exchange (“NYMEX”). The Company received the fixed price amount stated in the contract and paid to its counterparty the current market price for oil as listed on the NYMEX West Texas Index +(“WTI”). During the third quarter of 2011, the Company entered into fixed price swap contracts for 2012 with the purchaser of the Company’s WCBB oil. The Company’s 2012 fixed price swap contracts are tied to the commodity prices +on the International Petroleum Exchange (“IPE”). +F-24 +Table of Contents +Index to Financial Statements +For the Company’s 2012 fixed price swap contracts, the Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price for oil as +listed on the IPE for Brent Crude. At December 31, 2011, the Company had the following fixed price swaps in place: +Daily Volume +(Bbls/day) +Weighted +Average Price +January – December 2012 +2,000 +$ +108.00 +At December 31, 2011 the fair value of derivative assets related to the fixed price swaps was as +follows: +Short-term derivative instruments – asset +$ +1,601,000 +At December 31, 2010, the fair value of derivative liabilities related to the fixed price swaps was +as follows: +Short-term derivative instruments – liabilities +$ +4,720,000 +All fixed price swaps and forward sales contracts have been executed in connection with the +Company’s oil price hedging program. For fixed price swaps qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract price is included in oil sales in the period for which the underlying production was hedged. +For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are +recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Amounts reclassified out of accumulated other comprehensive income into earnings as a component of oil and condensate sales for the years ended +December 31, 2011 and 2010 are presented below. +Year ended December 31, +2011 +2010 +(Reduction) addition to oil and condensate sales +$ +(4,720,000 +) +$ +(18,736,000 +) +The Company expects to reclassify $1,576,000 out of accumulated other comprehensive income into earnings +as a component of oil and condensate sales during the year ended December 31, 2012 related to fixed price swaps. +The +following table presents the balances of the Company’s cumulative hedging activities included in other comprehensive income. +December 31, 2008 +$ +— +December 31, 2009 +$ +(18,736,000 +) +December 31, 2010 +$ +(4,720,000 +) +December 31, 2011 +$ +1,576,000 +Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between +the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company recognized a gain of $25,000 related to hedge ineffectiveness for the year ended +December 31, 2011, which is included in oil and condensate sales in the consolidated statements of operations. The Company did not recognize into earnings any amount related to hedge ineffectiveness for the years ended December 31, 2010 +and 2009. +In 2009, the Company was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day +at a weighted average daily price of $55.17 per barrel, before transportation costs and differentials, for the period April 2009 to August 2009. The Company also was party to forward sales contracts +F-25 +Table of Contents +Index to Financial Statements +for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period September 2009 to +December 2009. For the period January 2010 through February 2010, the Company was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation +costs and differentials. For the period March 2010 through December 2010, the Company was party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before +transportation costs and differentials. +In the first quarter of 2009, the Company terminated forward sales contracts for +3,000 barrels per day of March 2009 production for approximately $1.5 million and terminated forward sales contracts for 3,000 barrels per day in the second quarter of 2009 for $476,000. For the year ended December 31, 2009, approximately $2.0 +million related to such terminations is included in oil and condensate sales on the accompanying consolidated statements of operations. +The Company delivered approximately 31% of its 2011 production under fixed price swaps. +15. +FAIR VALUE MEASUREMENTS +The Company adopted FASB ASC 820 for all financial assets and liabilities measured at fair value on a recurring basis. +The Company adopted FASB ASC 820 effective January 1, 2009 for all non-financial assets and liabilities. FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an +orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market +inputs. The statement requires fair value measurements be classified and disclosed in one of the following categories: +Level 1 +– Quoted prices in active markets for identical assets and liabilities. +Level 2 – Quoted prices in active markets +for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. +Level 3 – Significant inputs to the valuation model are unobservable. +Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. +The following tables summarize the Company’s financial and nonfinancial liabilities by FASB ASC 820 valuation level as +of December 31, 2011 and 2010: +As of December 31, 2011 +Level 1 +Level 2 +Level 3 +Assets: +Fixed price swaps +$ +— +$ +1,601,000 +$ +— +Liabilities: +Fixed price swaps +$ +— +$ +— +$ +— +As of December 31, 2010 +Level 1 +Level 2 +Level 3 +Assets: +Fixed price swaps +$ +— +$ +— +$ +— +Liabilities: +Fixed price swaps +$ +— +$ +4,720,000 +$ +— +The estimated fair value of the Company’s fixed price swap contracts was based upon forward +commodity prices based on quoted market prices, adjusted for differentials. +F-26 +Table of Contents +Index to Financial Statements +The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC +Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal +estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to +use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the twelve months ended December 31, 2011 were approximately $1,390,000. +16. +RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business activities with certain entities affiliated with its +largest stockholder. +Windsor Permian, LLC (“Windsor”), an entity controlled by Wexford, operates the Permian Basin +wells in West Texas. At December 31, 2011 and 2010, the Company owed Windsor approximately $5,593,000 and $5,871,000, respectively, related to reimbursement for services provided. Approximately $5,489,000 and $2,386,000 of services provided by +Windsor are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2011 and 2010, respectively. Approximately $50,614,000 and $21,666,000 related to services performed by Windsor are +included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2011 and 2010, respectively. +Athena Construction LLC (“Athena”), an entity controlled by Wexford, performs services for the Company at its WCBB and Hackberry fields. At December 31, 2011 and December 31, 2010, the +Company owed Athena approximately $676,000 and $791,000, respectively, related to these services. Approximately $423,000 and $438,000 of services provided by Athena are included in lease operating expenses in the consolidated statements of +operations for the years ended December 31, 2011 and 2010, respectively. Approximately $2,851,000 and $2,554,000 related to services performed by Athena are included in oil and natural gas properties on the accompanying consolidated balance +sheets at December 31, 2011 and 2010, respectively. +Great White Directional Services LLC (“Directional”) +performs services for the Company at its WCBB and Hackberry fields. At December 31, 2011 and December 31, 2010, the Company owed Directional approximately $2,449,000 and $952,000, respectively, related to these services. Approximately +$6,068,000 and $3,008,000 relating to services performed by Directional are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2011 and 2010, respectively. Directional was controlled by +Wexford until it was sold to an unrelated third party in August 2011. +Great White Pressure Control (“Pressure +Control”) performs services for the Company at its WCBB field. At December 31, 2010, the Company owed Pressure Control approximately $80,000 related to these services. Approximately $80,000 of services performed by Pressure Control are +included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2010. No services were performed by Pressure Control in 2011. Pressure Control was controlled by Wexford until it was sold to an +unrelated third party in August 2011. +Black Fin P&A, LLC (“Black Fin”), an entity controlled by Wexford, +performs services for the Company at its WCBB field. At December 31, 2011, the Company owed Black Fin $436,000 related to these services. No amounts were owed to Black Fin at December 31, 2010. Approximately $436,000 and $826,000 of +services performed by Black Fin are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2011 and 2010, respectively. +F-27 +Table of Contents +Index to Financial Statements +17. +COMMITMENTS +Plugging and Abandonment Funds +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month +through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment +obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of December 31, 2011, the plugging +and abandonment trust totaled approximately $3,121,000. At December 31, 2011, the Company has plugged 320 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its current minimum plugging obligation. +Contributions to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 15% of their total compensation through salary deferrals. Also under these plans, the Company will +make a contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals. During the years ended December 31, 2011, 2010 and 2009, Gulfport +incurred $310,000, $316,000 and $279,000, respectively, in contributions expense related to this plan. +Employment Agreement +In May 1999, Gulfport entered into an employment agreement with its Chairman of the Board. The original term of the +agreement expired on May 31, 2004, but automatically renews for successive terms of one year unless Gulfport or the Chairman elects otherwise. The employment agreement calls for an annual salary of $200,000, subject to adjustment for cost of +living increases. +The Company has entered into an oral agreement the Company’s Chief Executive Officer, with respect to +his compensation and benefits, pursuant to which he is entitled to an annual salary of $200,000 and, at the discretion of the Company’s board of directors, an annual cash incentive bonus. The compensation committee of the Board of Directors may +make upward adjustments to this salary. +18. +CONTINGENCIES +The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State +of Louisiana from the sale of oil under fixed price contracts during the years 2005 to 2007. The LDR maintains that Gulfport paid approximately $1,800,000 less in severance taxes under fixed price terms than the severance taxes Gulfport would have +had to pay had it paid severance taxes on the oil at the contracted market rates only. Gulfport has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts +with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. Gulfport has maintained its right to contest any final assessment or suit +F-28 +Table of Contents +Index to Financial Statements +for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against Gulfport seeking $2,275,729 in severance taxes, plus +interest and court costs. Gulfport filed a response denying any liability to the LDR for underpayment of severance taxes and is defending itself in the lawsuit. The LDR had taken no further action on this lawsuit since filing its petition two years +ago until recently when it propounded discovery requests to which Gulfport has responded. Gulfport recently served discovery requests on the LDR and is awaiting the LDR’s response. +In December 2010, the LDR filed two identical lawsuits against Gulfport in different venues to recover allegedly underpaid severance +taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by the +LDR in 2009, Gulfport denies all liability and will vigorously defend the lawsuit. The cases are in the early stages, and Gulfport has not yet filed a response to the recent lawsuits. Recently, the LDR filed motions to stay the lawsuits before +Gulfport filed any responsive pleadings. The LDR has advised Gulfport that it intends to pursue settlement discussions with Gulfport and other similarly situated defendants in separate proceedings. +Other Litigation +In +November 2006, Cudd Pressure Control, Inc. (“Cudd”) filed a lawsuit against Gulfport, Great White Pressure Control LLC (“Great White”) and six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit +was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White’s employment of the former Cudd +employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007. Gulfport filed a motion for +summary judgment on October 5, 2007. The court entered a final interlocutory judgment in favor of all defendants, including Gulfport, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the +Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, +and Cudd filed a motion to remand the case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition with the state court (a) alleging that Gulfport conspired with the other +defendants to misappropriate, and misappropriated Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking unspecified monetary damages. On April 13, 2010, Gulfport’s motion to be dismissed +from the proceeding for lack of personal jurisdiction was denied. This state court proceeding is in its initial stages. In 2011, the parties have continued with written discovery and production of documents. On February 15, 2011, Cudd filed a +third amended petition seeking $26.5 million (based on a report prepared by its expert) plus disgorgement of $6 million in payments by Great White to the individual defendants and punitive damages. Gulfport denies these claims with respect to +itself. Recently, the parties began the process of scheduling and taking additional depositions and it is anticipated that the case will remain in the discovery phase for at least the next several months. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for +contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al., 38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, +which did not name Gulfport as a defendant, alleges that the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. +Plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the +defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment +and response costs and stigma damages. On December 7, 2010, Gulfport was served with a copy of the plaintiffs’ +F-29 +Table of Contents +Index to Financial Statements +first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including Gulfport, bringing the total number of defendants to 21. It also +increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a +comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort +and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income; attorney fees and expenses and +damages for evaluation and remediation of any contamination that threatens groundwater. In addition to Gulfport, current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. +Inc., The Superior Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum +Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, Gulfport filed a pleading challenging the legal sufficiency of the petitions on several grounds and requesting that they +either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by Gulfport and similar pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which +expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue. In response, Gulfport and numerous defendants re-urged their pleadings challenging the legal sufficiency of the petitions. +Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the court on May 25, 2011 and were denied. The court signed the written judgment on December 9, 2011. Gulfport noticed its intent to seek +supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application. Gulfport filed its supervisory writ and the matter is currently pending before the Louisiana Third Circuit +Court of Appeal. Gulfport has served discovery requests and is currently responding to discovery requests from the plaintiffs. It is anticipated that the discovery phase of this case will become more active in the upcoming months. +Due to the current early stages of the LDR, Cudd and Reed litigation, the outcome is uncertain and management cannot determine the amount +of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations. +The Company has been named as a defendant on various other litigation matters. The ultimate resolution of these matters is not expected +to have a material adverse effect on the Company’s financial condition or results of operations for the periods presented in the consolidated financial statements. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry +principally in the state of Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their +specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long +term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit +Insurance Corporation up to $250,000. At December 31, 2011, Gulfport held cash in excess of insured limits in these banks totaling $93,397,000. +During the year ended December 31, 2011, Gulfport sold approximately 93% and 7% of its oil production to Shell Trading Company (“Shell”) and Windsor, respectively, 100% of its natural gas +liquids production to Windsor, and 50%, 27% and 22% of its natural gas production to Hilcorp Energy Company (“Hilcorp”), Chevron and Windsor, respectively. During the year ended December 31, 2010, Gulfport sold approximately 75% and +19% of its oil production to Shell and Windsor, respectively, and 50%, 32%, and 10% of its natural gas +F-30 +Table of Contents +Index to Financial Statements +production to Windsor, Chevron, and Hilcorp, respectively. During the year ended December 31, 2009, Gulfport sold approximately 92% and 7% of its oil production to Shell and Windsor, +respectively, 100% of its natural gas liquids production to Windsor, and 45%, 38%, and 16% of its natural gas production to Windsor, Chevron, and Hilcorp, respectively. +19. +LITIGATION TRUST ENTITY +Pursuant to the Company’s 1997 plan of reorganization, all of Gulfport’s possible causes of action against +third parties (with the exception of certain litigation related to recovery of marine and rig equipment assets and claims against Tri-Deck), existing as of the effective date of that plan, were transferred into a “Litigation Trust” +controlled by an independent party for the benefit of most of the Company’s existing unsecured creditors. The litigation related to recovery of marine and rig equipment and the Tri-Deck claims were subsequently transferred to the Litigation +Trust as described below. +The Litigation Trust was funded by a $3,000,000 cash payment from the Company, which was made on +the effective date of reorganization. Gulfport owns a 12% interest in the Litigation Trust with the other 88% being owned by the former general unsecured creditors of Gulfport. For financial statement reporting purposes, Gulfport has not recognized +the potential value of recoveries which may ultimately be obtained, if any, as a result of the actions of the Litigation Trust, treating the entire $3,000,000 payment as a reorganization cost at the time of Gulfport’s reorganization. +On January 20, 1998, Gulfport and the Litigation Trust entered into a Clarification Agreement whereby the rights to +pursue various claims reserved by Gulfport under the plan of reorganization were assigned to the Litigation Trust. In connection with this agreement, the Litigation Trust agreed to reimburse the Company $100,000 for legal fees Gulfport had incurred +in connection with these claims. As additional consideration for the contribution of this claim to the Litigation Trust, Gulfport is entitled to 20% to 80% of the net proceeds from these claims. +In December 2009, the Company received a final distribution from the Litigation Trust of approximately $234,000. No proceeds were +received from the Litigation Trust for the years ended December 31, 2011 or 2010. +20. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES +The following is historical revenue and cost information relating to the Company’s oil and gas operations located +entirely in the United States: +Capitalized Costs Related to Oil and Gas Producing Activities +2011 +2010 +Proven properties +$ +897,130,000 +$ +730,566,000 +Unproven properties +132,912,000 +11,756,000 +1,030,042,000 +742,322,000 +Accumulated depreciation, depletion, amortization and impairment reserve +(571,213,000 +) +(509,248,000 +) +Net capitalized costs +$ +458,829,000 +$ +233,074,000 +F-31 +Table of Contents +Index to Financial Statements +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +2011 +2010 +2009 +Acquisition +$ +119,522,000 +$ +17,627,000 +$ +1,885,000 +Development of proved undeveloped properties +123,489,000 +64,652,000 +28,652,000 +Exploratory +3,994,000 +— +502,000 +Recompletions +17,259,000 +16,917,000 +8,980,000 +Capitalized asset retirement obligation +1,390,000 +1,328,000 +361,000 +Total +$ +265,654,000 +$ +100,524,000 +$ +40,380,000 +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is +calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude +general office overhead and interest expense attributable to oil and gas production. +2011 +2010 +2009 +Revenues +$ +228,953,000 +$ +127,636,000 +$ +85,576,000 +Production costs +(47,230,000 +) +(31,580,000 +) +(26,113,000 +) +Depletion +(61,965,000 +) +(38,600,000 +) +(28,939,000 +) +119,758,000 +57,456,000 +30,524,000 +Income tax expense (benefit) +Current +282,000 +40,000 +28,000 +Deferred +(372,000 +) +— +— +(90,000 +) +40,000 +28,000 +Results of operations from producing activities +$ +119,848,000 +$ +57,416,000 +$ +30,496,000 +Depletion per barrel of oil equivalent (BOE) +$ +26.56 +$ +19.54 +$ +17.25 +F-32 +Table of Contents +Index to Financial Statements +Oil and Gas Reserves (Unaudited) +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2011, 2010 +and 2009 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within +the 12-month period ended December 31, 2011, 2010 and 2009, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas +are stated in millions of cubic feet (MMcf). The prices used for the 2011 reserve report are $96.19 per barrel and $4.12 per MMbtu, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, +respectively. The prices used at December 31, 2010 and 2009 for reserve report purposes are $76.16 per barrel and $4.38 per MMbtu and $57.90 per barrel and $3.87 per MMbtu, respectively. +Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates +are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. +2011 +2010 +2009 +Oil +Gas +Oil +Gas +Oil +Gas +Proved Reserves +Beginning of the period +19,704 +16,158 +17,488 +14,332 +21,771 +22,235 +Purchases in oil and gas reserves in place +2 +19 +3,913 +3,482 +1,728 +1,135 +Extensions and discoveries +3,940 +2,091 +5,574 +5,303 +2,614 +2,874 +Sales of oil and gas reserves in place +— +— +— +— +(736 +) +(282 +) +Revisions of prior reserve estimates +(4,714 +) +(1,662 +) +(5,426 +) +(6,171 +) +(6,294 +) +(11,139 +) +Current production +(2,187 +) +(878 +) +(1,845 +) +(788 +) +(1,595 +) +(491 +) +End of period +16,745 +15,728 +19,704 +16,158 +17,488 +14,332 +Proved developed reserves +7,485 +6,152 +7,230 +6,068 +6,165 +4,325 +Proved undeveloped reserves +9,260 +9,576 +12,474 +10,090 +11,323 +10,007 +The Company experienced downward reserve revisions in estimated proved reserves in 2011. These downward +revisions were primarily the result of the drilling of PUDs during the Company’s 2011 drilling program and ethane takeaway issues in the Permian Basin. The Company experienced downward reserve revisions in estimated proved reserves in 2010. +These downward revisions were primarily the result of the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of Oil and Gas Reporting” Final Rule. The Company experienced downward reserve revisions in +estimated proved reserves in 2009. These downward revisions were primarily the result of implementing the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of Oil and Gas Reporting” Final Rule. +Discounted Future Net Cash Flows (Unaudited) +The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2011, 2010 and 2009 using an unweighted average +first-of-the-month price for the period January through December for 2011, 2010 and 2009. +F-33 +Table of Contents +Index to Financial Statements +Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves +(Unaudited) +Year ended December 31, +2011 +2010 +2009 +Future cash flows +$ +1,594,050,000 +$ +1,479,295,000 +$ +1,005,029,000 +Future development and abandonment costs +(306,810,000 +) +(301,651,000 +) +(209,975,000 +) +Future production costs +(295,383,000 +) +(305,814,000 +) +(236,003,000 +) +Future production taxes +(124,739,000 +) +(136,323,000 +) +(97,841,000 +) +Future income taxes +(229,649,000 +) +(159,171,000 +) +(50,229,000 +) +Future net cash flows +637,469,000 +576,336,000 +410,981,000 +10% discount to reflect timing of cash flows +(260,788,000 +) +(260,849,000 +) +(170,207,000 +) +Standardized measure of discounted future net cash flows +$ +376,681,000 +$ +315,487,000 +$ +240,774,000 +In order to develop its proved undeveloped reserves according to the drilling schedule used by the +engineers in Gulfport’s reserve report, the Company will need to spend $52,855,000, $49,897,000 and $55,364,000 during years 2012, 2013 and 2014, respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2011 +2010 +2009 +Sales and transfers of oil and gas produced, net of production costs +$ +(181,723,000 +) +$ +(96,056,000 +) +$ +(59,463,000 +) +Net changes in prices, production costs, and development costs +136,071,000 +122,147,000 +183,426,000 +Acquisition of oil and gas reserves in place +72,000 +63,043,000 +20,981,000 +Extensions and discoveries +107,110,000 +88,227,000 +32,638,000 +Revisions of previous quantity estimates, less related production costs +(112,553,000 +) +(89,155,000 +) +(77,531,000 +) +Sales of reserves in place +— +— +(13,185,000 +) +Accretion of discount +31,549,000 +24,077,000 +12,624,000 +Net changes in income taxes +(36,674,000 +) +(54,879,000 +) +(22,238,000 +) +Change in production rates and other +117,342,000 +17,309,000 +37,282,000 +Total change in standardized measure of discounted future net cash flows +$ +61,194,000 +$ +74,713,000 +$ +114,534,000 +F-34 +Table of Contents +Index to Financial Statements +21. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The following table summarizes quarterly financial data for the years ended December 31, 2011 and 2010: +2011 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +46,638,000 +$ +55,589,000 +$ +58,081,000 +$ +68,946,000 +Income from operations +22,105,000 +28,156,000 +29,118,000 +31,585,000 +Income tax expense (benefit) +— +1,000 +— +(91,000 +) +Net income +21,174,000 +27,265,000 +29,009,000 +30,974,000 +Income per share: +Basic +$ +0.47 +$ +0.57 +$ +0.58 +$ +0.59 +Diluted +$ +0.47 +$ +0.57 +$ +0.57 +$ +0.59 +2010 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +27,355,000 +$ +28,875,000 +$ +33,181,000 +$ +37,533,000 +Income from operations +10,526,000 +11,004,000 +13,468,000 +14,779,000 +Income tax expense +— +40,000 +— +— +Net income +9,981,000 +10,389,000 +12,678,000 +14,315,000 +Income per share: +Basic +$ +0.23 +$ +0.24 +$ +0.28 +$ +0.32 +Diluted +$ +0.23 +$ +0.24 +$ +0.28 +$ +0.32 +22. +SUBSEQUENT EVENTS +In January 2012, Grizzly entered into an agreement to purchase approximately 46,700 acres of oil sands leases in the +Athabasca oil sands area for $225.0 million CAD. Gulfport’s share of the purchase price is approximately $56.3 million and will be due at closing of the transaction. Grizzly intends to develop the area using SAGD recovery technology. +On February 13, 2012, Gulfport entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of +$ 113.20 per barrel for the period of March 2012 through June 2013. The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price for oil as listed on the IPE for Brent Crude. +F-35 +Table of Contents +Index to Financial Statements +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and +Windsor Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a +party seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the +SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, +2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the +Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with +the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a +Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, +2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other +Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding +LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on +April 26, 2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, +2006). +10.4+ +Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.5 +of Amendment No. 1 to Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007). +E-1 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +10.5+ +Summary of Oral Employment Agreement with James D. Palm (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on +December 7, 2010). +10.6 +Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead +arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). +10.7 +Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). +10.8 +First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative +agent, letter of credit issuer and lead arranger, Amegy Bank National Association, KeyBank National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by +the Company with the SEC on May 9, 2011). +10.9 +Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. +000-19514, filed by the Company with the SEC on November 4, 2011). +10.10 +Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit +issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders party thereto (incorporated by +reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Ryder Scott Company. +23.4* +Consent of Pinnacle Energy Services, LLC. +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +E-2 +Table of Contents +Index to Financial Statements +Exhibit +Number +Description +32.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and +Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Ryder Scott Company. +101.INS** +XBRL Instance Document. +101.SCH** +XBRL Taxonomy Extension Schema Document. +101.CAL** +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF** +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB** +XBRL Taxonomy Extension Labels Linkbase Document. +101.PRE** +XBRL Taxonomy Extension Presentation Linkbase Document. +* +Filed herewith. +** +Furnished herewith, not filed. ++ +Management contract, compensatory plan or arrangement. +E-3 \ No newline at end of file diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/filing_metadata.csv b/raw/filings/0000874499/2011/0001193125-12-081951/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..97d8ce63a7a1180ecb8aa20d48db48b261b30c5b --- /dev/null +++ b/raw/filings/0000874499/2011/0001193125-12-081951/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2012-02-27,2011-12-31,2012-02-27T22:11:48.000Z,0001193125-12-081951,d268850d10k.htm,FORM 10-K,10094934,1,0,https://www.sec.gov/Archives/edgar/data/874499/000119312512081951/d268850d10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000119312512081951/,2011,2011,1 diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/item1.txt b/raw/filings/0000874499/2011/0001193125-12-081951/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..4c6e86e656baf0375a17ce47c04f8d4f973a25cf --- /dev/null +++ b/raw/filings/0000874499/2011/0001193125-12-081951/item1.txt @@ -0,0 +1,650 @@ +ITEM 1. +BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the +Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. During 2010, we acquired our initial acreage position in the Niobrara Formation of northwestern Colorado and, during 2011, we +acquired our initial acreage position in the Utica Shale in Eastern Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, and have interests in entities that operate in +Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2011, at our WCBB field, we recompleted 68 wells and drilled 21 wells for a total cost of approximately $42.4 million as of December 31, 2011. Of the 21 new wells drilled at WCBB in 2011, 19 were +completed as producing wells, one was non-productive and one was waiting on completion. In the fourth quarter of 2011, production at WCBB was 362,996 net barrels of oil equivalent, or BOE, or an average of 3,946 BOE per day, 96% of which was from +oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. During 2012, we currently +anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $36.0 million to $38.0 million. +In 2011, at our East Hackberry field, we recompleted 24 wells and drilled 22 wells for a total cost of approximately $51.9 million as of December 31, 2011. Of the 22 new wells drilled at East +Hackberry during 2011, 17 were completed as producing wells, two were non-productive and three were waiting on completion. In the fourth quarter of 2011, net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of +which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas. +During 2012, we currently anticipate drilling 10 to 12 wells and recompleting 10 wells for an aggregate estimated cost of $24.0 million to $26.0 million. +In the fourth quarter of 2011, net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our +average net daily production at West Hackberry was 37 BOE, 100% of which was from oil. +In 2011, 39 gross (17 net) wells were +drilled and eight gross (four net) wells were recompleted on our Permian Basin acreage for a total net cost of $38.4 million. As of December 31, 2011, 35 of the 39 wells had been completed and four wells were awaiting completion. In the fourth +quarter of 2011, net production from our Permian Basin acreage was 93,760 BOE, or an average of 1,019 BOE per day, of which approximately 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 +through January 31, 2012, our average daily net production from our Permian Basin acreage was 1,032 BOE, of which 72% was from oil, 16% was from natural gas liquids and 12% was from natural gas. We currently anticipate that 23 to 25 gross (11.5 +to 12.5 net) wells will be drilled and five gross (2.5 net) wells will be recompleted on this acreage in 2012 for an estimated aggregate net cost of $23.0 million to $25.0 million. In an effort to facilitate the development of our Permian Basin and +other domestic acreage, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates four drilling rigs. The remaining 75% equity interest is owned by entities controlled by Wexford Capital LP, or +Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of February 20, 2012. We have also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in +Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford. +2 +Table of Contents +Index to Financial Statements +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara +Formation in northwestern Colorado and held leases for approximately 15,000 net acres as of December 31, 2011. During the year ended December 31, 2011, we drilled three gross (1.5 net) wells on this acreage. In the fourth quarter of 2011, +net production from our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average net daily production from our Niobrara acreage was 41 BOE, 100% +of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey, have received a processed version of the seismic and are selecting future drilling locations. During 2012, we currently anticipate drilling five +to seven gross wells in the Niobrara Formation for approximately $5.0 million to $6.0 million. +As of December 31, 2011, +we held approximately 800 net acres in the Williston Basin of western North Dakota and eastern Montana with interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale of certain of our Bakken acreage and +production from such acreage, wells drilled subsequent to such sale and wells that might be drilled in the future. In the fourth quarter of 2011, our net production from this acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was +from oil, 6% was from natural gas and 3% was from natural gas liquids. From January 1, 2012 through January 31, 2012, our average daily net production from our Bakken acreage was 71 BOE, of which 92% was from oil and 8% was from natural +gas. +As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in +the Utica Shale in Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We intend to continue to pursue opportunities in this area +and have commitments with various future closing dates that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We recently spud our first well on our Utica Shale +acreage. +During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% +interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort +McMurray within a few miles of other existing oil sands projects. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine separate lease blocks and conducted a seismic program. +In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources +Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core hole drilling and seismic program, +submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD +well pairs. +We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are +owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast +Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. +We also +own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one +million acres. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in +March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the +intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet per day of +3 +Table of Contents +Index to Financial Statements +gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic feet per day. Pressure buildup information confirmed that this wellbore lacked the +permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to +produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to +drill the first, located to the south of the TEW-E well, late this year or early 2013. +As of December 31, 2011, we had +19.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $490.5 million and associated standardized measure of discounted future +net cash flows of approximately $376.7 million, excluding reserves attributable to our interests in Grizzly, Tatex II and Tatex III. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a +non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Principal Oil +and Natural Gas Properties +The following table presents certain information as of December 31, 2011 reflecting our +net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in northwestern Colorado and in the Williston Basin in western North Dakota and +eastern Montana. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +MBOE +MBOE +MBOE +West Cote Blanche Bay Field (4) +80.108/100 +95 +95 +189 +189 +5,668 +5,668 +352 +3,617 +3,969 +E. Hackberry Field (5) +79.424/100 +30 +30 +93 +93 +3,291 +3,291 +226 +1,606 +1,832 +W. Hackberry Field +87.5/100 +2 +2 +23 +23 +592 +592 +— +76 +76 +Permian Basin +35.4/46.87 +121 +57 +— +— +8,880 +4,119 +2,008 +10,877 +12,885 +Niobrara Formation +39.7/47.9 +6 +3 +2 +1 +3,954 +1,977 +26 +500 +526 +Williston Basin (6) +2.8/3.3 +6 +.2 +— +— +1,708 +132 +7 +67 +74 +Overrides/Royalty Non-operated +Various +133 +.2 +— +— +— +— +3 +2 +5 +Total +393 +187.4 +307 +306 +24,093 +15,779 +2,622 +16,745 +19,367 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes six gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, +we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +4 +Table of Contents +Index to Financial Statements +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off +the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 +feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the +remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 994 wells drilled as of December 31, 2011, 900 were completed as producing wells. As a result, the +field has a historic success rate of 91% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2011, we drilled 183 new wells, 166 of which were productive, for a 91% success rate. As of December 31, +2011, estimated field cumulative gross production was 192.6 MMBOE and 236.6 billion cubic feet, or Bcf, of gas. Of the 994 wells drilled in WCBB as of December 31, 2011, 89 were producing, 189 were shut-in, six were producing intermittently and +five were being used as salt water disposal wells. The other 705 wells have been plugged and abandoned. +In 1991, Texaco +conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December +1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the +first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which +created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets +having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 994 wells that had been drilled in +the field as of December 31, 2011, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to +faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells +drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault +before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk +associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an +5 +Table of Contents +Index to Financial Statements +effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory +of prospects at WCBB as of December 31, 2011 included 24 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2015. +Facilities +We own and operate a production facility at WCBB that includes +four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2011, we recompleted 68 gross and net wells +and drilled 21 gross and net wells at WCBB. Nineteen of the new wells were completed as producers, one was non-productive and one was waiting on completion. As of February 20, 2012, we had drilled three wells, were in the process of drilling +two additional wells and recompleted six wells during 2012. Of the 21 wells drilled in 2011, 18 were considered deep wells. The 19 productive wells, with total depths ranging from 2,500 to 10,748 feet, have approximately 1,855 feet of aggregate +apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2012. +Production Status +In +the fourth quarter of 2011, our production at WCBB was 362,996 net BOE, or an average of 3,946 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net +daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. The decrease in production was due to normal production declines. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the +Gulf of Mexico. We own a 100% working interest (approximately 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 3,291 acres, including the +Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We also hold 2,868 net acres subject to a two-year exploration agreement we entered into with an +active gulf coast operator. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have licensed approximately 54 square miles of 3-D seismic data covering a portion of the +area and are reprocessing the data. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The +massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2011 was +over 1,625 MBOE and 330 Bcf of casinghead gas production. A total of 223 wells have been drilled on our portion of the field. As of December 31, 2011, 30 wells had daily production, 93 were shut-in and two had been converted to salt water +disposal wells. The remaining 98 wells had been plugged and abandoned. +6 +Table of Contents +Index to Financial Statements +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry +acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. +These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West +Hackberry fields. In addition, we own and operate two production facilities at East Hackberry that include a land based tank battery, production barge, three natural gas compressors, dehydration units and salt water disposal systems. +Recent and Future Activity +During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at this field. We believe that this 3-D seismic data enhances our +probability of drilling success, and we continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2011 at East Hackberry, we recompleted 24 gross and net wells and drilled 13 gross and net land wells and nine gross +and net wells on water. Seventeen of the 22 wells drilled during 2011 were completed as producing wells, two were non-productive and three were waiting on completion. As of February 20, 2012, we had recompleted two wells during 2012, drilled +two wells and were in the process of drilling two additional wells. We currently intend to drill 10 to 12 gross and net wells and recomplete 10 gross and net wells at East Hackberry during 2012. +Production Status +In +the fourth quarter of 2011, our net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our +average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas. The increase in production in 2012 is a result of our 2012 drilling activities. +West Hackberry Field +Location and +Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, +approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of +one of the United States Department of Energy’s Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil +Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2011 was 286 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, two are producing, +23 are shut-in and one has been converted to a saltwater disposal well. The remaining 10 wells have been plugged and abandoned. +7 +Table of Contents +Index to Financial Statements +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in +the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +Production Status +In +the fourth quarter of 2011, our net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day. From January 1, 2012 through January 31, 2012, our average net daily production at West Hackberry was 37 BOE and was 100% oil. +Facilities +We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. +Permian Basin (West Texas) +Location and Land +We +acquired approximately 4,100 net acres and 32 gross (16 net) producing wells in West Texas (near Midland) in the Permian Basin effective November 1, 2007. Subsequently, we acquired approximately 11,200 additional net acres, which brought our +total net acreage position in the Permian Basin to approximately 15,300 net acres as of December 31, 2011. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing +basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Permian LLC, or Windsor, an entity controlled by Wexford, is the operator of this field. +Area History +The +Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets +occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was +revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned +interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began +acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry +Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in +enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2011, we held interests in 121 gross (57 net) producing wells. +Geology +The +Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging +8 +Table of Contents +Index to Financial Statements +Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir +rock within the section is generally found in close proximity to the Central Basin Platform. +Wolfberry well reserves are +typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Ryder Scott Company L.P., or Ryder Scott, an independent petroleum engineering firm, has estimated that at December 31, 2011, proved reserves net to our +interest in these assets were approximately 12.9 million BOE, of which 23% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 252 gross well locations on 40-acre +units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. +Production Status +In the fourth quarter of 2011, our net production from +the Permian Basin field was 93,760 BOE, or an average of 1,019 BOE per day, of which 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 through January 31, 2012, our average daily net +production from our Permian Basin acreage was 1,032 BOE, 88% of which was from oil and natural gas liquids and 12% of which was from natural gas. +Facilities +There are typical land oil and natural gas processing +facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +In 2011, 39 gross (17 net) wells were +drilled in our Permian Basin acreage. From January 1, 2012 to February 20, 2012, two gross (one net) wells had been drilled on this acreage and were waiting on completion and at February 20, 2012 one gross (0.5 net) additional +well was being drilled. We have identified 252 gross future development drilling locations. We currently expect an estimated 23 to 25 gross (11.5 to 12.5 net) wells to be drilled on our acreage in 2012. The wells are expected to be drilled to +approximately 11,200 feet. In an effort to facilitate the drilling of these and future wells, in 2011 we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates four drilling rigs. We acquired our +interest in Bison from Windsor Permian LLC, or Windsor. Windsor is the operator of our Permian Basin properties and is controlled by Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of February 20, +2012. During 2011, we also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford. +Niobrara Formation (Northwestern Colorado) +Location and Land +Effective as of April 1, 2010, we acquired +leasehold interests in the Niobrara Formation in northwestern Colorado, and held leases for 14,993 acres as of December 31, 2011. We are the operator on the acreage. +Area History +The Niobrara Formation is a shale oil rock formation located +in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as +another +9 +Table of Contents +Index to Financial Statements +potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional +technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, +conventional production has been very localized and limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally +mature. +Geology +The Niobrara Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, +calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated +with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. +The producing intervals are geologically equivalent to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play. +Production Status +In the fourth quarter of 2011, our net production from +our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average daily net production from our Niobrara acreage was 41 BOE, 100% of which was from +oil. +Facilities +There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping +units. +Recent and Future Activity +We drilled three gross (1.5 net) wells at Niobrara during 2011. We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect, have received a processed version of the seismic and are +selecting future drilling locations. We currently intend to drill five to seven gross wells at Niobrara during 2012. +Bakken +Location and Land +The Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining +interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of +its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 +net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of +December 31, 2011, we held approximately 800 net acres, interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale, wells drilled subsequent to such sale and wells that might be drilled in the future. +10 +Table of Contents +Index to Financial Statements +Production Status +In the fourth quarter of 2011, our net production from our Bakken acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was from oil, 3% was from natural gas liquids and 6% was from natural +gas. From January 1, 2012 through January 31, 2012, our average net daily production from this acreage was 71 BOE, of which 92% was from oil and 8% was from natural gas. +Facilities +There are typical land oil and gas processing facilities in the +Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and future activities +One gross (.01 net) well was drilled on our acreage in 2011. There are no new activities currently scheduled for 2012 for our Bakken acreage. +Utica Shale (Eastern Ohio) +Location and Land +As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in +Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We intend to continue to pursue opportunities in this area and have commitments +with various future closing dates that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We recently spud our first well on our Utica Shale acreage. +Area History +Based on +the estimates published by the Ohio Department of Natural Resources, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas. During 2011, a number of oil and gas +companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio and applied for drilling permits with the Ohio Department of Natural Resources. +During 2011, most of the drilling activity in the Utica Shale occurred in Eastern Ohio, where our acreage is located. Based on the initial drilling results, the Utica Shale is prospective for oil and +natural gas liquids. Specifically, early wells drilled in the Utica Shale indicated potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than natural gas. +Geology +The +Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late +Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. +Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from +wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has +potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. +11 +Table of Contents +Index to Financial Statements +The Utica Shale is estimated to be thicker and more geographically extensive than the +Marcellus Shale and, based on early drilling results, has the potential to support commercial production. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West +Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and part of Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 +feet. Over the rock unit as a whole, there is a general thinning from east to west. +The Utica Shale is also significantly +deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio +and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. +The Utica Shale is +estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica +Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers +have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale. +Facilities +There are typical land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well +locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and future activities +We recently spud our first well on our Utica Shale acreage and expect to drill approximately 20 gross (ten net) wells +during 2012. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas +and Oklahoma as described in the following table: +Field +State +Parish/County +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Deer Island +Louisiana +Terrebonne +3.125 +% +0 +% +1 +0 +Napoleonville +Louisiana +Assumption +0 +% +2.5 +% +3 +0 +Crest +Texas +Ochiltree +2.000 +% +0 +% +1 +0 +Eagle City South +Oklahoma +Dewey +1.040 +% +0 +% +1 +0 +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex +II, at a cost of $2.4 million. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which includes the Phu Horm Field. During the year ended December 31, 2011, we received +$870,000 in distributions, reducing our total investment in Tatex II to $1.0 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were +achieved at the Phu Horm field located in +12 +Table of Contents +Index to Financial Statements +northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. For 2011, net gas production was approximately 83 MMcf per day and condensate +production was 380 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a +member of APICO) in the Phu Horm field is 0.7%. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex II’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve +information. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, +at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining +interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the year ended December 31, +2011, we paid $3.8 million in cash calls, bringing our total investment in Tatex III to $8.3 million. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second +well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout +drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet per day of gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic +feet per day. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in +place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the +application process for two more drilling locations. Tatex III currently expects to drill the first, located to the south of the TEW-E well, late this year or early 2013. +Grizzly Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are +owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands +projects. Our total net investment in Grizzly was approximately $69.0 million as of December 31, 2011. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine separate lease +blocks and conducted a seismic program. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council +authorizing the Alberta Energy Resources Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core +hole drilling and seismic program, submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction of a central processing facility +and the drilling of ten initial SAGD well pairs. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these +companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to +take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control +of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of +13 +Table of Contents +Index to Financial Statements +skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural +gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our +production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average +differential less $2.70 per barrel for transportation. During 2011, we sold 93% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 22%, 27% and 50% of our natural gas production to Windsor, +Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 50%, 32%, and 10% of our natural gas production to Windsor, Chevron +and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor, Chevron and +Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price at which the oil and natural gas we produce may be sold is +uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is +impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, we were party to +forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period +March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November +2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps +for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per +barrel. For the period from January 2013 through June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45% of our 2010 +production. Under the 2011 contracts, we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. Such arrangements may expose us to risk of +financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These forward sales contacts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant +to FASB ASC 815, “ Derivatives and Hedging, “ and related pronouncements. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation +affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our +cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and +natural gas properties located along the Louisiana Gulf Coast, West Texas and the Niobrara Formation in northwestern Colorado. The states in which our fields are located in regulate the production and sale of oil and natural gas, including +requirements for obtaining drilling +14 +Table of Contents +Index to Financial Statements +permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas +resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development +and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental +Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws +and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production +activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former +operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for +pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws +and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial +position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from +compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . +The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding +the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, +more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” +that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous +wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as +“hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to +waste handling, and that we hold all necessary and up-to- date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of +managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as +amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes +15 +Table of Contents +Index to Financial Statements +of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated +facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed +“responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property +contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury +and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental +agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the +Safe Drinking Water Act or SDWA, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and +other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill +prevention, control and countermeasure, or SPCC, plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank +spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas +exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention +plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. +The OPA,is the primary federal law for oil spill liability. OPA contains numerous requirements relating to the prevention of +and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency +plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs +and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the +requirements of each of these laws. +Air Emissions . The Federal Clean Air Act, as amended, and comparable state laws +and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for +our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified +sources. In particular, on August 23, 2011, the EPA published in the Federal Register a proposed rule to establish new air emission controls for oil and natural gas production and natural gas processing operations. The new emission +standards seek to reduce volatile organic compound, or VOC, emissions, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells. The EPA received public comment and conducted public +hearing regarding the proposed rules and must take final action on them by April 3, 2012. These laws and regulations may increase the costs of compliance for some +16 +Table of Contents +Index to Financial Statements +facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the +federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our +operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Our operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide +and methane, which are emitted in the course of oil and natural gas exploration and production. +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures +and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be +required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to +which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas +properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. +Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could +cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a +material adverse affect on our financial position, results of operations and cash flows. +Currently, we have general liability +insurance coverage with an annual aggregate limit of up to $21.0 million which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore West Cote +Blanche Bay properties, we also have a $25.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to +$10.0 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage +includes deductibles of up to $1,000,000 per occurrence ($1.5 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of +insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or +unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. +We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant +event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. +At the depths and in the areas in which we operate, and in light of the vertical and directional drilling that we undertake, we typically +do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for five specific Southern Louisiana wells. In addition, it is +currently anticipated that we will carry control of well coverage for all of our Utica Shale wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the +service provider’s employees as well as contractors and subcontractors hired by the service provider. +17 +Table of Contents +Index to Financial Statements +We have prepared and have in place spill prevention control and countermeasure plans for +each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we +own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as +a result of spills, blow-outs and natural disasters. This emergency response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. +It has previously reported that it owns over 164 response vehicles, 65 response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage +barge sets, allowing for storage of up to 248 barrels of recovered oil each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for +the retainer and clean up services during 2011 were approximately $220,000. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the +future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure +at our WCBB field, we believe other companies would be available to us in the event our primary remediation company was unable to perform. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of this office space to certain of our affiliates. We +also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a +building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2011, we had 50 employees. An unrelated Louisiana well servicing company provides all necessary field +personnel needed to operate the WCBB and the Hackberry fields. In addition, in the past, certain of our employees performed management and administrative services for affiliated companies. We were reimbursed by these affiliates for the salaries and +benefits of these individuals based on the estimated time they spent working for those affiliates. For the year ended December 31, 2009, expenses reimbursed to us under these arrangements were $0.6 million, respectively, and are reflected as a +reduction in our general and administrative expenses. No amounts were reimbursed to us under these arrangements in 2011 or 2010. +Available +Information +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments +to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such +material is electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual +report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +18 +Table of Contents +Index to Financial Statements \ No newline at end of file diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/item13.txt b/raw/filings/0000874499/2011/0001193125-12-081951/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..07db716c566b6e68e4df43ea7be136022e880185 --- /dev/null +++ b/raw/filings/0000874499/2011/0001193125-12-081951/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and +Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/item9a.txt b/raw/filings/0000874499/2011/0001193125-12-081951/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..475b77ba19a9aa7d429a76a0f3d2ddf6e85a7981 --- /dev/null +++ b/raw/filings/0000874499/2011/0001193125-12-081951/item9a.txt @@ -0,0 +1,68 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief +Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the +60 +Table of Contents +Index to Financial Statements +Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are +also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required +disclosures. +As of December 31, 2011, an evaluation was performed under the supervision and with the participation of +management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities +Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2011, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial +reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management’s Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is +also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are +designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent +limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with +respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control +over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal +Control—Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2011. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year +ended December 31, 2011 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2011, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +61 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in +Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over +financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an +opinion on the Company’s internal control over financial reporting based on our audit. +We conducted our audit in accordance with the +standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in +all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control +based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial +statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, +in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in +accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance +regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject +to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria +established in Internal Control—Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of +the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, +stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 27, 2012 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 27, 2012 +62 +Table of Contents +Index to Financial Statements \ No newline at end of file diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/rp_note.txt b/raw/filings/0000874499/2011/0001193125-12-081951/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2011/0001193125-12-081951/rpt_disclosure.txt b/raw/filings/0000874499/2011/0001193125-12-081951/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..6ab76f0ae7cf13197e595127c9164944e056d8a7 --- /dev/null +++ b/raw/filings/0000874499/2011/0001193125-12-081951/rpt_disclosure.txt @@ -0,0 +1,100 @@ +Certain Relationships and Related Transactions +Review and Approval of Related Party Transactions +The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be substantively applied to each transaction +reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the Company. Further, the Company’s Code of +Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party transactions. +The Company’s policy that all of its employees and directors, as well as their family members, must avoid any activity that is or has the appearance +of conflicting with the Company’s business interest. This policy is a written policy included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform +the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the +Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give +rise to a conflict of interest. +Further, under the Audit Committee Charter, the Audit Committee is responsible for reviewing and monitoring +compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the Audit Committee, reviews and approves all +relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members, +have a direct or indirect material interest. The board of directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as +they determine in the good faith exercise of their discretion. +Administrative Services Agreements +We are a party to administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Everest Operations +Management LLC, which we refer to as Everest, and Tatex Thailand III, LLC, which we refer to as Tatex III. Under these agreements, our services include professional and technical support and the fees for such services can be amended by mutual +agreement of the parties. Each of these administrative service agreements may be cancelled (1) by us with at least 60 days prior written notice and, (2) by the counterparty at any time with at least 30 days prior written notice to us and +(3) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We did not provide services under any of these agreements in 2011 and received no +reimbursements thereunder. Each of Stampede Farms, Everest and Tatex III is controlled by Wexford Capital LP, or Wexford. +Services Provided to Us by Our Affiliates +We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge +services in our West Cote Blanche Bay, or WCBB, and Hackberry fields located along the Louisiana Gulf Coast. For the year ended December 31, 2011, we paid Athena $3,389,000 and owed an additional $676,000 for such services at that date. Athena +is controlled by Wexford. +34 +Table of Contents +Effective March 1, 2008, Everest provides tax planning, preparation of supporting tax schedules and +consultation services to us based on an agreed fee structure. The scope of such services can be modified with the mutual agreement of the parties. Everest is controlled by Wexford. We paid Everest $5,000 for these services in 2011. +Caliber Development Company, LLC, or Caliber, provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. For the year ended +December 31, 2011, we paid Caliber $20,000 and owed an additional $2,000 at that date. Caliber is an entity controlled by Wexford. +Great +White Directional Services LLC, which we refer to as Directional, performs directional drilling services for us at our WCBB and Hackberry fields. Directional was an entity controlled by Wexford until August 24, 2011 when it was sold to an +unrelated third party. Directional is no longer a related party. While still a related party, we paid Directional approximately $2,625,000 and owed an additional $1,133,000 for such services at that date. +Great White Pressure Control, which we refer as Pressure Control, performs services for us at our WCBB field. Pressure Control was an entity controlled +by Wexford until August 24, 2011 when it was sold to an unrelated third party. Pressure Control is no longer a related party. While still a related party, we paid Pressure Control approximately $80,000. No amounts were owed to Pressure Control +as of August 24, 2011. +Black Fin P&A, LLC, which we refer to as Black Fin, performs plugging and abandonment services for us at our +WCBB field. For the year ended December 31, 2011, we did not pay any amounts to Black Fin and owed $436,000 to for such services at that date. Black Fin is an entity controlled by Wexford. +Our Investments in Affiliates and Related Agreements +We have a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are owned by other entities controlled by Wexford. Tatex II holds 85,122 of the 1,000,000 +outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering two million acres which includes the Phu Horm Field. +During 2011, we received $870,000 in distributions from Tatex II. +We have a 17.9% ownership interest in Tatex III. Tatex III owns a +concession covering approximately one million acres in Thailand. Approximately 68.7% of the remaining interests in Tatex III are owned by other entities and individuals affiliated with Wexford. During the year ended December 31, 2011, we paid +$3,794,000 in cash calls to Tatex III. +We own a 24.9999% interest in Grizzly, a Canadian unlimited liability company, through our wholly +owned subsidiary Grizzly Holdings, Inc. The remaining interests in Grizzly are owned by other entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the +Alberta Province near Fort McMurray. Grizzly Holdings Inc. entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly borrowed funds from us. Borrowed funds initially bore interest at LIBOR plus 4% and had an +original maturity date of December 31, 2012. Effective April 1, 2010, the loan agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan +agreement was further amended to change the maturity date to December 31, 2012. Interest was paid on a paid-in-kind basis by increasing the outstanding balance of the loan. During the year ended December 31, 2011, we loaned Grizzly +approximately $3,182,000 and recognized interest income of approximately $147,000. Effective December 7, 2011, Grizzly Holdings Inc. entered into a debt settlement agreement with Grizzly under which Grizzly agreed to satisfy the entire +outstanding debt and accrued interest of $22,325,000 by issuing additional common shares of Grizzly with no effect to the ownership structure of Grizzly. +35 +Table of Contents +During the third quarter of 2011, we purchased a 25% ownership interest in Bison Drilling and Field Services +LLC, or Bison, at a cost of $6,009,000, subject to adjustment. In April 2012, we increased our ownership interest in Bison to 40% for an additional payment of $6,152,000. The remaining interests in Bison are owned by entities controlled by Wexford, +including Windsor Permian LLC, or Windsor. Bison owns and operates drilling rigs. +During the fourth quarter of 2011, we purchased a 25% +ownership interest in Muskie Holdings LLC, or Muskie, at a cost of $2,142,000, subject to adjustment. The remaining interests in Muskie are owned by entities controlled by Wexford, including Windsor. Muskie holds certain assets, real estate and +rights in a lease covering land in Wisconsin that is prospective for mining oil and natural gas fracture grade sand. +Area of Mutual Interest and Related Agreements +Effective as of November 1, 2007, we and Windsor entered into an area of mutual +interest agreement to jointly acquire oil and gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain +exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. During 2011, we acquired approximately 604 net acres from Windsor under the terms +of this agreement for an aggregate of $1,102,000. Windsor is controlled by Wexford. +Windsor is the operator of all of our acreage in the +Permian Basin. As operator of these properties, Windsor is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which we hold an interest. For the year ended December 31, 2011, +Windsor billed us approximately $56,103,000 and at December 31, 2011, we owed $5,593,000 for these services. +Effective April 1, +2010, we entered into an area of mutual interest agreement with Windsor Niobrara LLC, which we refer to as Windsor Niobrara, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, +exploiting and producing oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50/50 basis. The parties also agreed, subject to certain +exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. We are the operator of this acreage in the Niobrara Formation. As operator, we are +responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2011, we billed Windsor Niobrara $6,642,000 and, at December 31, 2011, Windsor Niobrara +owed us $3,557,000 for these services. Windsor Niobrara is controlled by Wexford. +In February 2011, we entered into an agreement with an +unrelated third party to acquire certain leasehold interests in acreage located in the Utica Shale in Ohio. The agreement also granted us an exclusive right of first refusal for a period of six months on certain additional tracts leased by the +seller. As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in Eastern Ohio under these and other agreements for approximately $118,421,000. As of February 20, +2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We have commitments with various future closing dates that could increase our acreage position in the Utica Shale to +an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. Entities affiliated with Wexford, primarily Windsor Ohio LLC, or Windsor Ohio, participated with us on a 50/50 basis in the acquisition of the leases described above and, at +December 31, 2011, held leasehold interests in approximately 49,000 net acres for which they paid approximately $118,413,000, excluding fees and expenses of $1,184,000 billed under the acquisition team agreement described below. We are the +operator on this acreage in the Utica Shale. +Effective July 1, 2008, we entered into an acquisition team agreement with Everest to +identify and evaluate potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an +acquisition or divestiture, the party whose acquisition team identified the acquisition or divestiture is entitled to +36 +Table of Contents +receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or +divestiture consideration. The agreement has a one-year term unless earlier terminated by either party upon 30 days notice. +From time to +time, certain of our petroleum engineers provide services relating to evaluation of potential investments to Wexford and geological evaluations, seismic review and similar services to Tatex II and Tatex III. Wexford, Tatex II and Tatex III, +respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities. We did not provide any services under these arrangements in 2011. +Our Relationships with Wexford and its Affiliates +Charles E. Davidson is the Chairman and Chief Investment Officer of Wexford and he beneficially owned approximately 16.8% of our outstanding common stock as of December 31, 2011. Wexford is the manager of +the Wexford-controlled entities described above. As manager, Wexford has the exclusive authority to, among other things, purchase, hold and dispose of the assets of each such entity. Mr. Liddell, our Chairman of the Board, is the operating member +and, in some cases, an officer, of certain of these entities. All distributions made by these entities are first paid to the Wexford members in accordance with their respective ownership interests until they have received amounts equal to their +respective capital contributions. Thereafter, distributions are to be made 90% to the Wexford members in accordance with their respective ownership interests and 10% to Mr. Liddell. Mr. Liddell is not currently entitled to, and has not received, +distributions from any of these entities. All transactions between us and these entities are reviewed and approved by our independent directors. +37 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/filing.txt b/raw/filings/0000874499/2012/0001445305-13-000396/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..cdfff3b3c1be28fff06536012226d657573501cc --- /dev/null +++ b/raw/filings/0000874499/2012/0001445305-13-000396/filing.txt @@ -0,0 +1,5135 @@ +10-K +1 +gpor-12312012x10k.htm +10-K +GPOR-12.31.2012-10K +Table of Contents +Index to Financial Statements +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +______________________________________________ +Form 10-K +(Mark One) +ý +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2012 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number: 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant as Specified in Its Charter) +______________________________________________ +Delaware +73-1521290 +(State or Other Jurisdiction of Incorporation or Organization) +(I.R.S. Employer Identification No.) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip code) +(405) 848-8807 +(Registrant’s Telephone Number, Including Area Code) +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No ý +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): +Large Accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 29, 2012 , based on the closing price of the common stock on the NASDAQ Global Select Market on June 29, 2012 , the last business day of the registrant’s most recently completed second fiscal quarter ($20.63 per share), was $1,148,840,242.35 . +As of February 20, 2013 , 77,339,886 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy Corporation’s Proxy Statement for the 2013 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. +Table of Contents +Index to Financial Statements +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +BUSINESS +2 +ITEM 1A. +RISK FACTORS +24 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +43 +ITEM 2. +PROPERTIES +43 +ITEM 3. +LEGAL PROCEEDINGS +48 +ITEM 4. +MINE SAFETY DISCLOSURES +50 +PART II +51 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +51 +ITEM 6. +SELECTED FINANCIAL DATA +51 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +53 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +66 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +67 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +67 +ITEM 9A. +CONTROLS AND PROCEDURES +67 +ITEM 9B. +OTHER INFORMATION +70 +PART III +70 +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +70 +ITEM 11. +EXECUTIVE COMPENSATION +70 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +70 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +70 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +70 +PART IV +71 +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +71 +Signatures +S -1 +Index to Consolidated Financial Statements +F -1 +Exhibit Index +E -1 +i +Table of Contents +Index to Financial Statements +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “ Risk Factors ” and “ Management's Discussion and Analysis of Financial Condition and Results of Operations ” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +Index to Financial Statements +PART I +ITEM 1. +BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in the Utica Shale in Eastern Ohio. During 2010, we acquired our initial acreage position in the Niobrara Formation of Northwestern Colorado and, during 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, a 21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO (see “- Recent Developments-Contribution ” below), and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2012, at our WCBB field, we recompleted 61 wells and drilled 31 wells for a total cost of approximately $68.2 million as of December 31, 2012. Of the 31 new wells drilled at WCBB in 2012, 27 were completed as producing wells and four were non-productive. In the fourth quarter of 2012, production at WCBB was approximately 293,906 net barrels of oil equivalent, or BOE, or an average of 3,195 BOE per day, 98% of which was from oil and 2% of which was from natural gas. During January 2013, our average net daily production at WCBB was approximately 3,054 BOE, 98% of which was from oil and 2% of which was from natural gas. During 2013, we currently anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $42.0 million to $45.0 million. +In 2012, at our East Hackberry field, we recompleted 32 wells and drilled 23 wells for a total cost of approximately $70.1 million as of December 31, 2012. Of the 23 new wells drilled at East Hackberry during 2012, 19 were completed as producing wells, three were non-productive and one was being drilled at year end. In the fourth quarter of 2012, net production at East Hackberry was approximately 212,975 BOE, or an average of 2,315 BOE per day, 98% of which was from oil and 2% of which was from natural gas. During January 2013, our average net daily production at East Hackberry was approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas. During 2013, we currently anticipate drilling ten to twelve wells and recompleting 24 wells for an aggregate estimated cost of $26.0 million to $28.0 million. +At December 31, 2012, we were drilling one well at our West Hackberry field. In the fourth quarter of 2012, net production at West Hackberry was approximately 4,711 BOE, or an average of 51 BOE per day, 96% of which was from oil and 4% of which was from natural gas. During January 2013, our average net daily production at West Hackberry was approximately 29 BOE, 100% of which was from oil. +As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, and in February 2013 we acquired an additional approximately 22,000 net acres in the Utica Shale. See "-Recent Developments - February 2013 Utica Acreage Acquisition." We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2012, had drilled 14 wells, ten of which had been completed. As of February 15, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected to be producing by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells on-line have primarily been associated with MarkWest Energy Partners, L.P.'s challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012. +We have three rigs under contract on our Utica Shale acreage. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 2013 for approximately $382.0 million to $426.0 million. +Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 BOE per day, 35% of which was from oil and natural gas liquids, or NGLs, and 65% of which was from natural gas. During January 2013, our average daily net production from the Utica Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. The Wagner 1-28H well, our longest producing well in the Utica Shale, was assigned gross proved estimated ultimate recovery reserves at December 31, 2012 of 65.8 thousand barrels of oil, or MBbls, and 10.0 billion cubic feet, or Bcf, of unshrunk natural gas by Ryder Scott Company, +2 +Table of Contents +Index to Financial Statements +L.P., or Ryder Scott. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 million BOE, or MMBOE, of proved reserves. +From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was NGL's and 12% was natural gas. For more information regarding the contribution of our Permian Basin acreage to Diamondback, see “ -Recent Developments-Contribution ” below. +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and held leases for approximately 11,788 net acres as of December 31, 2012. During the year ended December 31, 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. In the fourth quarter of 2012, net production from our Niobrara Formation acreage was approximately 2,644 BOE, or an average of 29 BOE per day, 100% of which was from oil. During January 2013, our average net daily production from our Niobrara Formation acreage was approximately 43 BOE, 100% of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey and have received a processed version of the seismic. During 2013, we currently do not anticipate drilling any wells in the Niobrara Formation. +As of December 31, 2012, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in nine wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2012, our net production from this acreage was approximately 7,355 BOE, or an average of 80 BOE per day, of which 87% was from oil, 10% was from natural gas and 3% was from NGLs. During January 2013, our average daily net production from our Bakken Formation acreage was approximately 73 BOE, of which 89% was from oil and 11% was from natural gas. +We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oils Sands Inc., an entity owned by certain investment funds managed by Wexford Capital LP, or Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of December 5, 2011, and approximately 9.5% as of March 13, 2012, which ownership was reduced to less than 1% as of September 28, 2012. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately $172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the Alberta Energy Resources Conservation Board, or ERCB, to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake by the third quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid-2014 and first oil production by mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company's bitumen starting in the third quarter of 2013. +We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, +3 +Table of Contents +Index to Financial Statements +LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. +We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately 490,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet, or MMcf, per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013. +In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing. Stingray Pressure and Stingray Cementing provide well completion services. We also acquired a 50% equity interest in Blackhawk Midstream LLC, or Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. In March 2012, we acquired a 50% equity interest in Timber Wolf Terminals LLC, or Timber Wolf, for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In the fourth quarter of 2012, we acquired a 50% equity interest in Stingray Logistics LLC, or Stingray Logistics, which will provide well services. In 2011, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in Bison for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie Holdings LLC, or Muskie, which is engaged in the mining of hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. +As of December 31, 2012, we had 13.9 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $436.8 million and associated standardized measure of discounted future net cash flows of approximately $348.6 million , excluding reserves attributable to our interests in Diamondback, Grizzly, Tatex II and Tatex III. See "Item 2. Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Recent Developments +February 2013 Utica Acreage Acquisition +On February 11, 2013, we entered into a purchase and sale agreement, or the PSA, with Windsor Ohio, LLC, or Windsor Ohio, which is an affiliate of Wexford, pursuant to which Windsor Ohio agreed to sell, assign, transfer and convey to us approximately 22,000 net acres representing 100% of its right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio for approximately $220.4 million, subject to certain adjustments. This transaction, which closed on February 15, 2013, excluded Windsor Ohio's interest in 14 existing wells and 16 proposed future wells together with certain acreage surrounding these wells. We acquired our initial acreage in the Utica Shale in February 2011 and subsequently acquired additional acreage in the area. Windsor Ohio participated with us in the acquisition of these leases. Through a prior transaction with Windsor Ohio, as discussed below under the heading " —December 2012 Utica Acreage Acquisition, " we acquired approximately 37,000 net acres, which increased our working interest in the acreage at the time to 77.7%. Through this most recent transaction, we acquired an additional approximately 16.2% interest in these leases, increasing our working interest in the acreage to 93.8%. All of the acreage included in this transaction is currently nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. +Pending the completion of title review after the closing, approximately $33.6 million of the purchase price has been placed +4 +Table of Contents +Index to Financial Statements +in an escrow account. The escrow account will terminate on May 1, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review. Pursuant to the PSA, we and Windsor Ohio have agreed to indemnify each other, our respective affiliates and their respective officers, directors, employees and agents from and against all losses that such indemnified parties incur arising from any breach of representations, warranties or covenants in the PSA and certain other matters. The transaction was approved by a special committee of our board of directors, who engaged independent counsel and financial advisors to assist with their review. +December 2012 Utica Acreage Acquisition +On December 17, 2012, we entered into a purchase and sale agreement with Windsor Ohio, pursuant to which Windsor Ohio agreed to sell, assign, transfer and convey to us approximately 30,000 net acres which, at the time, represented 50% of its right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio. On December 19, 2012, the parties amended that agreement to provide for our acquisition of approximately 7,000 additional net acres. The aggregate purchase price for these interests was approximately $372.0 million, subject to certain adjustments. As discussed above, we acquired our initial acreage in the Utica Shale in February 2011 and subsequently acquired additional acreage in the area. Windsor Ohio has participated with us in the acquisition of these leases and through this transaction, we acquired an additional approximately 27.5% interest in these leases, increasing our working interest in the acreage to 77.7%. The transaction closed on December 24, 2012. All of the acreage included in this transaction is nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the completion of title review after the closing, approximately $53.9 million of the purchase price was placed in an escrow account. The escrow account will terminate on April 30, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review. +Contribution +On May 7, 2012, we entered into a contribution agreement with Diamondback, which is an affiliate of Wexford. Under the terms of the contribution agreement, we agreed to contribute to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and gas interests in the Permian Basin. On October 11, 2012, we completed this contribution, which we refer to in this Annual Report as the Contribution. At the closing of the Contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of the Contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of December 11, 2012, Wexford beneficially owned approximately 44.4% of Diamondback's outstanding common stock. +In connection with the Contribution, we and Diamondback entered into an investor rights agreement in which we have the right, for so long as we beneficially own more than 10% of Diamondback's outstanding common stock, to designate one individual as a nominee to serve on Diamondback's board of directors. Such nominee, if elected to Diamondback's board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as we have the right to designate a nominee to Diamondback's board and there is no nominee of ours actually serving as a Diamondback director, we will have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. We are also entitled to certain information rights and Diamondback granted us certain demand and “piggyback” registration rights obligating Diamondback to register with the Securities and Exchange Commission, or the SEC, any shares of Diamondback common stock that we own. Immediately upon completion of the Contribution, we owned a 35% equity interest in Diamondback, rather than leasehold interests in our Permian Basin acreage. Upon completion of the Diamondback IPO and the exercise in full by the underwriters of their over-allotment option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. +Notes Offerings +On October 17, 2012, we issued $250.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the October Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, which indenture we refer to as the senior note indenture. The offering of the October Notes is referred to herein as the October Notes Offering. On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the December Notes, to qualified institutional +5 +Table of Contents +Index to Financial Statements +buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, which offering we refer to herein as the December Notes Offering. The December Notes were issued as additional securities under the senior note indenture. The October Notes and the December Notes are referred to collectively herein as the Notes, and we refer to the October Notes Offering and the December Notes Offering collectively as the Notes Offerings. +Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. For more information regarding the Notes, see Item 7. “ Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Senior Notes .” +Equity Offerings +On December 24, 2012, we issued and sold 11,750,000 shares of our common stock in an underwritten public offering, or the December 2012 Equity Offering (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares). The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of common stock subject to the over-allotment option at a second closing, which occurred on January 7, 2013. The net proceeds from the December 2012 Equity Offering (including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) were approximately $460.7 million. We used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, as described above under the caption “ —December 2012 Utica Acreage Acquisition .” The remaining net proceeds will be used for general corporate purposes, including the funding of a portion of our 2013 capital development plan. +On February 15, 2013, we issued and sold 8,912,500 shares of our common stock (including the 1,162,500 shares issued upon the exercise in full of an over-allotment option granted to the underwriters) in an underwritten public offering, which we refer to in this report as the February 2013 Equity Offering. The net proceeds from the February 2013 Equity Offering were approximately $325.8 million. We used a portion of these net proceeds to fund the acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio, as described above under the caption “ -February 2013 Utica Acreage Acquisition. ” The remaining net proceeds will be used for general corporate purposes, including the funding of a portion of our 2013 capital development plan. +Senior Secured Credit Facility +Effective as of October 17, 2012, in connection with the completion of the October Notes Offering and the Contribution, our borrowing base under our senior secured credit facility was set at $45.0 million until the next borrowing base redetermination. Upon completion of the December Notes Offering, our borrowing base was further reduced to $40.0 million. As of December 31, 2012, no borrowings were outstanding under our senior secured credit facility. +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2012 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Utica Shale in Eastern Ohio, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. +6 +Table of Contents +Index to Financial Statements +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +MBOE +MBOE +MBOE +West Cote Blanche Bay Field (4) +80.108/100 +109 +109 +181 +181 +5,668 +5,668 +556 +4,266 +4,822 +E. Hackberry Field (5) +80.309/100 +41 +41 +96 +96 +3,931 +3,931 +151 +1,900 +2,051 +W. Hackberry Field +83.333/100 +3 +3 +23 +23 +1,192 +1,192 +3 +95 +98 +Utica Shale (6) +40.641/50.0 +2 +1 +— +— +2,441 +1,800 +4,886 +1,702 +6,588 +Niobrara Formation +36.2/41.5 +7 +3 +2 +1 +2,807 +1,404 +16 +204 +220 +Bakken Formation (7) +2.7/2.9 +8 +0.2 +— +— +1,862 +163 +10 +82 +92 +Overrides/Royalty Non-operated +Various +208 +0.4 +2 +0.06 +— +— +6 +2 +8 +Total +378 +157.6 +304 +301.06 +17,901 +14,158 +5,628 +8,251 +13,879 +(1) +Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. +(2) +Includes seven gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 11% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +Does not give effect to our February 2013 acquisition of approximately 22,000 additional net acres. See "—Recent Developments-February 2013 Utica Acreage Acquisition." +(7) NRI/WI is from wells that have been drilled or in which we have elected to participate. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,025 wells drilled as of December 31, 2012, 927 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2012, we drilled 214 new wells, 193 of which were productive, for a 90% success rate. As of December 31, 2012, estimated field cumulative gross production was 194.0 MMBOE and 236.9 Bcf of gas. Of the 1,025 wells drilled in WCBB as of December 31, 2012, 102 were producing, 181 were shut-in, seven were producing intermittently and five were being used as salt water disposal wells. The other 730 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition +7 +Table of Contents +Index to Financial Statements +and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,025 wells that had been drilled in the field as of December 31, 2012, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2012 included 36 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2015. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2012, we recompleted 61 gross and net wells and drilled 31 gross and net wells at WCBB. Of the 31 new wells drilled at WCBB in 2012, 27 were completed as producers and four were non-productive. As of February 15, 2013, we had recompleted 12 wells during 2013. Of the 31 wells drilled in 2012, 26 were considered deep wells. The 27 productive wells, with total depths ranging from 2,500 to 10,697 feet, have approximately 1,818 feet of aggregate apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2013. +Production Status +In the fourth quarter of 2012, our production at WCBB was approximately 293,906 net BOE, or an average of 3,195 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production at WCBB was approximately 3,054 BOE, 98% of which was from oil and 2% of which was from natural gas. As there was no production from new wells brought on line in January 2013, the decrease in average net daily production was due to normal production declines. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.309% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2012, we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic data. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production +8 +Table of Contents +Index to Financial Statements +through 2012 was over 2,754 MBOE and 330 Bcf of casinghead gas production. A total of 239 wells have been drilled on our portion of the field. As of December 31, 2012, 41 wells had daily production, 96 were shut-in and two had been converted to salt water disposal wells. The remaining 100 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, four natural gas compressors, dehydration units and salt water disposal systems. +Recent and Future Activity +During 2012 at East Hackberry, we recompleted 32 gross and net wells and drilled 14 gross and net land wells and nine gross and net wells on water. Of the 23 wells drilled during 2012, 19 were completed as producing wells, three were non-productive and one was being drilled at year end. As of February15, 2013, we had recompleted two wells during 2013, drilled two wells and were in the process of drilling one additional well in our East Hackberry field. We currently intend to drill ten to twelve gross and net wells and recomplete 24 gross and net wells in our East Hackberry field during 2013. +Production Status +In the fourth quarter of 2012, our net production at East Hackberry was approximately 212,975 BOE, or an average of 2,315 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production at East Hackberry was approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas. The increase in production in 2013 is a result of our 2012 drilling activities. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 83.333% NRI) in 1,192 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2012 was 307 MBOE and 140 Bcf of natural gas. There have been 37 wells drilled to date on our portion of West Hackberry. Currently, three of such wells are producing, 23 are shut-in and one has been converted to a saltwater disposal well. The remaining ten wells have been plugged and abandoned. At December 31, 2012, we were drilling one well at our West Hackberry field. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +9 +Table of Contents +Index to Financial Statements +Production Status +In the fourth quarter of 2012, our net production at West Hackberry was approximately 4,711 BOE, or an average of 51 BOE per day. From January 1, 2013 through January 31, 2013, our average net daily production at West Hackberry was approximately 29 BOE and was 100% from oil. +Facilities +We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. +Utica Shale (Eastern Ohio) +Location and Land +As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, including the approximately 37,000 net acres acquired in December 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. See "-Recent Developments-February 2013 Utica Acreage Acquisition." +Area History +Based on the estimates published by the Ohio Department of Natural Resources, or ODNR, in 2012, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2012, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio. As of February 9, 2013, the ODNR reported that in the Utica Shale in Ohio there were 65 producing horizontal wells, 236 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 15 horizontal wells that were being drilled and an additional 272 horizontal wells that had been permitted. +During 2012, most of the drilling activity in the Utica Shale occurred in Eastern Ohio, where our acreage is located. Based on the initial drilling results, the Utica Shale is prospective for oil and NGLs. Specifically, early wells drilled in the Utica Shale indicated potential for production of significant amounts of NGLs, which generally have a higher value, on an energy-equivalent basis, than natural gas. +Geology +The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. +Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. +The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west. +The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. +10 +Table of Contents +Index to Financial Statements +The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale. +Facilities +There are typical land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well locations including storage tank batteries, oil/gas/water separation equipment, vapor recovery line heaters and compression. +Recent and Future Activities +We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2012, had drilled 14 wells, ten of which had been completed. As of February 15, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected to be producing by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells online have primarily been associated with MarkWest Energy Partners, L.P.'s challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. +We have three rigs under contract on our Utica Shale acreage. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 2013. +Production Status +Aggregate net production from the Utica Shale during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 BOE per day, 35% of which was from oil and NGLs and 65% of which was from natural gas. During January 2013, our average daily net production from the Utica Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. The Wagner 1-28H well, our longest producing well in the Utica Shale, was assigned gross proved estimated ultimate recovery reserves at December 31, 2012 of 65.8 MBbls of oil and 10.0 Bcf of unshrunk natural gas by Ryder Scott. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 MMBOE of proved reserves. +Permian Basin (West Texas) +Location and Land +In 2007, we acquired approximately 4,100 net acres in West Texas in the Permian Basin with production at the time of acquisition from 32 gross (16 net) wells, predominately in the Wolfcamp formation. Subsequently, we acquired approximately 14,100 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 18,200 net acres as of September 30, 2012. From our initial acquisition in the Permian Basin through the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 118 gross (53.7 net) wells were drilled on our leasehold acreage in this area, primarily targeting the Wolfberry formation. We were not the operator of our Permian Basin acreage but were actively involved in the planning and execution of the drilling plans governed by a joint operating agreement with a subsidiary of Diamondback, which is the operator in this field. From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was NGLs and 12% was natural gas. +The Permian Basin area covers a significant portion of Western Texas and Eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. +11 +Table of Contents +Index to Financial Statements +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum's Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum's program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. +Geology +The Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +Facilities +There are typical land oil and natural gas processing facilities in the Permian Basin. The facilities located at well locations included storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +As discussed above under the heading “- Recent Developments-Contribution ,” on October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a subsidiary of Diamondback as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Following the Contribution, we account for our interest in Diamondback as an equity investment. +Niobrara Formation (Northwestern Colorado) +Location and Land +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado, and held leases for approximately 11,788 net acres as of December 31, 2012. In 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. +Area History +The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of +12 +Table of Contents +Index to Financial Statements +producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. +Geology +The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. +Production Status +In the fourth quarter of 2012, our net production from our Niobrara Formation acreage was approximately 2,644 BOE, or an average of 29 BOE per day, 100% of which was from oil. From January 1, 2013 through January 31, 2013, our average daily net production from our Niobrara Formation acreage was approximately 43 BOE, 100% of which was from oil. +Facilities +There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We do not anticipate drilling any wells in the Niobrara Formation during 2013. +Bakken Formation +Location and Land +The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken's assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOE per day of production for approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2012, we held approximately 864 net acres, interests in nine wells and an overriding royalty interests in certain existing and future wells. +Production Status +In the fourth quarter of 2012, our net production from our Bakken Formation acreage was approximately 7,355 BOE, or an average of 80 BOE per day, of which 87% was from oil, 3% was from NGLs and 10% was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production from this acreage was approximately 73 BOE, of which 89% was from oil and 11% was from natural gas. +Facilities +There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +13 +Table of Contents +Index to Financial Statements +Recent and Future Activities +Three gross (.04 net) wells were drilled on our Bakken Formation acreage in 2012. As of February 15, 2013, two gross (.03 net) wells had been drilled on our Bakken Formation acreage in 2013. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2012: +Field +State +Parish/County +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Deer Island +Louisiana +Terrebonne +3.125 +% +— +% +1 +— +Napoleonville +Louisiana +Assumption +— +% +2.5 +% +3 +— +Crest +Texas +Ochiltree +2 +% +— +% +1 +— +Eagle City South +Oklahoma +Dewey +1.04 +% +— +% +1 +— +Fay South +Oklahoma +Blaine +0.301 +% +— +% +1 +— +Squaw Cheek +Oklahoma +Blaine +0.694 +% +— +% +1 +— +Our Equity Investments +Permian Basin . As discussed above under the heading “- Recent Developments-Contribution ,” on October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. +Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc., an entity owned by certain investment funds managed by Wexford. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca and Peace River oil sands region of Alberta, Canada. Our total net investment in Grizzly was approximately $172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the ERCB to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake during the third quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid-2014 and first oil production by mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN’s rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly’s Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company’s bitumen starting in the third quarter of 2013. +14 +Table of Contents +Index to Financial Statements +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II, at a cost of $2.4 million. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. During the year ended December 31, 2012, we received $0.8 million in distributions, reducing our total investment in Tatex II to $0.2 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet per day. For 2012, net gas production was approximately 93 MMcf per day and condensate production was 428 barrels per day. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately 490,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the year ended December 31, 2012, we paid $0.6 million in cash calls, bringing our total investment in Tatex III to $8.7 million. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 MMcf per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013. +Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure and Stingray Cementing. Stingray Pressure and Stingray Cementing will provide well completion services. We also acquired a 50% equity interest in Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. In the fourth quarter of 2012, we also acquired a 50% equity interest in Stingray Logistics, which will provide well services. In March 2012, we acquired a 50% equity interest in Timber Wolf for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Midstream for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest in Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in Bison for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the mining of hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. +15 +Table of Contents +Index to Financial Statements +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI trade month average differential less $2.00 per barrel for transportation. During the year ended December 31, 2012 , we sold approximately 92% and 8% of our oil production to Shell Trading Company, or Shell, and Diamondback O&G LLC (a wholly-owned subsidiary of Diamondback formerly known as Windsor Permian LLC), or Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G and 41% , 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G, and 22%, 27% and 50% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Diamondback O&G, respectively, and 50%, 32%, and 10% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. Shell has agreed to purchase our Utica Shale oil and we have agreements in place with various purchasers for our Utica Shale natural gas production. We may not continue to have ready access to suitable markets for our future oil and natural gas production and if a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, “ and related pronouncements. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +16 +Table of Contents +Index to Financial Statements +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, and in the Utica Shale in Eastern Ohio, the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property +17 +Table of Contents +Index to Financial Statements +contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. +The Oil Pollution Act, or OPA, is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. +Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail under the caption “ -Regulation of Hydraulic Fracturing .” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. +Climate Change . Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutants” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other +18 +Table of Contents +Index to Financial Statements +GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective in January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation's National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. +In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +19 +Table of Contents +Index to Financial Statements +Regulation of Hydraulic Fracturing +Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. +On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between later in 2013 and 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. +Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota +20 +Table of Contents +Index to Financial Statements +Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 4, 2012, the U.S. Department of Interior, or DOI, issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. +Other Regulation of the Oil and Natural Gas Industry +The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. +The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. +Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices. +Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: +• +the location of wells; +• +the method of drilling and casing wells; +• +the timing of construction or drilling activities, including seasonal wildlife closures; +• +the rates of production or “allowables”; +• +the surface use and restoration of properties upon which wells are drilled; +21 +Table of Contents +Index to Financial Statements +• +the plugging and abandoning of wells; and +• +notice to, and consultation with, surface owners and other third parties. +State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. +Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. +Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. +Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. +Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. +Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. +22 +Table of Contents +Index to Financial Statements +Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. +State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. +The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows. +Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore WCBB properties, we also have a $25.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $12.5 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $1,000,000 per occurrence ($1.5 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. +At the depths and in the areas in which we operate, and in light of the vertical and directional drilling that we undertake, we typically do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for five specific Southern Louisiana wells. In addition, it is currently anticipated that we will carry control of well coverage for all of our Utica Shale wells. We also require all of our third +23 +Table of Contents +Index to Financial Statements +party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. +We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters. This emergency response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. It has previously reported that it owns over 164 response vehicles, 65 response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage barge sets, allowing for storage of up to 248 barrels of recovered oil each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for the retainer and clean up services during 2012 and 2011 were approximately $85,000 and $220,000, respectively. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure at our WCBB field, we believe other companies would be available to us in the event our primary remediation company was unable to perform. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. Additionally, we lease approximately 6,500 square feet of office space in other buildings in Oklahoma City. We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We lease 1,400 square feet of office space in St. Clairsville, Ohio that serves as our Ohio headquarters. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2012, we had 128 employees. An unrelated Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. During 2012, certain of our employees performed management and administrative services for affiliated companies for which we were reimbursed approximately $3.2 million. +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +ITEM 1A. +RISK FACTORS +Risks Related to our Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +24 +Table of Contents +Index to Financial Statements +• +weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity and other transportation facilities; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +speculative trading in crude oil and natural gas derivative contracts; +• +political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and Russia; and +• +the overall domestic and global economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to herein as West Texas Intermediate or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $13.31 per MMBtu in July 2008. During 2012, West Texas Intermediate prices ranged from $80.48 to $108.99 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.80 to $3.80 per MMBtu. On December 31, 2012, the West Texas Intermediate posted price for crude oil was $91.82 per barrel and the Henry Hub spot market price of natural gas was $3.35 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. +Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition. +Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition. +Our success depends on finding, developing or acquiring additional reserves, which requires significant capital expenditures. +Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +25 +Table of Contents +Index to Financial Statements +• +our proved reserves; +• +the level of oil and natural gas we are able to produce from existing wells; +• +the prices at which oil and natural gas are sold; and +• +our ability to acquire, locate and produce new reserves. +We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +If we are unable to complete capital projects in a timely manner, our business, financial condition, results of operations and cash flows could be materially and adversely affected. +Delays related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays may arise as a result of unpredictable factors, many of which are beyond our control, including: +• +denial of or delay in receiving requisite regulatory approvals and/or permits; +• +unplanned increases in the cost of construction materials or labor; +• +disruptions in transportation of components or construction materials; +• +adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers; +• +shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; +• +market-related increases in a project's debt or equity financing costs; and +• +nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors. +Any one or more of these factors could have a significant impact on our ongoing capital projects. +Our Canadian oil sands projects are complex undertakings and may not be completed at our estimated cost or at all. +We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oils Sands Inc., an entity owned by certain investment funds managed by Wexford. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately $172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the ERCB to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer +26 +Table of Contents +Index to Financial Statements +road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake during the third quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid- 2014 and first oil production by mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company's bitumen starting in the third quarter of 2013. These are complex projects and additional financing may be required. There can be no assurance that such financing, if required, could be obtained on commercially reasonable terms or at all. +The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations. +The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations. +We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues. +Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists could disrupt our operations resulting in a loss of revenues . Our executives are not restricted from competing with us if they cease to be employed by us, except under certain limited circumstances prohibiting competition while making use of our trade secrets. We are party to an employment agreement with each of these executive officers. As a practical matter, however, employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees. +SEC rules that went into effect for fiscal years ending on or after December 31, 2009 could limit our ability to book additional proved undeveloped reserves in the future. +SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe. +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production. +There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information herein represents estimates prepared by (i) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields at each of December 31, 2012 and 2011 and with respect to our WCBB and Niobrara fields at December 31, 2010, (ii) Ryder Scott with respect to our Utica Shale acreage at December 31, 2012 and our Permian Basin acreage at December 31, 2011 and (iii) Pinnacle Energy Services, LLC, +27 +Table of Contents +Index to Financial Statements +or Pinnacle, with respect to our Permian Basin acreage at December 31, 2010 (which acreage has been contributed to Diamondback as described in Item 1. “ Business-Recent Developments-Contribution ”) and (iv) our personnel with respect to our overriding royalty and non-operated interests at December 31, 2012 and 2011 and with respect to our Hackberry fields, overriding royalty and non-operated interests at December 31, 2010. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. +Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 2010, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. +The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2012, 2011 and 2010 on an average price equal to the unweighted arithmetic average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 2010, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. +As of December 31, 2012, approximately 40.2% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be realized. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. +28 +Table of Contents +Index to Financial Statements +Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly's lands cannot be determined at this time. +The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced. +The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field, which is our largest producing field. In October 2006, for example, a natural gas line in this field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. In addition, we currently intend to focus a significant portion of our future exploration and development activity on our Utica Shale acreage. Historically, there has been no or only limited infrastructure in this area and the commencement of production from our initial wells on our Utica Shale acreage has been delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we will be required to shut in or curtail production from the impacted field(s). Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations. +A substantial portion of our producing properties is located in Louisiana, making us vulnerable to risks associated with operating in this region. +Our largest field by production, WCBB, is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions such as fog or rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable or that any particular types of coverage will be available. +Our identified drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified over 700 drilling locations on our Louisiana, Ohio and Western Colorado properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. +Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations. +Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and +29 +Table of Contents +Index to Financial Statements +other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including: +• +unusual or unexpected geological formations; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delivery delays of equipment and services; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. +Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits. +Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. +In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. +We may incur losses as a result of title defects in the properties in which we invest. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. +Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss. +30 +Table of Contents +Index to Financial Statements +Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns. +We acquire significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells. +Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations. +Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production. +Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas. +Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future. +We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties. +We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including: +• +the timing and amount of capital expenditures; +31 +Table of Contents +Index to Financial Statements +• +the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; +• +the operator's expertise and financial resources; +• +approval of other participants in drilling wells; +• +selection of technology; and +• +the rate of production of the reserves. +In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2012, leases representing 45%, 17%, 2%, 12% and 24%, respectively, of our total Niobrara Formation undeveloped acreage are scheduled to expire in 2013, 2014, 2015, 2016 and thereafter. None of our Utica Shale acreage leases are scheduled to expire until 2015, at which time 36% of our total Utica Shale undeveloped acreage as of December 31, 2012 will be subject to expiration, with 64% of such acreage expiring thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. +Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities. +Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. +Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive. +Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See Item 1. "Business-Regulations-Environmental Matters and Regulation" and Item 1. "Business-Regulation-Other Regulation of The Oil and Natural Gas Industry" for a description of the laws and regulations that affect us. +32 +Table of Contents +Index to Financial Statements +Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. +On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between later in 2013 and 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. +Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas +33 +Table of Contents +Index to Financial Statements +Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 4, 2012, the U.S. Department of Interior, or DOI, issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. +Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities. +We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. +Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. In this regard, in November 2012, we and other entities involved in our WCBB field operations received a government subpoena, to which we have responded, for the production of documents and other information related primarily to a discharge of produced water that allegedly was identified by the U.S. Coast Guard in March 2012. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more +34 +Table of Contents +Index to Financial Statements +stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected. +Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate. +Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves +The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. +The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission, or the CFTC, has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The CFTC's final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court's decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions. +In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. +The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows. +35 +Table of Contents +Index to Financial Statements +Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows. +The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the percentage depletion allowance for oil and gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows. +The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce. +Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective in January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation's National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. +36 +Table of Contents +Index to Financial Statements +In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations. +We face extensive competition in our industry. +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +We depend upon a limited number of customers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce. +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in +37 +Table of Contents +Index to Financial Statements +Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI differential less $2.00 per barrel for transportation. During the year ended December 31, 2012 , we sold approximately 92% and 8% of our oil production to Shell and Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G, and 41% , 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G and 22%, 27% and 50% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Diamondback O&G, respectively, and 50%, 32%, and 10% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. Shell has agreed to purchase our Utica oil, and we have agreements in place with various purchasers for our Utica natural gas production. We may not continue to have ready access to suitable markets for our future oil and natural gas production. +Our method of accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. +Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for 2012, 2011 and 2010 adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. If prices of oil, natural gas and natural gas liquids decrease, we may be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of operations. +Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. +Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. +We have entered into forward sales contracts and fixed price swaps and may in the future enter into additional contracts for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. +To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For +38 +Table of Contents +Index to Financial Statements +January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging ,” and related pronouncements. +Our hedging transactions expose us to counterparty credit risk. +Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. +A terrorist attack or armed conflict could harm our business. +Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. +Conservation measures and technological advances could reduce demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. +Loss of our information and computer systems could adversely affect our business. +We are dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business. +Risks Relating to Our Indebtedness +Our substantial level of indebtedness could adversely affect our business, financial condition, results of operations and prospects. +As of December 31, 2012, we had total indebtedness (net of associated accrued discount and premium) of approximately $299.0 million, including $296.9 million attributable to the Notes, and borrowing base availability of $40.0 million under our secured revolving credit facility, under which no borrowings are outstanding. +Our outstanding indebtedness could have important consequences to you, including the following: +39 +Table of Contents +Index to Financial Statements +• +our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including restrictive covenants, could result in a default under our secured revolving credit facility or the senior note indenture; +• +the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business; +• +our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets; +• +we must use a substantial portion of our cash flow from operations to pay interest on the Notes and our other indebtedness, which will reduce the funds available to us for operations and other purposes; +• +our high level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt; +• +our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited; +• +our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and +• +we may be vulnerable to interest rate increases, as our borrowings under our secured revolving credit facility are at variable interest rates. +Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations and prospects. +In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically, the lenders under our secured revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or litigation. +We may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination. +In connection with the Contribution and the Notes Offerings, our borrowing base under our senior secured revolving credit facility was reduced to $40.0 million. The borrowing base is expected to be redetermined by the lenders on a semiannual basis. Additionally, the required lenders will be able to request one additional borrowing base redetermination in between scheduled redeterminations, and also have the right to redetermine the borrowing base upon the amendment, modification or termination of any swap contract or forward sales contract. In addition, our borrowing base will be reduced in connection with certain asset dispositions. +We repaid all borrowings outstanding under our secured revolving credit facility (approximately $146.5 million) with a portion of the proceeds from the October Notes Offering. We currently have no borrowings outstanding under our revolving credit facility, although we intend to reborrow under this facility in the future. If the outstanding borrowings under our secured revolving credit facility were to exceed the borrowing base as a result of any such recalculation, we would be required to eliminate this excess. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results. +Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness. +Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that +40 +Table of Contents +Index to Financial Statements +may be onerous or highly dilutive. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our secured revolving credit facility and the senior note indenture restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition. +Despite our current leverage, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks that we and our subsidiaries face. +We and our subsidiaries may be able to incur substantial additional indebtedness in the future, either under our senior secured credit facility or otherwise. The terms of our secured revolving credit facility and the indenture governing the Notes restrict our ability to incur additional indebtedness, but in each case do not completely prohibit us from doing so. In addition, the indenture governing the Notes allows us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indenture governing the Notes allows us to incur certain other additional secured debt and will allow our subsidiaries that do not guarantee the Notes to incur additional debt. In addition, the indenture governing the Notes does not prevent us from incurring other liabilities that do not constitute indebtedness. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. +Restrictive covenants in our secured revolving credit facility, in the senior note indenture and in future debt instruments may restrict our ability to pursue our business strategies. +Our secured revolving credit facility and the senior note indenture limit, and the terms of any future indebtedness may limit, our ability, among other things, to: +• +incur or guarantee additional indebtedness; +• +make certain investments; +• +declare or pay dividends or make distributions on our capital stock; +• +prepay subordinated indebtedness; +• +sell assets including capital stock of restricted subsidiaries; +• +agree to payment restrictions affecting our restricted subsidiaries; +• +consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; +• +enter into transactions with our affiliates; +• +incur liens; +• +engage in business other than the oil and gas business; and +• +designate certain of our subsidiaries as unrestricted subsidiaries. +The restrictions contained in these agreements could limit our ability to plan for, or react to, market conditions, meet capital needs, make acquisitions or otherwise restrict our activities or business plans. +A breach of any of these restrictive covenants could result in default under the agreement governing our senior secured revolving credit facility. If default occurs, the lenders under our senior secured revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the senior note indenture. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our senior secured revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our senior secured revolving credit facility and the Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness. +Risks Related to Our Common Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: +41 +Table of Contents +Index to Financial Statements +• +changes in oil and natural gas prices; +• +changes in production levels; +• +changes in governmental regulations and taxes; +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +We do not currently pay dividends on our common stock and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock. +A change of control could limit our use of net operating losses. +As of December 31, 2012, we had a net operating loss, or NOL, carry forward of approximately $4.3 million for federal income tax purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +Future sales of our common stock may depress our stock price. +We have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of February 20, 2013, there were 77,339,886 shares of our common stock issued and outstanding, excluding 245,831 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan and 335,241 shares issuable upon exercise of outstanding options to purchase our common stock granted under our Amended and Restated 2005 Stock Incentive Plan. +We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects. +We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock. +In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders. +42 +Table of Contents +Index to Financial Statements +The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Additional information regarding our properties is included in Item 1. "Business" above and in Note 4 of the notes to our consolidated financial statements included in this report, which information is incorporated herein by reference. +Proved Oil and Natural Gas Reserves +SEC Rule-Making Activity +In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the following: +• +Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis. +• +Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. +• +Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history. +• +Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. +• +Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction. +We adopted the rules effective December 31, 2009, as required by the SEC. +Evaluation and Review of Reserves. +Reserve estimates at December 31, 2012 were prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields (52% of our proved reserves at December 31, 2012), by Ryder Scott with respect to our assets in the Utica Shale in Eastern Ohio (47% of our proved reserves at December 31, 2012) and by our personnel with respect to our overriding royalty and non-operated interests (less than 1% of our proved reserves at December 31, 2012). +NSAI and Ryder Scott are independent petroleum engineering firms. Copies of their summary reserve reports are included as Exhibit 99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. +We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI and Ryder Scott, our independent reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our WCBB, Hackberry and Niobrara fields and our assets in the Utica Shale. Our internal technical team members meet with NSAI and Ryder Scott periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI and Ryder Scott for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our proved reserves attributable to our other minority interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our chief reserve engineer is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 30 years of reservoir and operations experience and our geophysical staff has +43 +Table of Contents +Index to Financial Statements +over 60 years combined industry experience. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. +Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: +• +review and verification of historical production data, which data is based on actual production as reported by us; +• +preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision; +• +review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; +• +direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; and +• +verification of property ownership by our land department. +The following table sets forth our estimated proved reserves at December 31, 2012 , 2011 and 2010 : +Year Ended December 31, +2012 +2011 +2010 +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Oil +(MBbls) +Natural +Gas +(MMcf) +Proved developed +5,219 +18,482 +7,485 +6,152 +7,230 +6,068 +Proved undeveloped +3,032 +15,289 +9,260 +9,576 +12,474 +10,090 +Total (1) +8,251 +33,771 +16,745 +15,728 +19,704 +16,158 +Year Ended December 31, +2012 +2011 +2010 +Total net proved oil and natural gas reserves (MBOE) (1) +13,879 +19,367 +22,397 +PV-10 value (in millions) (2) +$ +436.8 +$ +490.5 +$ +392.6 +Standardized measure (in millions) (3) +$ +348.6 +$ +376.7 +$ +315.5 +_____________________ +(1) +Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 2010, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2012, 2011 and 2010. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. +(2) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports for the years ended December 31, 2012, 2011 and 2010 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $ 91.32 per barrel and $ 2.76 per MMBtu for 2012, $ 96.19 per barrel and $ 4.12 per MMBtu for 2011 and $ 76.16 per barrel and $ 4.38 per MMBtu for 2010, and in each case adjusted by lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure-standardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value: +44 +Table of Contents +Index to Financial Statements +December 31, +2012 +2011 +2010 +Standardized measure of discounted future net cash flows +$ +348,641,000 +$ +376,681,000 +$ +315,487,000 +Add: Present value of future income tax discounted at 10% +88,206,000 +113,791,000 +77,117,000 +PV-10 value +$ +436,847,000 +$ +490,472,000 +$ +392,604,000 +(3) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. +The above table does not include proved reserves net to our interest in Diamondback, Tatex II, Tatex III or Grizzly. For further discussion of our interest in Tatex II, Tatex III and Grizzly, see Item 1. “ Business-Our Equity Investments .” +The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “ Risk Factors ” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. +Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves, or PUDs, at December 31, 2012, 2011 and 2010 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 18 to our consolidated financial statements included in this report. Also contained in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves. Additional information regarding our proved reserves can be found in Item 7. “ Management's Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations ” and “- Critical Accounting Policies and Estimates ” included in this report. +Proved Undeveloped Reserves (PUDs) +As of December 31, 2012 , our proved undeveloped reserves totaled 3,032 MBOE of oil and 15,289 MMcf of natural gas, for a total of 5,580 MBOE. Approximately 61% of our PUDs at year-end 2012 were located in our Utica field, 21% were located in WCBB, 17% were located in our East Hackberry field and 1% of our PUDs were located in our Niobrara field. PUDs will be converted from undeveloped to developed as the applicable wells begin production. Changes in PUDs that occurred during 2012 were primarily due to: +• +The loss of approximately 9,574 MBOE attributable to the contribution of our Permian Basin acreage to Diamondback; +• +Additions of 3,376 MBOE attributable to 2012 acquisitions and extensions in our Utica field and additions of 1,275 MBOE attributable to 2012 extensions in our Louisiana fields; +• +Conversion of approximately 73 MBOE attributable to PUDs into proved developed reserves; +• +Downward revisions of approximately 31 MBOE in PUDs due to changes in commodity prices; +• +Downward revisions to estimates of approximately 215 MBOE; and +• +Exclusion of 34 MBOE attributable to one PUD location that was not scheduled to be drilled within the next five years. +Costs incurred relating to the development of PUDs were approximately $18.0 million in 2012. Estimated future development costs relating to the development of PUDs are projected to be approximately $82.8 million in 2013, $16.4 million in 2014, $4.3 million in 2015 and $0.4 million in 2016. +45 +Table of Contents +Index to Financial Statements +All PUD drilling locations are scheduled to be drilled prior to the end of 2016. +As of December 31, 2012, 40% of our total proved reserves were classified as proved developed non-producing. +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2012 +2011 +2010 +Production Volumes: +Oil (MBbls) +2,323 +2,128 +1,777 +Gas (MMcf) +1,108 +878 +788 +Natural gas liquids (MGal) +2,714 +2,468 +2,821 +Oil equivalents (MBOE) +2,573 +2,333 +1,976 +Average Prices: +Oil (per Bbl) +$ +104.46 +(1) +$ +104.33 +(1) +$ +68.29 +(1) +Gas (per Mcf) +$ +2.91 +$ +4.37 +$ +4.40 +Natural gas liquids (per Gal) +$ +0.98 +$ +1.25 +$ +1.00 +Oil equivalents (per BOE) +$ +96.63 +$ +98.13 +$ +64.61 +Production Costs: +Average production costs (per BOE) +$ +9.45 +$ +8.96 +$ +8.92 +Average production taxes (per BOE) +$ +11.43 +$ +11.29 +$ +7.07 +Total production costs and production taxes (per BOE) +$ +20.88 +$ +20.25 +$ +15.99 +(1) +Includes various derivative contracts at a weighted average price of: +January – December 2012 +$ +108.31 +January – December 2011 +$ +86.96 +January – December 2010 +$ +57.55 +Excluding the effect of fixed price swaps, the average oil price for 2012 would have been $ 106.11 per barrel of oil and $ 98.12 per BOE. The total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the effect of fixed price swap contracts, the average oil price for 2011 would have been $ 107.13 per barrel of oil and $ 100.68 per BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the effect of forward sales contracts, the average oil price for 2010 would have been $ 78.12 per barrel of oil and $ 73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. +The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2012 : +46 +Table of Contents +Index to Financial Statements +Year Ended December 31, +2012 +2011 +2010 +WCBB +Net Production +Oil (MBbls) +1,126 +1,258 +1,176 +Gas (MMcf) +260 +237 +410 +NGL (Mgal) +— +— +— +Total (MBOE) +1,169 +1,298 +1,244 +Average Sales Price: +Oil (per Bbl) +$ +105.19 +$ +104.49 +$ +62.57 +Gas (per Mcf) +$ +2.89 +$ +4.16 +$ +4.44 +NGL (per Gal) +$ +— +$ +— +$ +— +Average Production Cost (per BOE) +$ +9.66 +$ +8.71 +$ +8.90 +Utica Shale +Net Production +Oil (MBbls) +25 +— +— +Gas (MMcf) +365 +— +— +NGL (Mgal) +80 +— +— +Total (MBOE) +87 +— +— +Average Sales Price: +Oil (per Bbl) +$ +78.21 +$ +— +$ +— +Gas (per Mcf) +$ +2.99 +$ +— +$ +— +NGL (per Gal) +$ +1.56 +$ +— +$ +— +Average Production Cost (per BOE) +$ +8.30 +$ +— +$ +— +Productive Wells and Acreage +The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the total gross and net developed and undeveloped acres as of December 31, 2012. +NRI/WI (1) +Productive +Oil Wells (2) +Productive +Gas Wells +Non-Productive +Oil Wells +Non-Productive +Gas Wells +Developed +Acreage (3) +Undeveloped +Acreage +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +West Cote Blanche Bay Field (4) +80.108/100 +108 +108 +1 +1 +163 +163 +18 +18 +5,668 +5,668 +— +— +E. Hackberry Field (5) +80.309/100 +41 +41 +— +— +96 +96 +— +— +3,931 +3,931 +581 +581 +W. Hackberry Field +83.333/100 +3 +3 +— +— +23 +23 +— +— +1,192 +1,192 +— +— +Utica Shale (6) +40.641/50.0 +1 +0.5 +1 +0.5 +— +— +— +— +2,441 +1,800 +134,693 +104,122 +Niobrara Formation (7) +36.2/41.5 +7 +3 +— +— +2 +1 +— +— +2,807 +1,404 +21,210 +10,384 +Bakken Formation (8) +2.7/2.9 +8 +0.2 +— +— +— +— +— +— +1,862 +163 +3,505 +701 +Overrides/Royalty Non-operated +Various +208 +0.4 +— +— +2 +0.06 +— +— +— +— +— +— +Total +376 +156.1 +2 +1.5 +286 +283.06 +18 +18 +17,901 +14,158 +159,989 +115,788 +47 +Table of Contents +Index to Financial Statements +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes seven gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 11% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) Does not give effect to our acquisition of approximately 22,000 additional net acres in February 2013. See "Item 1. Business-Recent Developments-February 2013 Utica Acreage Acquisition." +(7) +The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. Leases representing 45%, 17%, 2%, 12% and 24% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2013, 2014, 2015, 2016 and thereafter, respectively. +(8) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +Completed and Present Drilling and Recompletion Activities +The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +2012 +2011 +2010 +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +92 +92 +100 +96 +87 +84 +Dry +1 +0.5 +— +— +— +— +Total +93 +92.5 +100 +96 +87 +84 +Development: +Productive +70 +57 +82 +57 +57 +42 +Dry +8 +7 +3 +3 +— +— +Total +78 +64 +85 +60 +57 +42 +Exploratory: +Productive +19 +6 +1 +1 +— +— +Dry +— +— +— +— +— +— +Total +19 +6 +1 +1 +— +— +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations. +ITEM 3. +LEGAL PROCEEDINGS +The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR maintains that we paid approximately $1.8 million less in severance taxes under fixed price terms than the severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any liability to the LDR for underpayment of +48 +Table of Contents +Index to Financial Statements +severance taxes and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. We have maintained our right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15th Judicial District Court, Lafayette Parish, in Louisiana against our company seeking $2,275,729 in severance taxes, plus interest and court costs. We filed a response denying any liability to the LDR for underpayment of severance taxes and are defending our company in the lawsuit. The LDR had taken no further action on this lawsuit since filing its petition other than propounding discovery requests to which we have responded. Since serving discovery requests on the LDR and received the LDR's responses in 2012, there has been no further activity on the case and no trial date has been set. +In December 2010, the LDR filed two identical lawsuits against us in different venues to recover allegedly underpaid severance taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney's fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, we have denied all liability and will vigorously defend the lawsuit. The cases are in the very early stages, and we have not yet filed a response to these lawsuits. Recently, the LDR filed motions to stay the lawsuits before we filed any responsive pleadings. The LDR has advised us that it intends to pursue settlement discussions with us and other similarly situated defendants in separate proceedings, but has taken no action to initiate settlement talks. There has been no activity on either of these lawsuits for two years. +In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us, Great White Pressure Control LLC, or Great White, and six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White's employment of the former Cudd employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff's RICO claim was dismissed without prejudice by order of the court on February 14, 2007. We filed a motion for summary judgment on October 5, 2007. The Court entered a final interlocutory judgment in favor of all defendants, including us, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the case to the original state court, which motion was granted. Cudd subsequently filed amended petitions with the state court (a) alleging, among other things, that we conspired with the other defendants to misappropriate, and misappropriated Cudd's trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking monetary damages, including $11.8 million as a reasonable royalty for the alleged use of its trade secrets. Cudd also sought disgorgement of the alleged benefits received by the various defendants. Cudd also sought its attorney's fees, which Cudd claimed were not less than $450,000 plus 10% of any final judgment. This case went to trial on September 5, 2012 and on September 28, 2012 the jury rendered its verdict, awarding no damages to the plaintiffs. We along with all defendants filed a Motion for Entry of Judgment that is consistent with the jury's verdict. Cudd filed an Application for Disgorgement and a Motion for Judgment Notwithstanding the Verdict. The court denied all of Cudd's post-trial motions on October 12, 2012, the court issued its final judgment on January 10, 2013. On that same day, Cudd filed motions for a new trial and to modify, correct or reform the judgment. Those motions remain pending. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al., 38th Judicial District. No. 10-18714. The plaintiffs' original petition for damages, which did not name us as a defendant, alleges that the plaintiffs' property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. Plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and response costs and stigma damages. On December 7, 2010, we were served with a copy of the plaintiffs' first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including us, bringing the total number of defendants to 21. It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income; attorney fees and expenses; and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to us, current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior +49 +Table of Contents +Index to Financial Statements +Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, we filed a pleading challenging the legal sufficiency of the petitions on several grounds and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by us and similar pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue. In response, we and numerous defendants re-urged their pleadings challenging the legal sufficiency of the petitions. Some of the defendants' grounds for challenging the plaintiffs' petitions were heard by the court on May 25, 2011 and were denied. The court signed the written judgment on December 9, 2011. We noticed our intent to seek supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application. We filed our supervisory writ, which was denied by the Louisiana Third Circuit Court of Appeal and the Louisiana Supreme Court. We have been active in serving discovery requests and responding to discovery requests from the plaintiffs. A trial date has been set for September 2013. +Due to the early stages of the LDR and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that may result. In each case, management has determined the possibility of loss is remote. However, litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse affect on our financial condition or results of operations and management cannot determine the amount of loss, if any, that may result. +We have been named as a defendant in various other lawsuits related to our business. In each such case, management has determined that the possibility of loss is remote. The resolution of these matters is not expected to have a material adverse effect on our financial condition or results of operations in future periods. +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +50 +Table of Contents +Index to Financial Statements +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Price Range of Common Stock +Our common stock is quoted on the NASDAQ Global Select Market under the symbol “GPOR.” The following table sets forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2011 +First Quarter +$ +36.38 +$ +20.00 +Second Quarter +38.09 +23.84 +Third Quarter +37.49 +22.00 +Fourth Quarter +37.80 +18.72 +2012 +First Quarter +$ +37.63 +$ +27.66 +Second Quarter +29.66 +15.79 +Third Quarter +33.11 +18.17 +Fourth Quarter +40.73 +28.94 +2013 +First Quarter (through February 22, 2013) +$ +42.75 +$ +35.65 +On February 22, 2013, the last reported sale price of our common stock on the NASDAQ Global Select Market was $36.91. +Unregistered Sales of Equity Securities and Use of Proceeds +None. +Repurchases of Equity Securities +None. +Holders of Record +At the close of business on February 21, 2013, there were 325 stockholders of record holding 77,339,886 shares of our outstanding common stock. There were approximately 26,202 beneficial owners of our common stock as of February 21, 2013. +Dividend Policy +We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends to the holders of our common stock. +ITEM 6. +SELECTED FINANCIAL DATA +You should read the following selected consolidated financial data in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the related notes appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2012 , December 31, 2011 and December 31, 2010 and the selected consolidated balance sheet data at December 31, 2012 and December 31, 2011 are derived from our audited consolidated financial statements appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2009 and +51 +Table of Contents +Index to Financial Statements +December 31, 2008 and the selected consolidated balance sheet data at December 31, 2010 , December 31, 2009 and December 31, 2008 are derived from our audited consolidated financial statements that are not included in this report. The historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during any of the periods set forth in the following table. +Fiscal Year Ended December 31, +2012 +2011 +2010 +2009 +2008 +Selected Consolidated Statements of Operations Data: +Revenues +$ +248,926,000 +$ +229,254,000 +$ +127,921,000 +$ +85,968,000 +$ +141,873,000 +Costs and expenses: +Lease operating expenses +24,308,000 +20,897,000 +17,614,000 +16,316,000 +22,856,000 +Production taxes +29,400,000 +26,333,000 +13,966,000 +9,797,000 +15,813,000 +Depreciation, depletion and amortization +90,749,000 +62,320,000 +38,907,000 +29,225,000 +42,472,000 +Impairment of oil and natural gas properties +— +— +— +— +272,722,000 +General and administrative +13,808,000 +8,074,000 +6,063,000 +4,992,000 +6,843,000 +Accretion expense +698,000 +666,000 +617,000 +582,000 +560,000 +Gain on sale of assets +(7,300,000 +) +— +— +— +— +151,663,000 +118,290,000 +77,167,000 +60,912,000 +361,266,000 +Income (Loss) from Operations +97,263,000 +110,964,000 +50,754,000 +25,056,000 +(219,393,000 +) +Other (Income) Expense: +Interest expense +7,458,000 +1,400,000 +2,761,000 +2,309,000 +4,762,000 +Insurance recoveries +— +— +— +(1,050,000 +) +(769,000 +) +Settlement of fixed price contracts +— +— +— +— +(39,000,000 +) +Interest income +(72,000 +) +(186,000 +) +(387,000 +) +(564,000 +) +(540,000 +) +(Income) loss from equity method investments +(8,322,000 +) +1,418,000 +977,000 +706,000 +656,000 +(936,000 +) +2,632,000 +3,351,000 +1,401,000 +(34,891,000 +) +Income (Loss) from Continuing Operations before Income Taxes +98,199,000 +108,332,000 +47,403,000 +23,655,000 +(184,502,000 +) +Income Tax Expense (Benefit) +26,363,000 +(90,000 +) +40,000 +28,000 +— +Income (Loss) from Continuing Operations +71,836,000 +108,422,000 +47,363,000 +23,627,000 +(184,502,000 +) +Discontinued Operations: +Loss on disposal of Belize properties, net of tax +3,465,000 +— +— +— +— +Net Income (Loss) Available to Common Stockholders +$ +68,371,000 +$ +108,422,000 +$ +47,363,000 +$ +23,627,000 +$ +(184,502,000 +) +Net Income (Loss) Per Common Share—Basic: +$ +1.22 +$ +2.22 +$ +1.08 +$ +0.55 +$ +(4.33 +) +Net Income (Loss) Per Common Share—Diluted: +$ +1.21 +$ +2.20 +$ +1.07 +$ +0.55 +$ +(4.33 +) +52 +Table of Contents +Index to Financial Statements +At December 31, +2012 +2011 +2010 +2009 +2008 +Selected Consolidated Balance Sheet Data: +Total assets +$ +1,578,368,000 +$ +691,158,000 +$ +319,693,000 +$ +227,344,000 +$ +221,873,000 +Total debt, including current maturity +$ +299,038,000 +$ +2,283,000 +$ +51,917,000 +$ +52,428,000 +$ +70,731,000 +Total liabilities +$ +451,960,000 +$ +58,808,000 +$ +108,637,000 +$ +102,293,000 +$ +107,772,000 +Stockholders’ equity +$ +1,126,408,000 +$ +632,350,000 +$ +211,056,000 +$ +125,051,000 +$ +114,101,000 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors” and the section entitled “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. +Overview +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields and in the Utica Shale in Eastern Ohio. During 2010, we acquired our initial acreage position in the Niobrara Formation of Northwestern Colorado and, during 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, a 21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO (see "Item 1. Business-Recent Developments-Contribution ” above), and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +2012 and 2013 Year to Date Highlights +• +Oil and natural gas revenues increased 9% to $248.6 million for the year ended December 31, 2012 from $229.0 million for the year ended December 31, 2011. +• +Production increased 10% to approximately 2,572,618 barrels of oil equivalent, or BOE, for the year ended December 31, 2012 from approximately 2,333,208 BOE for the year ended December 31, 2011. +• +During 2012, we drilled 94 gross (71 net) wells, which included 23 gross (8.4 net) wells drilled by our operators in the Permian Basin, the Niobrara Formation and the Bakken Formation. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012. During 2012 we recompleted 94 gross (93 net) wells. Of our 94 new wells drilled, 69 were completed as producing wells and eight were non-productive and, at year end, 13 were waiting on completion and four were drilling. +• +During 2011 and 2012 , we acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, including the approximately 37,000 net acres acquired in December 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. We spud our first well on our Utica Shale acreage in February 2012 and, as of February 15, 2013, had spud 16 wells, of which three were producing, seven had been completed, four were waiting on completion and two were being drilled. +• +In October 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin for shares of Diamondback common stock and a promissory note, which was repaid to us at the closing of the Diamondback IPO. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. +• +In October and December of 2012, we issued a total of $300.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, resulting in net proceeds to us of approximately $290.3 million, a portion of which we used to repay all outstanding borrowings under our senior secured revolving credit facility. We intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan. +53 +Table of Contents +Index to Financial Statements +• +In December of 2012, we completed an underwritten public offering of an aggregate of 11,750,000 shares of our common stock (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares). In January 2013, the underwriters exercised their option to purchase the remaining 900,000 shares of our common stock to cover over-allotments. We received net proceeds of approximately $460.7 million through these sales of our common stock. We used approximately $372.0 million to fund our acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio and we intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan. +• +In February 2013, we completed an underwritten public offering of an aggregate of 8,912,500 shares of our common stock (including the exercise in full of an over-allotment option for 1,162,500 shares granted to the underwriters). We received net proceeds of approximately $325.8 million from this offering. We used approximately $220.4 million to fund our acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio and we intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan. +Critical Accounting Policies and Estimates +Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements: +Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period 2012, 2011 and 2010, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled $626.3 million at December 31, 2012 and $138.6 million at December 31, 2011. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development. +Ceiling Test . Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period January - December of the applicable year beginning with 2009, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved +54 +Table of Contents +Index to Financial Statements +properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural gas and natural gas liquids decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. No ceiling test impairment was required for the year ended December 31, 2012 . +Asset Retirement Obligations . We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. +We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates. +Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. NSAI, Ryder Scott and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2012 on a well-by-well basis for our properties. +Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. +Income Taxes . We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At +55 +Table of Contents +Index to Financial Statements +December 31, 2012, a valuation allowance of $4.6 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized. +Revenue Recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. +Investments—Equity Method. Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, our share of investees’ earnings or loss is recognized in the statement of operations. In accordance with FASB ASC 825 , "Financial Instruments," we have elected the fair value option of accounting for our equity method investment in Diamondback's stock. At the end of each reporting period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by us and the resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations. +We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. There was no impairment of equity method investments at December 31, 2012 or 2011 . +Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities. +Derivative Instruments and Hedging Activities . We seek to reduce our exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, “ Derivatives and Hedging ,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. +To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contacts and fixed price swaps are +56 +Table of Contents +Index to Financial Statements +accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, “ and related pronouncements. +RESULTS OF OPERATIONS +Results of Operations +The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2012 +2011 +2010 +Production Volumes: +Oil (MBbls) +2,323 +2,128 +1,777 +Gas (MMcf) +1,108 +878 +788 +Natural gas liquids (MGal) +2,714 +2,468 +2,821 +Oil equivalents (MBOE) +2,573 +2,333 +1,976 +Average Prices: +Oil (per Bbl) +$ +104.46 +(1) +$ +104.33 +(1) +$ +68.29 +(1) +Gas (per Mcf) +$ +2.91 +$ +4.37 +$ +4.40 +Natural gas liquids (per Gal) +$ +0.98 +$ +1.25 +$ +1.00 +Oil equivalents (per BOE) +$ +96.63 +$ +98.13 +$ +64.61 +Production Costs: +Average production costs (per BOE) +$ +9.45 +$ +8.96 +$ +8.92 +Average production taxes (per BOE) +$ +11.43 +$ +11.29 +$ +7.07 +Total production costs and production taxes (per BOE) +$ +20.88 +$ +20.25 +$ +15.99 +_____________________ +(1) +Includes various derivative contracts at a weighted average price of: +January – December 2012 +$ +108.31 +January – December 2011 +$ +86.96 +January – December 2010 +$ +57.55 +Excluding the net effect of fixed price swaps, the average oil price for 2012 would have been $ 106.11 per barrel of oil and $ 98.12 per BOE. The total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the net effect of fixed price swap contracts, the average oil price for 2011 would have been $ 107.13 per barrel of oil and $ 100.68 BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the net effect of forward sales contracts, the average oil price for 2010 would have been $ 78.12 per barrel of oil and $ 73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. +From 2011 to 2012, our net equivalent oil production increased 10% from 2,333,208 BOE to 2,572,618 BOE due to the results of our 2012 drilling and recompletion activities. From 2010 to 2011, our net equivalent oil production also increased 18% from 1,975,576 BOE to 2,333,208 BOE due to the results of our 2011 drilling and recompletion activities. We currently estimate that our 2013 production will be between 7,800,000 and 8,100,000 BOE. However, such estimate may change based on a change in our expected drilling and recompletion activities or the changing economic climate and unforeseen events, such as hurricanes. +57 +Table of Contents +Index to Financial Statements +Comparison of the Years Ended December 31, 2012 and December 31, 2011 +We reported net income of $68,371,000 for the year ended December 31, 2012 as compared to net income of $108,422,000 for the year ended December 31, 2011. This 37% decrease in period-to-period net income was due primarily to a 2% decrease in realized BOE prices to $96.63 for the year ended December 31, 2012, a 16% increase in lease operating expenses, a 71% increase in general and administrative expenses, a 12% increase in production taxes, an approximately $6.0 million increase in interest expense, a $3.5 million loss on the disposal of our Belize properties, net of tax, and a $24.2 million increase in income taxes from continuing and discontinued operations, partially offset by a 10% increase in net production to 2,572,618 BOE, a gain on sale of assets of $7.3 million and income from equity method investments of $8.3 million. +Oil and Gas Revenues . For the year ended December 31, 2012 , we reported oil and natural gas revenues of $248,601,000 as compared to oil and natural gas revenues of $228,953,000 during 2011. This $19,648,000, or 9%, increase in revenues was primarily attributable to a 10% increase in net production to 2,572,618 BOE from 2,333,208 BOE, partially offset by a 2% decrease in realized BOE prices to $96.63 from $98.13, for the year ended December 31, 2012 as compared to the year ended December 31, 2011. +The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2012 and December 31, 2011: +Year Ended +December 31, +2012 +2011 +Oil production volumes (MBbls) +2,323 +2,128 +Gas production volumes (MMcf) +1,108 +878 +Natural gas liquids production volumes (MGal) +2,714 +2,468 +Oil equivalents (MBOE) +2,573 +2,333 +Average oil price (per Bbl) +$ +104.46 +$ +104.33 +Average gas price (per Mcf) +$ +2.91 +$ +4.37 +Average natural gas liquids (per Gal) +$ +0.98 +$ +1.25 +Oil equivalents (per BOE) +$ +96.63 +$ +98.13 +Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes increased to $ 24,308,000 for the year ended December 31, 2012 from $ 20,897,000 for 2011. This increase was mainly the result of an increase in expenses related to property taxes, chemicals and fuel, compressor rentals, contract pumpers, field supervision, equipment repairs and maintenance, salt water disposal and well workovers. +Production Taxes . Production taxes increased to $ 29,400,000 for the year ended December 31, 2012 from $ 26,333,000 for 2011. This increase was primarily related to a 10% increase in production partially offset by a 2% decrease in the average realized BOE price received, resulting in a 9% increase in oil and gas revenues. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $ 90,749,000 for the year ended December 31, 2012 , and consisted of $90,230,000 in depletion of oil and natural gas properties and $519,000 in depreciation of other property and equipment, as compared to total DD&A expense of $ 62,320,000 for 2011. This increase was due to an increase in our full cost pool as a result of our capital activities, an increase in our production and a decrease in our total proved reserves volume used to calculate our total DD&A expense. +General and Administrative Expenses . Net general and administrative expenses increased to $ 13,808,000 for the year ended December 31, 2012 from $ 8,074,000 for 2011. This $5,734,000 increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in legal expenses, franchise taxes and fees for auditing and tax services, partially offset by an increase in administrative services reimbursements under the acquisition team agreement and an increase in general and administrative costs related to exploration and development activity capitalized to the full cost pool. +58 +Table of Contents +Index to Financial Statements +Accretion Expense . Accretion expense increased to $ 698,000 for the year ended December 31, 2012 from $ 666,000 for the same period in 2011. +Interest Expense . Interest expense increased to $ 7,458,000 for the year ended December 31, 2012 from $ 1,400,000 for 2011 due to higher outstanding debt balances and higher weighted average interest rates. During 2011, total weighted debt outstanding under our revolving credit facility was approximately $21,084,000 and bore a weighted average interest rate of 3.32%. During 2012, total weighted average debt outstanding under our revolving credit facility was approximately $45.0 million and bore a weighted average interest rate of 2.85%. On October 17, 2012, we issued $250.0 million aggregate principal amount of our 7.75% Senior Notes due 2020, a portion of the proceeds from which was used to repay all outstanding borrowings under our revolving credit facility. On December 21, 2012, we issued an additional $50.0 million aggregate principal amount of our 7.75% Senior Notes due 2020. In addition, we wrote off approximately $1,143,000 of unamortized loan fees associated with our revolving credit facility in conjunction with the lowering of our borrowing base during the year ended December 31, 2012. +Income Taxes . As of December 31, 2012 , we had a net operating loss carry forward of approximately $4.3 million, in addition to numerous temporary differences, which gave rise to a net deferred tax liability. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2012, a valuation allowance of $4.6 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized. We recognized an income tax expense from continuing and discontinued operations of $24.1 million for the year ended December 31, 2012. +Comparison of the Years Ended December 31, 2011 and December 31, 2010 +We reported net income of $108,422,000 for the year ended December 31, 2011 as compared to net income of $47,363,000 for the year ended December 31, 2010. This 129% increase in period-to-period net income was due primarily to an 18% increase in net production to 2,333,208 BOE and a 52% increase in realized BOE prices to $98.13 for the year ended December 31, 2011, partially offset by a 19% increase in lease operating expenses, a 33% increase in general and administrative expenses and an 89% increase in production taxes. +Oil and Gas Revenues . For the year ended December 31, 2011, we reported oil and natural gas revenues of $228,953,000 as compared to oil and natural gas revenues of $127,636,000 during 2010. This $101,317,000, or 79%, increase in revenues was primarily attributable to an 18% increase in net production to 2,333,208 BOE from 1,975,576 BOE and a 52% increase in realized BOE prices to $98.13 from $64.61, in each case for the year ended December 31, 2011 as compared to the year ended December 31, 2010. +The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2011 and December 31, 2010: +Year Ended +December 31, +2011 +2010 +Oil production volumes (MBbls) +2,128 +1,777 +Gas production volumes (MMcf) +878 +788 +Natural gas liquids production volumes (MGal) +2,468 +2,821 +Oil equivalents (MBOE) +2,333 +1,976 +Average oil price (per Bbl) +$ +104.33 +$ +68.29 +Average gas price (per Mcf) +$ +4.37 +$ +4.40 +Average natural gas liquids (per Gal) +$ +1.25 +$ +1.00 +Oil equivalents (per BOE) +$ +98.13 +$ +64.61 +Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes increased to $20,897,000 for the year ended December 31, 2011 from $17,614,000 for 2010. This increase was mainly the result of an increase in expenses +59 +Table of Contents +Index to Financial Statements +related to chemicals and fuel, equipment repairs and maintenance, field supervision, overhead, property taxes, rentals, salt water disposal and well workovers. +Production Taxes . Production taxes increased to $26,333,000 for the year ended December 31, 2011 from $13,966,000 for 2010. This increase was primarily related to an 18% increase in production and a 52% increase in the average realized BOE price received resulting in a 79% increase in oil and gas revenues. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $62,320,000 for the year ended December 31, 2011, and consisted of $61,965,000 in depletion of oil and natural gas properties and $355,000 in depreciation of other property and equipment, as compared to total DD&A expense of $38,907,000 for 2010. This increase was due to an increase in our full cost pool as a result of our capital activities, an increase in our production and a decrease in our total proved reserves volume, primarily resulting from the contribution to Diamondback of our Permian Basin oil and natural gas interests, used to calculate our total DD&A expense. +General and Administrative Expenses . Net general and administrative expenses increased to $8,074,000 for the year ended December 31, 2011 from $6,063,000 for 2010. This $2,011,000 increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in legal expenses, franchise taxes and bank fees, partially offset by an increase in administrative services reimbursements under the acquisition team agreement and an increase in general and administrative costs related to exploration and development activity capitalized to the full cost pool. +Accretion Expense . Accretion expense increased slightly to $666,000 for the year ended December 31, 2011 from $617,000 for the same period in 2010. +Interest Expense . Interest expense decreased to $1,400,000 for the year ended December 31, 2011 from $2,761,000 for 2010 due to a decrease in the interest rate paid and the repayment of all of our outstanding debt under our revolving credit facility during the fourth quarter of 2011 so that no amounts were outstanding as of December 31, 2011, as compared to $49,500,000 outstanding as of the same date in 2010. Further, during 2010, in conjunction with the repayment of our prior revolving credit facility on September 30, 2010, we expensed approximately $225,000 in unamortized loan fees associated with this facility, which is included in interest expense in our consolidated statements of operations for the year ended December 31, 2010. Total weighted debt outstanding under our revolving credit facility was $21,084,000 for the year ended December 31, 2011 and $46,931,000 for 2010. As of December 14, 2011 (the latest date during the year ended December 31, 2011 on which we had borrowings outstanding), amounts borrowed under our credit facility bore interest at the Eurodollar rate of 2.26%. +Income Taxes . As of December 31, 2011, we had a net operating loss carry forward of approximately $116.8 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2011, a valuation allowance of $12,347,000 had been provided for deferred tax assets, with the exception of $1,000,000 related to alternative minimum taxes. We recognized an income tax benefit of $90,000 for the year ended December 31, 2011. +Liquidity and Capital Resources +Overview . Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our credit facilities and the proceeds from issuances of equity securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or our oil and natural gas production. During 2012, we received net proceeds (before offering expenses) of approximately $427.9 million from the sale of shares of our common stock and net proceeds of approximately $290.3 million from the Notes Offerings. We received an additional $32.8 million of net proceeds (before offering expenses) in January 2013 following the exercise by the underwriters of their option to purchase an additional 900,000 shares of our common stock to cover over-allotments and an additional $325.8 million of net proceeds (before offering expenses) in February 2013 from the February 2013 Equity Offering. During 2011, we received aggregate net proceeds (before offering expenses) of approximately $307.1 million from the sale of shares of our common stock. +Net cash flow provided by operating activities was $199,158,000 for the year ended December 31, 2012 , as compared to net cash flow provided by operating activities of $158,138,000 for 2011. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 10% increase in our net BOE production, partially offset by a 2% decrease in net realized BOE prices. +60 +Table of Contents +Index to Financial Statements +Net cash flow provided by operating activities was $158,138,000 for the year ended December 31, 2011 as compared to net cash flow provided by operating activities of $85,835,000 for 2010. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 52% increase in net realized BOE prices and an 18% increase in our net BOE production. +Net cash used in investing activities for the year ended December 31, 2012 was $840,579,000 as compared to $323,248,000 for 2011. During the year ended December 31, 2012 , we spent $757,192,000 in additions to oil and natural gas properties, of which $175,401,000 was spent on our 2012 drilling and recompletion programs, $38,838,000 was spent on expenses attributable to the wells drilled and recompleted during 2011, $13,309,000 was spent on compressors and other facility enhancements, $1,699,000 was spent on plugging costs, $509,806,000 was spent on lease related costs, primarily the acquisition of leases in the Utica Shale, and $4,990,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, during the year ended December 31, 2012 , $ 103,915,000 was invested in Grizzly and an aggregate of $43,392,000 was invested in our other equity investments. During the year ended December 31, 2012 , we used cash from operations and proceeds from the Notes Offerings and the December 2012 Equity Offering for our investing activities. +Net cash used in investing activities for the year ended December 31, 2011 was $323,248,000 as compared to $105,315,000 for 2010. During the year ended December 31, 2011, we spent $287,292,000 in additions to oil and natural gas properties, of which $106,947,000 was spent on our 2011 drilling and recompletion programs, $31,872,000 was spent on expenses attributable to the wells drilled and recompleted during 2010, $8,320,000 was spent on compressors and other facility enhancements, $177,000 was spent on plugging costs, $124,713,000 was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $3,651,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, $3,182,000 was loaned to, and $22,676,000 was invested in, Grizzly during the year ended December 31, 2011, and $3,794,000, $6,009,000 and $2,142,000 was invested in our investments in Tatex III, Bison and Muskie, respectively, during the year ended December 31, 2011. During the year ended December 31, 2011, we used cash from operations and proceeds from our equity offering for our investing activities. +Net cash provided by financing activities for the year ended December 31, 2012 was $714,612,000 as compared to $256,539,000 for 2011. The 2012 amount provided by financing activities was primarily attributable to the net proceeds of $426,907,000 from the December 2012 Equity Offering (not including the $32,776,000 received in January 2013 following the exercise by the underwriters of the December 2012 Equity Offering of their option to purchase an additional 900,000 shares of our common stock to cover over-allotments), $296,835,000 from our offerings of 7.750% Senior Notes due 2020 and $184,000 from the exercise of stock options. +Net cash provided by financing activities for the year ended December 31, 2011 was $256,539,000 as compared to $20,224,000 for 2010. The 2011 amount provided by financing activities was primarily attributable to the net proceeds of $307,154,000 from our equity offerings and exercise of stock options, partially offset by net principal payments of $49,500,000 on borrowings under our credit facility. The 2010 amount provided by financing activities was primarily attributable to the net proceeds from our equity offerings of $21,358,000. +Credit Facility . On September 30, 2010, we entered into a senior secured revolving credit facility with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association, or Amegy Bank. The revolving credit facility initially matured on September 30, 2013, had a maximum commitment amount of $100.0 million and had a borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24, 2010. On May 3, 2011, we entered into a first amendment to the revolving credit facility with The Bank of Nova Scotia, Amegy Bank, KeyBank National Association, or KeyBank, and Société Générale. Under the terms of the first amendment, KeyBank and Société Générale were added as additional lenders, the maximum amount of the revolving credit facility was increased to $350.0 million, the borrowing base was increased to $90.0 million, certain fees and rates payable by us under the credit facility were decreased, and the maturity date was extended until May 3, 2015. On October 31, 2011, we entered into additional amendments to our revolving credit facility pursuant to which, among other things, the borrowing base under the facility was increased to $125.0 million. On December 14, 2011, we repaid all outstanding borrowings under the credit facility with a portion of the net proceeds of our equity offering completed on December 5, 2011 pending the application of such proceeds to fund certain Utica Shale lease acquisitions and for general corporate purposes. On May 2, 2012, we entered into an amendment to the revolving credit facility under which, among other things, the borrowing base was increased to $155.0 million. In addition, Credit Suisse, Deutsche Bank Trust Company Americas and IBERIABANK were added as additional lenders and Société Générale left the bank group. As of December 31, 2012, there were no borrowings outstanding under our revolving credit facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility. +61 +Table of Contents +Index to Financial Statements +On October 9, 2012, we entered into an amendment to our revolving credit facility that modified certain covenants to permit the October Notes Offering. The October Notes Offering closed on October 17, 2012 and we repaid all indebtedness outstanding under our revolving credit facility on that date with a portion of the proceeds from the October Notes Offering. Effective as of October 17, 2012, we amended our revolving credit facility to lower the applicable rates (i) from a range of 1.00% to 1.75% to a range of 0.75% to 1.50% for the base rate loans and (ii) from a range of 2.00% to 2.75% to a range of 1.75% to 2.50% for the Eurodollar rate loans and letters of credit. This amendment also lowered the commitment fees for Level 1 and Level 2 usage levels, in each case, from 0.50% per annum to 0.375% per annum. Also, effective as of October 17, 2012, in connection with the completion of the October Notes Offering and the Contribution, our borrowing base under the credit facility was reduced to $45.0 million until the next borrowing base redetermination. Effective as of December 18, 2012, we entered into another amendment to our revolving credit facility that modified certain covenants to permit the December Notes Offering and reduce the borrowing base under our revolving credit facility to $40.0 million until the next borrowing base redetermination. +Advances under our revolving credit facility, as amended, may be in the form of either base rate loans or Eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from .75% to 1.50%, plus (2) the highest of: (a) the federal funds rate plus 0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the Eurodollar rate for an interest period of one month plus 1.00%. The interest rate for Eurodollar loans is equal to (1) the applicable rate, which ranges from 1.75% to 2.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. We have had no outstanding borrowings under our revolving credit facility since October 17, 2012, on which date the outstanding borrowings, prior to repayment, bore interest at the Eurodollar rate (2.97%) per annum. +Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries' ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2012. +Senior Notes . On October 17, 2012, we issued $250.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, or the October Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee. +On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, or the December Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The December Notes were issued as additional securities under the existing senior note indenture. The December Notes and the October Notes are treated as a single class of debt securities under the senior note indenture. We used a portion of the net proceeds from the October Notes Offering to repay all amounts outstanding at such time under our revolving credit facility. We intend to use the remaining net proceeds of October Notes Offering and the net proceeds of the December Notes Offering for general corporate purposes, which may include funding a portion of our 2013 capital development plan. +Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. +62 +Table of Contents +Index to Financial Statements +The Notes are senior unsecured obligations and rank equally in the right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes. +We may redeem some or all of the Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, we may redeem the Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Notes initially issued remains outstanding immediately after such redemption. +If we experience a change of control (as defined in the senior note indenture), we will be required to make an offer to repurchase the Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in the senior note indenture, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. +The senior note indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. +Building Loans . In June 2004, we purchased the office building we occupy in Oklahoma City, Oklahoma, for $3.7 million. We entered into a new building loan in March 2011 to refinance the $2.4 million outstanding at that time. The new agreement matures in February 2016 and bears interest at a fixed rate of 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. As of December 31, 2012 , approximately $2.1 million was outstanding on this loan. +Capital Expenditures . Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions of oil and natural gas interests in the Utica Shale, Permian Basin and the Niobrara Formation, to fund Grizzly's delineation drilling program and initial preparation of the Algar Lake facility and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, and (2) pursue acquisition and disposition opportunities and (3) business integration opportunities. +Of our net reserves at December 31, 2012 , 40.2% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities. +At December 31, 2012 , our booked inventory of prospects included approximately 36 drilling locations at WCBB. The drilling schedule used in our December 31, 2012 reserve report anticipates that all of those wells will be drilled by the end of 2015. During 2012, we recompleted 61 wells and drilled 31 wells, of which 27 were completed as producers and four were non-productive, for an aggregate cost of $68.2 million. From January 1, 2013 through February 15, 2013, we recompleted 12 existing wells at our WCBB field. We currently intend to recomplete 60 wells and drill 22 to 24 new wells during 2013 at our WCBB field. Our aggregate drilling and recompletion expenditures for our WCBB field during 2013 are estimated to be approximately $42.0 million to $45.0 million. +63 +Table of Contents +Index to Financial Statements +In our Hackberry fields, in 2012, we recompleted 32 existing wells and drilled 24 wells, of which 19 were completed as producers, three were non-productive and, at December 31, 2012, two were drilling, for an aggregate cost of $70.1 million. From January 1, 2013 through February 15, 2013, we recompleted two existing wells and drilled two new wells at our East Hackberry field and, at February 15, 2013, we were in the process of drilling one additional well at our East Hackberry field. We currently intend to drill ten to twelve wells and recomplete 24 wells in our Hackberry fields in 2013. Total capital expenditures for our Hackberry fields during 2013 are estimated to be approximately $26.0 million to $28.0 million. +From January 1, 2012 through October 11, 2012, 19 gross (8.3 net) wells were spud on our Permian Basin acreage, all of which were completed as producers and one gross (0.3 net) existing well was recompleted between January 1, 2012 and October 11, 2012, for an aggregate cost of $20.9 million. As discussed above under the heading "Item 1. Business-Recent Developments-Contribution ,” on October 11, 2012, we contributed all of our oil and gas interests in the Permian Basin to Diamondback. We have no further funding obligations for operations relating to this Permian Basin acreage conducted after October 11, 2012. +In the Niobrara Formation in Northwestern Colorado, in 2011, we completed a 60 square mile 3-D seismic survey and have received a processed version of the seismic data. During 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. Our total capital expenditures with respect to these three gross wells in the Niobrara Formation were approximately $2.5 million. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2013. +In the Utica Shale in Eastern Ohio, in 2011 and 2012 , we acquired approximately 137,000 gross (106,000 net) acres for approximately $626.9 million. As of December 31, 2012 , we had drilled 14 wells on our Utica Shale acreage. Our total lease acquisition costs in the Utica Shale during 2012 were approximately $508.5 million. In addition, during 2012, we spent approximately $66.1 million to drill 14 gross (6.7 net) wells on our Utica acreage. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 2013. Total capital expenditures in the Utica Shale during 2013 are estimated to be approximately $382.0 million to $426.0 million, excluding leasehold acquisitions. +During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2012 , our net investment in Grizzly was approximately $172.8 million. Our capital requirements in 2012 for Grizzly were approximately $103.9 million, primarily for the expenses associated with the construction of the Algar Lake facility, drilling activity during the 2011-2012 winter drilling season and our $56.3 million share of the cost of the May River property. This acquisition was completed in February 2012 when Grizzly purchased approximately 47,000 acres of oil sands leases in the Athabasca oil sands area for $225.0 million CAD. We funded our portion of the purchase price with borrowings under our revolving credit facility. Effective October 5, 2012, Grizzly entered into a $125.0 million revolving credit facility, of which $75.0 million is initially available for borrowing to fund additional infrastructure relating to the Algar Lake facility and other future development projects. As of that same date, we entered into an agreement with Grizzly in which we committed to make monthly payments from October 2012 to May 2013 in the aggregate amount of approximately $8.5 million (of which $4.0 million was paid in 2012) to fund the construction and development of the Algar Lake facility. We also agreed to fund our proportionate share of any unfunded cost overruns, which we currently expect to be $3.0 million to $7.0 million. +We did not have any capital expenditures in 2012 related to our interests in Thailand. Total 2013 capital expenditures for Thailand are estimated to be $2.0 million to $2.5 million to drill one gross well. +In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing. Stingray Pressure and Stingray Cementing provide well completion services. We also acquired a 50% equity interest in Blackhawk Midstream LLC, or Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. Blackhawk also has an option to acquire up to a 40% equity interest in the entity that provides midstream services to us in connection with our Utica Shale acreage. In the fourth quarter of 2012, we acquired a 50% equity interest in Stingray Logistics LLC, Stingray Logistics. Stingray Logistics will provide well services. In March 2012, we acquired a 50% equity interest in Timber Wolf Terminals LLC, or Timber Wolf, for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie Holdings LLC, or Muskie, which is engaged in the mining of +64 +Table of Contents +Index to Financial Statements +hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. +Our total capital expenditures for 2013 are currently estimated to be in the range of $458.0 million to $512.0 million, excluding the acquisition costs associated with our February 2013 Utica Shale acquisition and with any additional Utica Shale acreage or other potential acquisitions and any amounts attributable to Grizzly. Approximately 85% of our 2013 estimated capital expenditures are currently expected to be spent in the Utica Shale. This range is up from the $277.6 million spent on 2012 activities primarily due to the significant increase in our acreage position in the Utica Shale and our contemplated Utica development plans, although such anticipated 2013 expenditures are partially offset relative to 2012 by the elimination of development costs in the Permian Basin as a result of the Contribution. We intend to continue to monitor pricing and cost developments and make adjustments to our future capital expenditure programs as warranted. +We believe that our cash on hand, cash flow from operations, proceeds from our recent offerings of debt and equity securities and borrowings under our revolving credit facility will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling programs, pursue additional acquisitions, exercise our Blackhawk option or accelerate our Canadian oil sands project, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. +Commodity Price Risk +The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $13.31 per MMBtu in July 2008. On December 31, 2012 , the West Texas Intermediate posted price for crude oil was $91.82 per barrel and the Henry Hub spot market price of natural gas was $3.35 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price fluctuations, in November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our expected 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. +Commitments +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller's (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2012, the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2012, we have plugged 354 wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. +65 +Table of Contents +Index to Financial Statements +Contractual and Commercial Obligations +The following table sets forth our contractual and commercial obligations at December 31, 2012 : +Payment due by period (1) +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +Building loan (2) +$ +2,143,000 +$ +150,000 +$ +326,000 +$ +1,667,000 +$ +— +7.75% senior unsecured notes due 2020 +486,000,000 +23,250,000 +46,500,000 +46,500,000 +369,750,000 +Asset retirement obligations +13,275,000 +60,000 +1,739,000 +820,000 +10,656,000 +Employment agreements +7,050,000 +2,400,000 +4,650,000 +— +— +Grizzly capital commitments +6,280,000 +6,280,000 +— +— +— +Operating leases +586,000 +179,000 +305,000 +102,000 +— +Total +$ +515,334,000 +$ +32,319,000 +$ +53,520,000 +$ +49,089,000 +$ +380,406,000 +_____________________ +(1) Does not include short-term derivative instruments of $9,778,000, which are due in less than one year. +(2) +Does not include estimated interest of $121,000 due in less than one year, $214,000 due in 1-3 years and $16,000 due in 3-5 years. +New Accounting Pronouncements +In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 , "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," which requires additional information about amounts reclassified out of accumulated other comprehensive income by component. This ASU requires the presentation, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, a cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The requirements of this ASU are effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The Company will adopt the provisions of this ASU for reporting periods in 2013 and does not expect the adoption of this ASU to have a material effect on its consolidated financial statements. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $13.31 per MMBtu in July 2008. On February 22, 2013, the West Texas Intermediate posted price for crude oil was $93.13 per barrel and the Henry Hub spot market price of natural gas was $3.27 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +66 +Table of Contents +Index to Financial Statements +To mitigate the effects of commodity price fluctuations, in November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. At December 31, 2012, we had a net liability derivative position of $9.8 million as compared to a net asset derivative position of $1.6 million as of December 31, 2011, related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately $19.4 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $19.4 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. +Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or Eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the Eurodollar rates are elected, the Eurodollar rates. As of October 17, 2012 (the latest date during the year ended December 31, 2012 on which we had borrowings outstanding), amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 2.97%. As of December 31, 2012, we had no variable interest rate borrowings outstanding; therefore, an increase in interest rates would not have impacted our interest expense. As of December 31, 2012, we did not have any interest rate swaps to hedge our interest risks. +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. +As of December 31, 2012, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that, as of December 31, 2012, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +67 +Table of Contents +Index to Financial Statements +Management's Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2012. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2012 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2012, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +68 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2012 and our report dated February 28, 2013 expressed an unqualified opinion on those financial statements. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 28, 2013 +69 +Table of Contents +Index to Financial Statements +ITEM 9B. +OTHER INFORMATION +None. +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10-Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning Item 11-Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For information concerning Item 14-Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +70 +Table of Contents +Index to Financial Statements +PART IV +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +The following documents are filed as part of this report: +(1) +Financial Statements +Reference is made to the Index to Financial Statements appearing on Page F-1. +(2) +Financial Statement Schedules +All financial statement schedules have been omitted because they are not applicable or the required disclosure is presented in the financial statements or notes thereto. +(3) +Exhibits +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.3 +Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012). +2.4 +Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 18, 2012). +2.5 +Amendment, dated December 19, 2012, to the Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 20, 2012). +2.6 +Purchase and Sale Agreement, dated February 11, 2013, by and between Windsor Ohio, LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 15, 2013). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +71 +Table of Contents +Index to Financial Statements +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +4.6 +Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.7 +Registration Rights Agreement, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.8 +First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +4.9 +Registration Rights Agreement, dated as of December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.4+ +Employment Agreement, dated November 7, 2012, between the Company and Mike Liddell (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.5+ +Employment Agreement, dated November 7, 2012, between the Company and James D. Palm (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.6+ +Employment Agreement, dated November 7, 2012, between the Company and Michael G. Moore (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.7 +Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). +10.8 +Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). +10.9 +First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, KeyBank National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2011). +10.10 +Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). +72 +Table of Contents +Index to Financial Statements +10.11 +Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). +10.12 +Fourth Amendment, dated May 2, 2012, to Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent and letter of credit issuer, Amegy Bank National Association, Key Bank National Association and Société Générale (incorporated by reference to Exhibit 10.1 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 10, 2012). +10.13 +Fifth Amendment to Credit Agreement, effective as of October 9, 2012, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 9, 2012). +10.14 +Sixth Amendment to Credit Agreement, effective as of October 17, 2012, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +10.15 +Seventh Amendment to Credit Agreement, effective as of December 18, 2012, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +10.16 +Investor Rights Agreement, dated as of October 11, 2012, between Gulfport Energy Corporation and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 17, 2012). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Ryder Scott Company. +23.4* +Consent of Pinnacle Energy Services, LLC. +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1** +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2** +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Ryder Scott Company. +101.INS** +XBRL Instance Document. +101.SCH** +XBRL Taxonomy Extension Schema Document. +73 +Table of Contents +Index to Financial Statements +101.CAL** +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF** +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB** +XBRL Taxonomy Extension Labels Linkbase Document. +101.PRE** +XBRL Taxonomy Extension Presentation Linkbase Document. +* +Filed herewith. +** +Furnished herewith, not filed. ++ +Management contract, compensatory plan or arrangement. +74 +Table of Contents +Index to Financial Statements +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Date: February 28, 2013 +GULFPORT ENERGY CORPORATION +By: +/s/ JAMES D. PALM +James D. Palm +Chief Executive Officer +In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Date: +February 28, 2013 +By: +/s/ JAMES D. PALM +James D. Palm +Chief Executive Officer and Director +(Principal Executive Officer) +Date: +February 28, 2013 +By: +/s/ MIKE LIDDELL +Mike Liddell +Chairman of the Board and Director +Date: +February 28, 2013 +By: +/s/ MICHAEL G. MOORE +Michael G. Moore +Vice President and Chief Financial Officer +(Principal Financial and Accounting Officer) +Date: +February 28, 2013 +By: +/s/ DONALD DILLINGHAM +Donald Dillingham +Director +Date: +February 28, 2013 +By: +/s/ CRAIG GROESCHEL +Craig Groeschel +Director +Date: +February 28, 2013 +By: +/s/ DAVID L. HOUSTON +David L. Houston +Director +Date: +February 28, 2013 +By: +/s/ SCOTT E. STRELLER +Scott E. Streller +Director +S -1 +Table of Contents +Index to Financial Statements +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F -2 +Consolidated Balance Sheets, December 31, 2012 and December 31, 2011 +F -3 +Consolidated Statements of Operations, Years Ended December 31, 2012, 2011 and 2010 +F -5 +Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2012, 2011 and 2010 +F -6 +Consolidated Statements of Stockholders’ Equity, Years Ended December 31, 2012, 2011 and 2010 +F -7 +Consolidated Statements of Cash Flows, Years Ended December 31, 2012, 2011 and 2010 +F -8 +Notes to Financial Statements +F -9 +F -1 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 28, 2013 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 28, 2013 +F -2 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +(Amounts rounded to nearest thousand) +December 31, +2012 +December 31, +2011 +Assets +Current assets: +Cash and cash equivalents +$ +167,088,000 +$ +93,897,000 +Accounts receivable—oil and gas +25,615,000 +28,019,000 +Accounts receivable—related parties +34,848,000 +4,731,000 +Prepaid expenses and other current assets +1,506,000 +1,327,000 +Short-term derivative instruments +664,000 +1,601,000 +Total current assets +229,721,000 +129,575,000 +Property and equipment: +Oil and natural gas properties, full-cost accounting, $626,295,000 and $138,623,000 excluded from amortization in 2012 and 2011, respectively +1,611,090,000 +1,035,754,000 +Other property and equipment +8,662,000 +8,024,000 +Accumulated depletion, depreciation, amortization and impairment +(665,884,000 +) +(575,142,000 +) +Property and equipment, net +953,868,000 +468,636,000 +Other assets: +Equity investments ($151,317,000 and $0 attributable to fair value option in 2012 and 2011, respectively) +381,484,000 +86,824,000 +Other assets +13,295,000 +5,123,000 +Total other assets +394,779,000 +91,947,000 +Deferred tax asset +— +1,000,000 +Total assets +$ +1,578,368,000 +$ +691,158,000 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +110,244,000 +$ +43,872,000 +Asset retirement obligation—current +60,000 +620,000 +Short-term derivative instruments +10,442,000 +— +Current maturities of long-term debt +150,000 +141,000 +Total current liabilities +120,896,000 +44,633,000 +Asset retirement obligation—long-term +13,215,000 +12,033,000 +Deferred tax liability +18,607,000 +— +Long-term debt, net of current maturities +298,888,000 +2,142,000 +Other non-current liabilities +354,000 +— +Total liabilities +451,960,000 +58,808,000 +Commitments and contingencies (Notes 16 and 17) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding +— +— +Stockholders’ equity: +Common stock - $.01 par value, 100,000,000 authorized, 67,527,386 issued and outstanding in 2012 and 55,621,371 in 2011 +674,000 +556,000 +Paid-in capital +1,036,245,000 +604,584,000 +Accumulated other comprehensive income (loss) +(3,429,000 +) +2,663,000 +Retained earnings +92,918,000 +24,547,000 +Total stockholders’ equity +1,126,408,000 +632,350,000 +Total liabilities and stockholders’ equity +$ +1,578,368,000 +$ +691,158,000 +F -3 +Table of Contents +Index to Financial Statements +See accompanying notes to consolidated financial statements. +F -4 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2012 +2011 +2010 +Revenues: +Oil and condensate sales +$ +242,708,000 +$ +222,025,000 +$ +121,350,000 +Gas sales +3,225,000 +3,838,000 +3,468,000 +Natural gas liquid sales +2,668,000 +3,090,000 +2,818,000 +Other income +325,000 +301,000 +285,000 +248,926,000 +229,254,000 +127,921,000 +Costs and expenses: +Lease operating expenses +24,308,000 +20,897,000 +17,614,000 +Production taxes +29,400,000 +26,333,000 +13,966,000 +Depreciation, depletion, and amortization +90,749,000 +62,320,000 +38,907,000 +General and administrative +13,808,000 +8,074,000 +6,063,000 +Accretion expense +698,000 +666,000 +617,000 +Gain on sale of assets +(7,300,000 +) +— +— +151,663,000 +118,290,000 +77,167,000 +INCOME FROM OPERATIONS +97,263,000 +110,964,000 +50,754,000 +OTHER (INCOME) EXPENSE: +Interest expense +7,458,000 +1,400,000 +2,761,000 +Interest income +(72,000 +) +(186,000 +) +(387,000 +) +(Income) loss from equity method investments +(8,322,000 +) +1,418,000 +977,000 +(936,000 +) +2,632,000 +3,351,000 +INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES +98,199,000 +108,332,000 +47,403,000 +INCOME TAX EXPENSE (BENEFIT) +26,363,000 +(90,000 +) +40,000 +INCOME FROM CONTINUING OPERATIONS +71,836,000 +108,422,000 +47,363,000 +DISCONTINUED OPERATIONS +Loss on disposal of Belize properties, net of tax +3,465,000 +— +— +NET INCOME +$ +68,371,000 +$ +108,422,000 +$ +47,363,000 +NET INCOME PER COMMON SHARE: +Basic net income from continuing operations per share +$ +1.28 +$ +2.22 +$ +1.08 +Basic net income from discontinued operations, net of tax, per share +(0.06 +) +— +— +Basic net income per share +$ +1.22 +$ +2.22 +$ +1.08 +Diluted net income from continuing operations per share +$ +1.27 +$ +2.20 +$ +1.07 +Diluted net income from discontinued operations, net of tax, per share +(0.06 +) +— +— +Diluted net income per share +$ +1.21 +$ +2.20 +$ +1.07 +Weighted average common shares outstanding—Basic +55,933,354 +48,754,840 +43,863,190 +Weighted average common shares outstanding—Diluted +56,417,488 +49,206,963 +44,256,092 +See accompanying notes to consolidated financial statements. +F -5 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(Amounts rounded to nearest thousand) +2012 +2011 +2010 +Net income +$ +68,371,000 +$ +108,422,000 +$ +47,363,000 +Foreign currency translation adjustment +1,355,000 +(1,865,000 +) +2,255,000 +Change in fair value of derivative instruments, net of taxes (1) +(8,452,000 +) +1,576,000 +(4,720,000 +) +Reclassification of settled contracts, net of taxes (2) +1,005,000 +4,720,000 +18,736,000 +Other comprehensive income (loss) +(6,092,000 +) +4,431,000 +16,271,000 +Comprehensive income +$ +62,279,000 +$ +112,853,000 +$ +63,634,000 +(1) Net of $(4,301,000) , $0 , and $0 in taxes for the years ended December 31, 2012, 2011 and 2010, respectively. +(2) Net of $512,000 , $0 , and $0 in taxes for the years ended December 31, 2012, 2011 and 2010, respectively. +See accompanying notes to consolidated financial statements. +F -6 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY +(Amounts rounded to nearest thousand) +Additional +Paid-in +Capital +Accumulated +Other +Comprehensive +Income(Loss) +Retained +Earnings +(Accumulated +Deficit) +Total +Stockholders’ +Equity +Common Stock +Shares +Amount +Balance at January 1, 2010 +42,696,409 +$ +427,000 +$ +273,901,000 +$ +(18,039,000 +) +$ +(131,238,000 +) +$ +125,051,000 +Net income +— +— +— +— +47,363,000 +47,363,000 +Other Comprehensive Income +— +— +— +16,271,000 +— +16,271,000 +Stock Compensation +— +— +492,000 +— +— +492,000 +Issuance of Common Stock in public offering, net of related expenses +1,668,503 +17,000 +21,341,000 +— +— +21,358,000 +Issuance of Common Stock through exercise of warrants +173,109 +2,000 +204,000 +— +— +206,000 +Issuance of Restricted Stock +58,525 +— +— +— +— +— +Issuance of Common Stock through exercise of options +48,889 +— +315,000 +— +— +315,000 +Balance at December 31, 2010 +44,645,435 +446,000 +296,253,000 +(1,768,000 +) +(83,875,000 +) +211,056,000 +Net income +— +— +— +— +108,422,000 +108,422,000 +Other Comprehensive Income +— +— +— +4,431,000 +— +4,431,000 +Stock Compensation +— +— +1,287,000 +— +— +1,287,000 +Issuance of Common Stock in public offering, net of related expenses +10,810,000 +108,000 +306,053,000 +— +— +306,161,000 +Issuance of Common Stock through exercise of warrants +566 +— +— +— +— +— +Issuance of Restricted Stock +63,370 +1,000 +(1,000 +) +— +— +— +Issuance of Common Stock through exercise of options +102,000 +1,000 +992,000 +— +— +993,000 +Balance at December 31, 2011 +55,621,371 +556,000 +604,584,000 +2,663,000 +24,547,000 +632,350,000 +Net income +— +— +— +— +68,371,000 +68,371,000 +Other Comprehensive Loss +— +— +— +(6,092,000 +) +— +(6,092,000 +) +Stock Compensation +— +— +4,688,000 +— +— +4,688,000 +Issuance of Common Stock in public offering, net of related expenses +11,750,000 +118,000 +426,789,000 +— +— +426,907,000 +Issuance of Restricted Stock +135,015 +— +— +— +— +— +Issuance of Common Stock through exercise of options +21,000 +— +184,000 +— +— +184,000 +Balance at December 31, 2012 +67,527,386 +$ +674,000 +$ +1,036,245,000 +$ +(3,429,000 +) +$ +92,918,000 +$ +1,126,408,000 +See accompanying notes to consolidated financial statements. +F -7 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +(Amounts rounded to nearest thousand) +Year Ended December 31, +2012 +2011 +2010 +Cash flows from operating activities: +Net income +$ +68,371,000 +$ +108,422,000 +$ +47,363,000 +Adjustments to reconcile net income to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +698,000 +666,000 +617,000 +Depletion, depreciation and amortization +90,749,000 +62,320,000 +38,907,000 +Stock-based compensation expense +2,813,000 +772,000 +295,000 +(Gain) loss from equity investments +(8,322,000 +) +1,418,000 +977,000 +Interest income—note receivable +(2,000 +) +(147,000 +) +(267,000 +) +Unrealized loss (gain) on derivative instruments +144,000 +(25,000 +) +— +Deferred income tax expense (benefit) +24,120,000 +(372,000 +) +(95,000 +) +Amortization of loan commitment fees +640,000 +540,000 +— +Amortization of note discount and premium +59,000 +— +— +Write off of loan commitment fees +1,143,000 +— +— +Loss on disposal of assets +5,702,000 +— +— +Gain on sale of assets +(7,300,000 +) +— +— +Changes in operating assets and liabilities: +Decrease (increase) in accounts receivable +2,404,000 +(13,067,000 +) +(5,460,000 +) +Increase in accounts receivable—related party +(30,117,000 +) +(4,158,000 +) +(437,000 +) +(Increase) decrease in prepaid expenses +(179,000 +) +405,000 +315,000 +Increase in other assets +— +— +(75,000 +) +Increase in accounts payable and accrued liabilities +50,506,000 +1,612,000 +4,948,000 +Settlement of asset retirement obligation +(2,271,000 +) +(248,000 +) +(1,253,000 +) +Net cash provided by operating activities +199,158,000 +158,138,000 +85,835,000 +Cash flows from investing activities: +Deductions to cash held in escrow +8,000 +8,000 +8,000 +Additions to other property, plant and equipment +(638,000 +) +(415,000 +) +(427,000 +) +Additions to oil and gas properties +(757,192,000 +) +(287,292,000 +) +(101,644,000 +) +Proceeds from sale of other property, plant and equipment +140,000 +— +— +Proceeds from sale of oil and gas properties +63,590,000 +1,384,000 +304,000 +Advances on note receivable to related party +— +(3,182,000 +) +(2,877,000 +) +Contributions to equity method investments +(147,307,000 +) +(34,621,000 +) +(1,244,000 +) +Distributions from equity method investments +820,000 +870,000 +565,000 +Net cash used in investing activities +(840,579,000 +) +(323,248,000 +) +(105,315,000 +) +Cash flows from financing activities: +Principal payments on borrowings +(158,639,000 +) +(97,634,000 +) +(52,711,000 +) +Borrowings on line of credit +158,500,000 +48,000,000 +52,200,000 +Proceeds from bond issuance +296,835,000 +— +— +Debt issuance costs and loan commitment fees +(9,175,000 +) +(981,000 +) +(1,144,000 +) +Proceeds from issuance of common stock, net of offering costs, and exercise of stock options +427,091,000 +307,154,000 +21,879,000 +Net cash provided by financing activities +714,612,000 +256,539,000 +20,224,000 +Net increase in cash and cash equivalents +73,191,000 +91,429,000 +744,000 +Cash and cash equivalents at beginning of period +93,897,000 +2,468,000 +1,724,000 +Cash and cash equivalents at end of period +$ +167,088,000 +$ +93,897,000 +$ +2,468,000 +Supplemental disclosure of cash flow information: +Interest payments +$ +1,461,000 +$ +991,000 +$ +1,949,000 +Income tax payments +$ +261,000 +$ +1,000 +$ +40,000 +Supplemental disclosure of non-cash transactions: +Capitalized stock based compensation +$ +1,875,000 +$ +515,000 +$ +197,000 +Asset retirement obligation capitalized +$ +2,195,000 +$ +1,390,000 +$ +1,328,000 +Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC +$ +1,355,000 +$ +(855,000 +) +$ +1,313,000 +Foreign currency translation gain (loss) on note receivable—related party +$ +— +$ +(1,085,000 +) +$ +942,000 +S ee accompanying notes to consolidated financial statements. +F -8 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2012 , 2011 AND 2010 +(Amounts rounded to nearest thousand) +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production company with its principal properties located in the Louisiana Gulf Coast, the Utica Shale in Eastern Ohio and in Western Colorado in the Niobrara Formation and has investments in companies operating in the Permian Basin in West Texas, Canada and Thailand. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC and Puma Resources, Inc. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its receivables are from two purchasers of the Company’s oil and gas. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2012 and December 31, 2011 . +Oil and Gas Properties +The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for 2012 , 2011 and 2010 , adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. +Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $ 626,295,000 and $ 138,623,000 at +F -9 +Table of Contents +Index to Financial Statements +December 31, 2012 and December 31, 2011 , respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. +The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years. +Foreign Currency +The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive income. +December 31, 2009 +$ +696,000 +December 31, 2010 +$ +2,952,000 +December 31, 2011 +$ +1,087,000 +December 31, 2012 +$ +2,442,000 +Net Income per Common Share +Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 12. +Income Taxes +Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. +The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1998 – 2012 U.S. federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2012 , the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative +F -10 +Table of Contents +Index to Financial Statements +expenses, respectively. For the year ended December 31, 2012 , there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements. +Revenue Recognition +Gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. At December 31, 2012 , the Company had a gas imbalance liability of approximately $354,000 . At December 31, 2011 , the Company had no imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month produced. +Investments—Equity Method +Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations. In accordance with FASB ASC 825 , "Financial Instruments ," the Company has elected the fair value option of accounting for its equity method investment in Diamondback Energy Inc.'s ("Diamondback") stock. At the end of each reporting period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by the Company and the resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations. +The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. There was no impairment of equity method investments at December 31, 2012 or 2011 . +Accounting for Stock-Based Compensation +The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, “ Compensation—Stock Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options and restricted stock, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for the options range between three to five years and have a maximum contractual term of ten years. The vesting periods for restricted shares range between three to five years with either quarterly or annual vesting installments. +Accounting for Derivative Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. +The Company estimates the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values reported in the consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to +F -11 +Table of Contents +Index to Financial Statements +compute depletion, depreciation, amortization and impairment of oil and gas properties. +Reclassification +Certain reclassifications have been made to prior period financial statements to conform to current period presentation. +Recent Accounting Pronouncements +In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 , "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," which requires additional information about amounts reclassified out of accumulated other comprehensive income by component. This ASU requires the presentation, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, a cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The requirements of this ASU are effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The Company will adopt the provisions of this ASU for reporting periods in 2013 and does not expect the adoption of this ASU to have a material effect on its consolidated financial statements. +In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides amendments to FASB ASC Topic 820, “Fair Value Measurements and Disclosure” (“FASB ASC 820”) . The purpose of the amendments in this update is to create common fair value measurement and disclosure requirements between GAAP and IFRS. The amendments change certain fair value measurement principles and enhance the disclosure requirements. The amendments to FASB ASC 820 were effective for interim and annual periods beginning after December 15, 2011. Adoption of this ASU for reporting periods in 2012 had no impact on the Company's financial position or results of operations. +In June 2011, the FASB issued ASU 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The amendments to FASB ASC 220 were effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The Company adopted this ASU for reporting periods in 2012 and reports the components of net income and the components of other comprehensive income in two separate but consecutive statements. Adoption of this ASU had no impact on the Company's financial position or results of operations. +2. +ACQUISITIONS +Beginning in February 2011, the Company entered into agreements to acquire certain leasehold interests located in the Utica Shale in Ohio. Certain of the agreements also grant the Company an exclusive right of first refusal for a period of six months on certain additional tracts leased by the seller. Affiliates of Gulfport initially participated with the Company on a 50/50 basis in the acquisition of all leases described above. On December 17, 2012, Gulfport entered into a definitive agreement to purchase approximately 30,000 net acres in the Utica Shale in Eastern Ohio for approximately $302.0 million . On December 19, 2012, the parties amended that agreement to provide for Gulfport's acquisition of approximately 7,000 additional net acres for approximately $70.0 million , resulting in a total purchase price of approximately $372.0 million , subject to certain adjustments. This transaction closed on December 24, 2012. At closing, approximately $53.9 million of the purchase price was placed in escrow pending completion of title review after the closing. The transaction, which increased Gulfport’s leasehold interests in the Utica Shale to approximately 137,000 gross ( 106,000 net) acres, excluded 14 existing wells, along with certain acreage surrounding each well. Gulfport will continue to serve as operator of its acreage in the Utica Shale. Gulfport funded this acquisition with a portion of the net proceeds from its common stock offering that closed on December 24, 2012. The Company received aggregate net proceeds (including the net proceeds from the partial exercise of the underwriters' over-allotment option) of approximately $427.9 million from this equity offering, as discussed below in Note 8. As of December 31, 2012, Gulfport has paid a total of $619.6 million for its Ohio acreage. +3. +ACCOUNTS RECEIVABLE—RELATED PARTIES +F -12 +Table of Contents +Index to Financial Statements +Included in the accompanying consolidated balance sheets for the years ended December 31, 2012 and 2011 , are amounts receivable from related parties of the Company. These receivables consist primarily of amounts billed by the Company to related parties as operator of such parties' Colorado and Ohio oil and gas properties. At December 31, 2012 and 2011 , these receivables totaled $34,848,000 and $4,731,000 , respectively. +The Company is a party to administrative service agreements with Stampede Farms LLC ("Stampede"), Everest Operations Management LLC ("Everest") and Tatex Thailand III, LLC ("Tatex III"), which agreements were each entered into effective March 1, 2008. Under these agreements, the Company’s services include professional and technical support and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements may be cancelled (1) by the Company with at least 60 days prior written notice, (2) by the counterparty at any time with at least 30 days prior written notice to the Company and (3) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. The Company did not provide services under any of these agreements in 2010, 2011 or 2012 and received no reimbursements thereunder. Each of Stampede, Everest and Tatex III is controlled by Wexford Capital LP ("Wexford"). Charles E. Davidson is the Chairman and Chief Investment Officer of Wexford and he beneficially owned approximately 13.3% and less than 1% of the Company’s outstanding common stock as of December 31, 2011 and September 28, 2012, respectively. +For the years ended December 31, 2011 and 2010 , the Company was reimbursed approximately $66,000 and $20,000 , respectively, by Orange Leaf Holdings, LLC, an affiliate of Gulfport, for office space which is included in other income (expense) in the consolidated statements of operations. +Effective July 1, 2008, the Company entered into an acquisition team agreement with Everest to identify and evaluate potential oil and gas properties in which the Company and Everest or its affiliates may wish to invest. Upon a successful closing of an acquisition or divestiture, the party identifying the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or divestiture consideration. The agreement may be terminated by either party upon 30 days notice. Affiliates of Everest were billed approximately $1,087,000 and $1,184,000 under this acquisition team agreement during the years ended December 31, 2012 and 2011 , respectively, which amounts are reflected as a reduction of general and administrative expenses in the consolidated statements of operations. No amounts were reimbursed under the acquisition team agreement for the year ended 2010 . +Effective April 1, 2010, the Company entered into an area of mutual interest agreement with Windsor Niobrara LLC (“Windsor Niobrara”), an entity controlled by Wexford, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, exploiting and producing oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50% /50% basis. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, Gulfport and Windsor Niobrara also entered into a development agreement, effective as of April 1, 2010, pursuant to which the Company and Windsor Niobrara agreed to jointly develop the contract area, and Gulfport agreed to act as the operator under the terms of a joint operating agreement. +4. +PROPERTY AND EQUIPMENT +The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2012 and 2011 are as follows: +December 31, +2012 +2011 +Oil and natural gas properties +$ +1,611,090,000 +$ +1,035,754,000 +Office furniture and fixtures +4,476,000 +3,692,000 +Building +3,926,000 +4,049,000 +Land +260,000 +283,000 +Total property and equipment +1,619,752,000 +1,043,778,000 +Accumulated depletion, depreciation, amortization and impairment +(665,884,000 +) +(575,142,000 +) +Property and equipment, net +$ +953,868,000 +$ +468,636,000 +No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, +F -13 +Table of Contents +Index to Financial Statements +2012 , 2011 and 2010 . +Included in oil and natural gas properties at December 31, 2012 and 2011 is the cumulative capitalization of $ 32,562,000 and $ 23,494,000 , respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $ 9,068,000 , $ 5,368,000 and $ 4,117,000 for the years ended December 31, 2012 , 2011 and 2010 , respectively. +The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2012 : +Costs Incurred in +2012 +2011 +2010 +Prior to 2010 +Total +Acquisition costs +$ +512,636,000 +$ +112,591,000 +$ +661,000 +$ +407,000 +$ +626,295,000 +Exploration costs +— +— +— +— +— +Development costs +— +— +— +— +— +Total oil and gas properties not subject to amortization +$ +512,636,000 +$ +112,591,000 +$ +661,000 +$ +407,000 +$ +626,295,000 +At December 31, 2012, approximately $ 295,000 of non-producing leasehold costs related to the Company’s Bakken properties and $ 5,998,000 of non-producing leasehold costs related to the Company’s Colorado properties are excluded from amortization. In addition, approximately $ 774,000 of non-producing leasehold costs related to the Company’s Southern Louisiana assets, $ 619,182,000 of non-producing leasehold costs related to the Company’s Ohio leasehold costs and $ 46,000 of non-producing leasehold costs related to other projects are also excluded from amortization. At December 31, 2011 , approximately $138,623,000 of non-producing leasehold costs was not subject to amortization. +During the year ended December 31, 2012, the Company determined that further development of its non-producing leasehold assets located in Belize was not in alignment with its current strategic operating plan and therefore recognized a loss on disposal of assets, net of tax, of approximately $3.5 million which is included in discontinued operations on the accompanying consolidated statements of operations for the year ended December 31, 2012 . +The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to occur within three to five years. +A reconciliation of the asset retirement obligation for the years ended December 31, 2012 and 2011 is as follows: +December 31, +2012 +2011 +Asset retirement obligation, beginning of period +$ +12,653,000 +$ +10,845,000 +Liabilities incurred +2,195,000 +1,390,000 +Liabilities settled +(2,271,000 +) +(248,000 +) +Accretion expense +698,000 +666,000 +Asset retirement obligation as of end of period +13,275,000 +12,653,000 +Less current portion +60,000 +620,000 +Asset retirement obligation, long-term +$ +13,215,000 +$ +12,033,000 +On May 7, 2012, the Company entered into a contribution agreement with Diamondback. Under the terms of the contribution agreement, the Company agreed to contribute to Diamondback, prior to the closing of the Diamondback initial public offering (“Diamondback IPO”), all its oil and gas interests in the Permian Basin (the "Contribution"). The Contribution was completed on October 11, 2012. At the closing of the Contribution, Diamondback issued to the Company (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $ 63.6 million , which was repaid to the Company at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash +F -14 +Table of Contents +Index to Financial Statements +adjustment based on changes in the working capital, long-term debt and certain other items of Diamondback O&G LLC, formerly Windsor Permian LLC ("Diamondback O&G"), as of the date of the Contribution. In January 2013, the Company received an additional payment from Diamondback of approximately $18.6 million as a result of this post-closing adjustment which is included in accounts receivable - related parties on the accompanying consolidated balance sheets. Diamondback O&G is a wholly-owned subsidiary of Diamondback. Under the contribution agreement, the Company is generally responsible for all liabilities and obligations with respect to the contributed properties arising prior to the Contribution and Diamondback is responsible for such liabilities and obligations with respect to the contributed properties arising after the Contribution. +In accordance with the Company's policy under the full cost method of accounting to only recognize a gain or loss upon the disposal of oil and natural gas properties if such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves, the Company recognized a gain on the sale of its Permian Basin assets of approximately $7.3 million , which is included in the accompanying consolidated statements of operations for the year ended December 31, 2012 . In addition, the Company recorded a reduction to its full cost pool of approximately $213.0 million as a result of the Contribution. +In connection with the Contribution, the Company and Diamondback entered into an investor rights agreement under which the Company has the right, for so long as it beneficially owns more than 10% of Diamondback’s outstanding common stock, to designate one individual as a nominee to serve on Diamondback’s board of directors. Such nominee, if elected to Diamondback’s board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as the Company has the right to designate a nominee to Diamondback’s board and there is no Gulfport nominee actually serving as a Diamondback director, the Company has the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. The Company is also entitled to certain information rights and Diamondback granted the Company certain demand and “piggyback” registration rights obligating Diamondback to register with the Securities and Exchange Commission (the "SEC") any +shares of Diamondback common stock that the Company owns. Immediately upon completion of the Contribution, the Company owned a 35% equity interest in Diamondback, rather than leasehold interests in the Company’s Permian Basin acreage. Upon completion of the Diamondback IPO on October 17, 2012, Gulfport owned approximately 22.5% of Diamondback's outstanding common stock. On October 18, 2012, the underwriters of the Diamondback IPO exercised in full their option to purchase additional shares of common stock of Diamondback and, upon the closing of such purchase on October 23, 2012, Gulfport owned approximately 21.4% of Diamondback's outstanding common stock. Following the Contribution, the Company accounts for its interest in Diamondback as an equity investment. +5. +EQUITY INVESTMENTS +Investments accounted for by the equity method consist of the following as of December 31, 2012 and 2011 : +December 31, +2012 +2011 +Investment in Tatex Thailand II, LLC +$ +203,000 +$ +1,030,000 +Investment in Tatex Thailand III, LLC +8,657,000 +8,282,000 +Investment in Grizzly Oil Sands ULC +172,766,000 +69,008,000 +Investment in Bison Drilling and Field Services LLC +13,518,000 +6,366,000 +Investment in Muskie Holdings LLC +7,320,000 +2,138,000 +Investment in Timber Wolf Terminals LLC +878,000 +— +Investment in Windsor Midstream LLC +9,503,000 +— +Investment in Stingray Pressure Pumping LLC +13,265,000 +— +Investment in Stingray Cementing LLC +3,110,000 +— +Investment in Blackhawk Midstream LLC +— +— +Investment in Stingray Logistics LLC +947,000 +— +Investment in Diamondback Energy LLC +151,317,000 +— +$ +381,484,000 +$ +86,824,000 +Tatex Thailand II, LLC +F -15 +Table of Contents +Index to Financial Statements +The Company has a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”). The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. During the year ended December 31, 2012 , Gulfport received $820,000 in distributions, reducing its total net investment in Tatex to $203,000 . The loss on equity investment related to Tatex was immaterial for the years ended December 31, 2012 , 2011 and 2010 . +Tatex Thailand III, LLC +The Company has a 17.9% ownership interest in Tatex Thailand III, LLC (“Tatex III”). Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2012 , Gulfport paid $ 626,000 in cash calls, increasing its total net investment in Tatex III to $ 8,657,000 . The Company recognized a loss on equity investment of $ 251,000 , $ 172,000 and $ 224,000 for the years ended December 31, 2012 , 2011 and 2010 , respectively, which is included in (income) loss from equity method investments in the consolidated statements of operations. +Grizzly Oil Sands ULC +The Company, through its wholly owned subsidiary Grizzly Holdings Inc. ("Grizzly Holdings"), owns a 24.9999% interest in Grizzly Oil Sands ULC, ("Grizzly") a Canadian unlimited liability company. The remaining interest in Grizzly is owned by an entity controlled by Wexford. Since 2006 , Grizzly has acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has drilled core holes and water supply test wells in ten separate lease blocks for feasibility of oil production and conducted a seismic program. In March 2010 , Grizzly filed an application in Alberta, Canada for the development of a steam-assisted gravity drainage ("SAGD") facility at Algar Lake. In November 2011 , the Government of Alberta provided a formal Order in Council authorizing the Alberta Energy Resources Conservation Board (ERCB) to issue formal regulatory approval of the project. During 2012, Grizzly finished SAGD well pair drilling at Algar Lake and began the process of completing those well pairs for SAGD injection and production and continued the fabrication and onsite construction of the Algar Lake facility. In the first quarter of 2012, Grizzly completed the acquisition of approximately 47,000 acres through the purchase of its May River property and has prepared a full field development plan under which the May River property will be developed in multiple phases. In 2012, Grizzly submitted a SAGD project regulatory application for the development of a project at Thickwood Hills. During the year ended December 31, 2012 , Gulfport paid $ 103,915,000 in cash calls and recorded a currency translation gain of $ 1,355,000 , increasing its total net investment in Grizzly to $ 172,766,000 at December 31, 2012. Grizzly’s functional currency is the Canadian dollar. The Company recognized a loss on equity investment of $ 1,512,000 , $ 1,592,000 and $ 740,000 for the years ended December 31, 2012 , 2011 and 2010 , respectively, which is included in (income) loss from equity method investments in the consolidated statements of operations. +The Company, through its wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008 , under which Grizzly borrowed funds from the Company. Borrowed funds initially bore interest at LIBOR plus 400 basis points and had an original maturity date of December 31, 2012 . Effective April 1, 2010 , the loan agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011 . Effective October 15, 2010 , the loan agreement was further amended to change the maturity date to December 31, 2012 . Interest was paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The Company loaned Grizzly approximately $ 3,182,000 during the year ended December 31, 2011 . The Company recognized interest income of approximately $ 147,000 and $ 267,000 for the years ended December 31, 2011 and 2010 , which is included in interest income in the consolidated statements of operations. Effective December 7, 2011 , Grizzly Holdings Inc., entered into a debt settlement agreement with Grizzly under which Grizzly agreed to satisfy the entire outstanding debt by issuing additional common shares of Grizzly with no effect to the composition of ownership structure of Grizzly. At such date, the Company’s investment in Grizzly increased by the total $ 22,325,000 outstanding advances and accrued interest due from Grizzly, the cumulative $ 75,000 currency translation loss for the note receivable was adjusted through accumulated other comprehensive income and the note receivable was considered paid in full. +The tables below summarize financial information for Grizzly as of December 31, 2012 , 2011 and 2010 : +Summarized balance sheet information: +F -16 +Table of Contents +Index to Financial Statements +December 31, +2012 +2011 +Current assets +$ +30,098,000 +$ +21,247,000 +Noncurrent assets +$ +720,550,000 +$ +284,361,000 +Current liabilities +$ +42,547,000 +$ +25,984,000 +Noncurrent liabilities +$ +14,515,000 +$ +1,780,000 +Summarized results of operations: +December 31, +2012 +2011 +2010 +Gross revenue +$ +— +$ +— +$ +— +Net loss +$ +6,050,000 +$ +6,605,000 +$ +3,234,000 +Bison Drilling and Field Services LLC +During the third quarter of 2011 , the Company purchased a 25% ownership interest in Bison Drilling and Field Services LLC (“Bison”) at a cost of $ 6,009,000 , subject to adjustment. In April 2012, the Company purchased an additional 15% ownership interest in Bison for $6,152,000 , bringing its total ownership interest in Bison to 40% . The remaining interests in Bison are owned by entities controlled by Wexford. Bison owns and operates drilling rigs. During the year ended December 31, 2012, Gulfport paid $ 1,373,000 in cash calls, increasing its total net investment in Bison to $ 13,518,000 . The Company recognized a loss on its equity investment in Bison of $ 373,000 for the year ended December 31, 2012 , and income of $ 357,000 for the year ended December 31, 2011 , which amounts are included in (income) loss from equity method investments in the consolidated statements of operations. +The Company entered into a loan agreement with Bison effective May 15, 2012, under which Bison may borrow funds from the Company. Interest accrues at LIBOR plus 0.28% or 8% , whichever is lower, and shall be paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan has a maturity date of January 31, 2015. The Company loaned Bison $1,594,000 during the first nine months of 2012, all of which was repaid by Bison during the third quarter of 2012. The interest income recognized on the note was immaterial for the year ended December 31, 2012 . +Muskie Holdings LLC +During the fourth quarter of 2011 , the Company purchased a 25% ownership interest in Muskie Holdings LLC (“Muskie”) at a cost of $ 2,142,000 , subject to adjustment. The remaining interests in Muskie are owned by entities controlled by Wexford. Muskie holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. During the year ended December 31, 2012 , Gulfport paid $ 6,213,000 in cash calls, increasing its total net investment in Muskie to $ 7,320,000 . The Company recognized a loss on equity investment of $ 1,031,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. The loss on equity investment related to Muskie was immaterial for the year ended December 31, 2011 . +Timber Wolf Terminals LLC +During the first quarter of 2012, the Company purchased a 50% ownership interest in Timber Wolf Terminals LLC (“Timber Wolf”) at a cost of $ 1,000,000 . The remaining interests in Timber Wolf are owned by entities controlled by Wexford. Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. The Company recognized a loss on equity investment of $ 122,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. +Windsor Midstream LLC +During the first quarter of 2012, the Company purchased a 22.5% ownership interest in Windsor Midstream LLC (“Midstream”) at a cost of $7,021,000 . The remaining interests in Midstream are owned by entities controlled by Wexford. Midstream owns a 28.4% interest in MidMar Gas LLC, a gas processing plant in West Texas. During the year ended +F -17 +Table of Contents +Index to Financial Statements +December 31, 2012 , the Company paid $ 1,819,000 in cash calls, increasing its total net investment in Midstream to $ 9,503,000 . The Company recognized income on equity investment of $ 663,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. +Stingray Pressure Pumping LLC +During the second quarter of 2012, the Company purchased a 50% ownership interest in Stingray Pressure Pumping LLC ("Stingray Pressure"). The remaining interests in Stingray Pressure are owned by entities affiliated with Wexford. Stingray Pressure provides well completion services. During the year ended December 31, 2012 , the Company paid $ 14,500,000 in cash calls, increasing its total net investment in Stingray Pressure to $13,265,000 . The Company recognized a loss on equity investment of $ 1,235,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. +Stingray Cementing LLC +During the second quarter of 2012, the Company purchased a 50% ownership interest in Stingray Cementing LLC ("Stingray Cementing"). The remaining interests in Stingray Cementing are owned by entities affiliated with Wexford. Stingray Cementing provides well cementing services. During the year ended December 31, 2012 , the Company paid $ 3,269,000 in cash calls, increasing its net investment in Stingray Cementing to $ 3,110,000 . The Company recognized a loss on equity investment of $ 159,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. +Blackhawk Midstream LLC +During the second quarter of 2012, the Company purchased a 50% ownership interest in Blackhawk Midstream LLC ("Blackhawk"). The remaining interest in Blackhawk is owned by an entity controlled by Wexford. Blackhawk coordinates gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. During the year ended December 31, 2012 , the Company paid $ 436,000 in cash calls. The Company recognized a loss on equity investment of $ 436,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. +Stingray Logistics LLC +During the fourth quarter of 2012, the Company purchased a 50% ownership interest in Stingray Logistics LLC ("Stingray Logistics"). The remaining interests in Stingray Logistics are owned by entities affiliated with Wexford. Stingray Logistics provides well services. During the year ended December 31, 2012 , the Company paid $ 983,000 in cash calls. The Company recognized a loss on equity investment of $ 36,000 for the year ended December 31, 2012, which is included in (income) loss from equity method investments in the consolidated statements of operations. +Diamondback Energy, Inc. +As noted above in Note 4, on May 7, 2012, the Company entered into a contribution agreement with Diamondback. Under the terms of the contribution agreement, the Company agreed to contribute to Diamondback, prior to the closing of the Diamondback IPO, all its oil and gas interests in the Permian Basin. The Contribution was completed on October 11, 2012. At the closing of the Contribution, Diamondback issued to the Company (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million , which was repaid to the Company at the closing of the Diamondback IPO on October 17, 2012. Following the closing of the Diamondback IPO, the Company owned approximately 21.4% of Diamondback's outstanding common stock for an initial investment in Diamondback of $ 138,496,000 . The Company accounts for its interest in Diamondback as an equity method investment and has elected the fair value option of accounting and valued its investment in Diamondback using the quoted closing market price of Diamondback's stock on December 31, 2012 of $19.12 per share multiplied by the Company's number of outstanding shares of Diamondback's stock. The Company's investment in Diamondback totaled $151,317,000 at December 31, 2012 . The Company recognized a gain on equity investment of $ 12,821,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. +The tables below summarize financial information for Diamondback as of December 31, 2012 , 2011 and 2010 : +Summarized balance sheet information: +F -18 +Table of Contents +Index to Financial Statements +December 31, +2012 +2011 +Current assets +$ +50,275,000 +$ +30,812,000 +Noncurrent assets +$ +556,426,000 +$ +232,766,000 +Current liabilities +$ +79,232,000 +$ +42,298,000 +Noncurrent liabilities +$ +65,401,000 +$ +92,243,000 +Summarized results of operations: +December 31, +2012 +2011 +2010 +Gross revenue +$ +74,962,000 +$ +49,366,000 +$ +27,253,000 +Income from operations +$ +17,307,000 +$ +15,147,000 +$ +9,181,000 +Net income (loss) +$ +(36,521,000 +) +$ +(386,000 +) +$ +8,231,000 +6. +OTHER ASSETS +Other assets consist of the following as of December 31, 2012 and 2011 : +December 31, +2012 +2011 +Plugging and abandonment escrow account on the WCBB properties (Note 16) +$ +3,113,000 +$ +3,121,000 +Certificates of Deposit securing letter of credit +275,000 +275,000 +Prepaid drilling costs +515,000 +228,000 +Loan commitment fees +9,388,000 +1,495,000 +Deposits +4,000 +4,000 +$ +13,295,000 +$ +5,123,000 +7. +LONG-TERM DEBT +A break-down of long-term debt as of December 31, 2012 and 2011 is as follows: +December 31, +2012 +2011 +Revolving credit agreement (1) +$ +— +$ +— +Building loans (2) +2,143,000 +2,283,000 +7.75% senior unsecured notes due 2020 (3) +300,000,000 +— +Unamortized original issue (discount) premium, net (4) +(3,105,000 +) +— +Less: current maturities of long term debt +(150,000 +) +(141,000 +) +Debt reflected as long term +$ +298,888,000 +$ +2,142,000 +Maturities of long-term debt (excluding premiums and discounts) as of December 31, 2012 are as follows: +F -19 +Table of Contents +Index to Financial Statements +2013 +$ +150,000 +2014 +158,000 +2015 +168,000 +2016 +1,667,000 +2017 +— +Thereafter +300,000,000 +Total +$ +302,143,000 +(1) On September 30, 2010, the Company entered into a $100 million senior secured revolving credit agreement with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association ("Amegy Bank"). The revolving credit facility initially matured on September 30, 2013 and had an initial borrowing base availability of $50.0 million , which was increased to $65.0 million effective December 24, 2010. The amounts borrowed under the credit agreement were used to repay all of the Company’s outstanding indebtedness under its prior revolving credit facility ( $42.0 million ) and term loan ( $2.5 million ), each with Bank of America, N.A., as administrative agent, and for general corporate purposes. The credit agreement is secured by substantially all of the Company’s assets. The Company’s wholly-owned subsidiaries guaranteed the obligations of the Company under the credit agreement. +On May 3, 2011, the Company entered into a first amendment to the revolving credit agreement with The Bank of Nova Scotia, Amegy Bank, KeyBank National Association (“KeyBank”) and Société Générale. Pursuant to the terms of the first amendment, KeyBank and Société Générale were added as additional lenders, the maximum amount of the facility was increased to $350.0 million , the borrowing base was increased to $90.0 million , certain fees and rates payable by the Company under the credit agreement were decreased, and the maturity date was extended until May 3, 2015. On October 31, 2011, the Company entered into additional amendments to its revolving credit facility pursuant to which, among other things, the borrowing base under this facility was increased to $125.0 million . +Effective May 2, 2012, the Company entered into a fourth amendment to its revolving credit facility under which, among other things, the borrowing base was increased to $155.0 million and Credit Suisse, Deutsche Bank Trust Company Americas and Iberiabank were added as additional lenders and Société Générale left the bank group. +On October 9, 2012, and October 17, 2012, the Company entered into a fifth amendment and a sixth amendment, respectively, to the revolving credit agreement. The fifth amendment modified certain covenants in the credit agreement to permit the Company to issue senior unsecured notes in an aggregate principal amount of up to $300.0 million and provided for a reduction in the borrowing base to an amount to be determined upon the completion of any senior unsecured notes issuance. The sixth amendment lowered the applicable rate set forth in the credit agreement (i) from a range of 1.00% to 1.75% to a range of 0.75% to 1.50% for the base rate loans and (ii) from a range of 2.00% to 2.75% to a range of 1.75% to 2.50% for the Eurodollar rate loans and letters of credit. The sixth amendment lowered the commitment fees for Level 1 and Level 2 usage levels, in each case, from 0.50% per annum to 0.375% per annum. Also, effective as of October 17, 2012, in connection with the Company's completion of the offering of $250.0 million 7.750% senior unsecured notes due 2020, (the "October Notes"), the repayment of all outstanding amounts under the revolving credit agreement with the proceeds of the October Notes, and the contribution of Gulfport’s oil and natural gas interests in the Permian Basin to Diamondback discussed in Note 4 above, Gulfport’s borrowing base under the credit agreement was reduced to $45.0 million until the next borrowing base redetermination. In conjunction with the lowering of the borrowing base in October 2012, the Company expensed a proportional amount of the unamortized loan fees associated with the revolving credit facility totaling approximately $1,088,000 , which is included in interest expense on the accompanying consolidated statements of operations. +On December 18, 2012, the Company entered into a seventh amendment to the revolving credit agreement under which the Company was permitted to issue $50.0 million 7.750% senior unsecured notes due 2020, (the "December Notes") under the same indenture as the October Notes, (collectively, the "Notes") and upon the issuance of the December Notes, the borrowing base under the revolving credit agreement was reduced from $45.0 million to $40.0 million until the next borrowing base redetermination. As of December 31, 2012 , the Company had no balance outstanding under the revolving credit agreement. In conjunction with the lowering of the borrowing base in December 2012, the Company expensed a proportional amount of unamortized loan fees associated with the revolving credit facility totaling approximately $55,000 , which is included in interest expense on the accompanying consolidated statements of operations. +Advances under the credit agreement, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.75% to 1.50% , plus (2) the highest of: +F -20 +Table of Contents +Index to Financial Statements +(a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.75% to 2.50% , plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At October 17, 2012 (the latest date during the year ended December 31, 2012 on which the Company had borrowings outstanding), amounts borrowed under the revolving credit agreement bore interest at the Eurodollar rate ( 2.97% ). +The credit agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: +• incur indebtedness; grant liens; +• pay dividends and make other restricted payments; +• make investments; +• make fundamental changes; +• enter into swap contracts and forward sales contracts; +• dispose of assets; +• change the nature of their business; and +• enter into transactions with their affiliates. +The negative covenants are subject to certain exceptions as specified in the credit agreement. The credit agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: +(i) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offering, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00 ; and +(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00 . The Company was in compliance with all covenants at December 31, 2012 . +(2) In March 2011, the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matures in February 2016 and bears interest at the rate of 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. +(3) On October 17, 2012, the Company issued the $250.0 million October Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, (the "October Notes Offering") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of December Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, ("the December Notes Offering"). The December Notes were issued as additional securities under the senior note indenture. The October Notes Offering and the December Notes Offering are collectively referred to as the "Notes Offerings". The Company used a portion of the net proceeds from the October Notes Offering to repay all amounts outstanding at such time under its revolving credit +F -21 +Table of Contents +Index to Financial Statements +facility. The Company intends to use the remaining net proceeds of October Notes Offering and the net proceeds of the December Notes Offering for general corporate purposes, which may include funding a portion of its 2013 capital development plan. +Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the Notes; provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, the Company may redeem the Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Notes initially issued remains outstanding immediately after such redemption. +(4) The October Notes were issued at a price of 98.534% resulting in a gross discount of $3,665,000 and an effective rate of 8.000% . The December Notes were issued at a price of 101.000% resulting in a gross premium of $500,000 and an effective rate of 7.531% . The premium and discount are being amortized using the effective interest method. +Interest Expense +The following schedule shows the components of interest expense at December 31, 2012 and 2011 : +December 31, +2012 +2011 +Cash paid for interest +$ +1,404,000 +$ +963,000 +Change in accrued interest +4,155,000 +(132,000 +) +Write-off of deferred loan costs +1,143,000 +— +Amortization of loan costs +640,000 +540,000 +Amortization of note discount and premium +59,000 +— +Other +57,000 +29,000 +Total interest expense +$ +7,458,000 +$ +1,400,000 +8. +COMMON STOCK OPTIONS, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is administered by the Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are defined as all directors of the Company, all officers of the Company and all key employees of the Company with a customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted under the Plan, as adjusted for changes in capitalization which have taken place since the Plan’s adoption, was 883,000 . The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, 2012 . No additional securities will be issued under the Plan other than upon exercise of options that are outstanding. +The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) Incentive Stock Options, +F -22 +Table of Contents +Index to Financial Statements +(b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights and (ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 2012 , the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. The shares of stock issued once the options are exercised will be from authorized but unissued common stock. +Sale of Common Stock +On May 19, 2010, the Company sold 1,481,481 shares of its common stock in an underwritten public offering at a public offering price of $13.50 per share less the underwriting discount. On May 25, 2010, the Company sold an additional 187,022 shares of common stock at the public offering price less the underwriting discount in connection with the underwriters’ partial exercise of the over-allotment option granted to them by the Company. The Company received the aggregate net proceeds of approximately $21.6 million from the sale of these shares after deducting the underwriting discount and before offering expenses. A portion of the net proceeds from the offering was used to fund the Company’s Niobrara Formation and Permian Basin acquisitions. The remaining net proceeds from this offering were used for general corporate purposes, including expenditures associated with the Company’s 2010 drilling programs. +On March 30, 2011, the Company completed the sale of an aggregate of 2,760,000 shares of its common stock in an underwritten public offering at a public offering price of $32.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $84.3 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. +On July 15, 2011, the Company completed the sale of an aggregate of 3,450,000 shares of its common stock in an underwritten public offering at a public offering price of $28.75 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $94.7 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. +On December 5, 2011, the Company completed the sale of an aggregate of 4,600,000 shares of its common stock in an underwritten public offering at a public offering price of $29.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $128.0 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the proceeds to fund capital expenditures associated with drilling, development and infrastructure, principally in the Utica Shale in Ohio and for general corporate purposes. +On December 24, 2012, the Company completed the sale of an aggregate of 11,750,000 shares of its common stock in an underwritten public offering (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares) at a public offering price of $38.00 per share less the underwriting discount. The Company received aggregate net proceeds (including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) of approximately $427.9 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds in part to fund the acquisition of additional Utica Shale acreage as discussed in Note 2. +Private Placement Offering +In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred Stock, Series A, of the Company (the “Preferred”) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per share, of the Company (the “Warrants”). Holders of the Preferred were entitled to receive dividends at the rate of 12% of the liquidation preference per annum payable quarterly in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of Preferred at the rate of 15% of the liquidation preference per annum. All Preferred shares were redeemed in 2005. +The 2,322,962 Warrants issued had a term of 10 years and a current exercise price of $1.19 per share of common stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the Warrants. The 8,875 unexercised warrants expired on March +F -23 +Table of Contents +Index to Financial Statements +31, 2012. +9. +STOCK-BASED COMPENSATION +During the years ended December 31, 2012 , 2011 and 2010 , the Company’s stock-based compensation cost was $ 4,688,000 , $ 1,287,000 and $ 492,000 , respectively, of which the Company capitalized $ 1,875,000 , $ 515,000 and $ 197,000 , respectively, relating to its exploration and development efforts. +The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon the historical experience of the Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant. +No stock options were issued during the years ended December 31, 2012 , 2011 and 2010 . +The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. +A summary of the status of stock options and related activity for the years ended December 31, 2012 , 2011 and 2010 are presented below: +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value +Options outstanding at December 31, 2009 +508,630 +$ +7.14 +5.38 +$ +2,192,000 +Granted +— +— +Exercised +(48,889 +) +6.46 +545,000 +Forfeited/expired +(1,500 +) +2.00 +Options outstanding at December 31, 2010 +458,241 +7.23 +4.48 +$ +6,621,000 +Granted +— +— +Exercised +(102,000 +) +9.74 +2,308,000 +Forfeited/expired +— +— +Options outstanding at December 31, 2011 +356,241 +6.51 +3.41 +$ +8,172,000 +Granted +— +— +Exercised +(21,000 +) +8.80 +628,000 +Forfeited/expired +— +— +Options outstanding at December 31, 2012 +335,241 +$ +6.37 +2.39 +$ +10,678,000 +Options exercisable at December 31, 2012 +335,241 +$ +6.37 +2.39 +$ +10,678,000 +Unrecognized compensation expense as of December 31, 2012 related to outstanding stock options and restricted shares was $ 6,745,000 . The expense is expected to be recognized over a weighted average period of 1.55 years. +The following table summarizes information about the stock options outstanding at December 31, 2012 : +F -24 +Table of Contents +Index to Financial Statements +Exercise +Price +Number +Outstanding +Weighted Average +Remaining Life +(in years) +Number +Exercisable +$ +3.36 +205,241 +2.06 +205,241 +$ +9.07 +5,000 +2.69 +5,000 +$ +11.20 +125,000 +2.92 +125,000 +335,241 +335,241 +The following table summarizes restricted stock activity for the twelve months ended December 31, 2012 , 2011 and 2010 : +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2009 +60,244 +$ +6.01 +Granted +111,667 +12.94 +Vested +(58,525 +) +8.17 +Forfeited +— +— +Unvested shares as of December 31, 2010 +113,386 +$ +11.72 +Granted +153,332 +$ +31.15 +Vested +(63,370 +) +12.87 +Forfeited +— +— +Unvested shares as of December 31, 2011 +203,348 +$ +26.02 +Granted +196,832 +$ +35.87 +Vested +(135,015 +) +29.59 +Forfeited +(19,334 +) +26.81 +Unvested shares as of December 31, 2012 +245,831 +$ +31.88 +10. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current and long-term debt related to the building loans are carried at cost, which approximates market value. +At December 31, 2012 the carrying value of the outstanding debt represented by the Notes was $ 296,895,000 , including the remaining unamortized discount of approximately $ 3,595,000 related to the October Notes and the remaining unamortized premium of approximately $ 490,000 related to the December Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $ 308,250,000 at December 31, 2012 . +The fair value of the derivative instruments is computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and are subject to significant volatility. +11. +INCOME TAXES +The income tax provision for continuing operations consists of the following: +F -25 +Table of Contents +Index to Financial Statements +2012 +2011 +2010 +Current: +State +$ +84,000 +$ +— +$ +40,000 +Federal +646,000 +282,000 +95,000 +Deferred: +State +2,214,000 +— +— +Federal +23,419,000 +(372,000 +) +(95,000 +) +Total income tax expense (benefit) provision from continuing operations +$ +26,363,000 +$ +(90,000 +) +$ +40,000 +A reconciliation of the statutory federal income tax amount to the recorded expense follows: +2012 +2011 +2010 +Income from continuing operations before federal income taxes +$ +98,199,000 +$ +108,332,000 +$ +47,403,000 +Expected income tax at statutory rate +34,370,000 +37,916,000 +16,591,000 +State income taxes +1,493,000 +4,227,000 +2,378,000 +Other differences +292,000 +(146,000 +) +(111,000 +) +Changes in valuation allowance +(9,792,000 +) +(42,087,000 +) +(18,818,000 +) +Income tax expense (benefit) recorded for continuing operations +$ +26,363,000 +$ +(90,000 +) +$ +40,000 +The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2012 , 2011 and 2010 are estimated as follows: +2012 +2011 +2010 +Deferred tax assets: +Net operating loss carryforward +$ +1,513,000 +$ +40,880,000 +$ +20,967,000 +Oil and gas property basis difference +— +— +32,054,000 +FASB ASC 718 compensation expense +762,000 +520,000 +347,000 +Investment in pass through entities +— +78,000 +722,000 +AMT credit +1,643,000 +1,000,000 +693,000 +Non-oil and gas property basis difference +— +103,000 +279,000 +Charitable contributions carryover +5,000 +3,000 +— +Unrealized gain on hedging activities +3,836,000 +— +— +Foreign tax credit carryforwards +2,074,000 +— +— +State net operating loss carryover +4,315,000 +6,410,000 +— +Total deferred tax assets +14,148,000 +48,994,000 +55,062,000 +Valuation allowance for deferred tax assets +(4,629,000 +) +(12,347,000 +) +(54,434,000 +) +Deferred tax assets, net of valuation allowance +9,519,000 +36,647,000 +628,000 +Deferred tax liabilities: +Oil and gas property basis difference +15,049,000 +35,637,000 +— +Investment in pass through entities +3,618,000 +— +— +Non-oil and gas property basis difference +227,000 +— +— +Investment in nonconsolidated affiliates +9,232,000 +— +— +Unrealized gain on hedging activities +— +10,000 +— +Total deferred tax liabilities +28,126,000 +35,647,000 +— +Net deferred tax asset (liability) +$ +(18,607,000 +) +$ +1,000,000 +$ +628,000 +The Company has an available federal tax net operating loss carryforward estimated at approximately $ 4,323,000 as of +F -26 +Table of Contents +Index to Financial Statements +December 31, 2012 . This carryforward will begin to expire in the year 2018. Based upon the December 31, 2012 net deferred tax liability position of the Company's oil and gas assets, management believes that this is a positive source of evidence to utilize the carryforward before it expires. Therefore, a valuation allowance has not been provided at December 31, 2012 . A valuation allowance has been provided at December 31, 2011 and 2010 because it was management’s belief in those years, based upon the Company’s past history of no taxable income and future projections of no taxable income during the carryforward period, it was more likely than not that the net deferred tax assets would not be realized. The Company also has state net operating loss carryovers of $84,031,000 from Oklahoma and Louisiana that will begin to expire in 2013, alternative minimum tax credits of $1,643,000 with no expiration date and federal foreign tax credit carryovers of $2,074,000 which begin to expire in 2017. The Company has recorded a valuation allowance of $4,629,000 related to state net operating loss carryovers and foreign tax credit carryovers as the carryovers may not be utilized based upon a more likely than not basis. +In 2012, the Diamondback Contribution generated an estimated $61.9 million taxable gain. As a result, the Company recognized $9,792,000 of its deferred tax assets which had previously been subject to a valuation allowance. The Company also recognized $25,633,000 of deferred tax expense in 2012 primarily due to the utilization of prior net operating losses from the Diamondback Contribution gain. Current federal expense in 2012, 2011 and 2010 is primarily attributable to alternative minimum tax. The Company also had income tax expense of $84,000 and $40,000 related to state income tax for the years ended December 31, 2012 and 2010 . +F -27 +Table of Contents +Index to Financial Statements +12. +EARNINGS PER SHARE +A reconciliation of the components of basic and diluted net income per common share is presented in the table below: +2012 +2011 +2010 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per +Share +Basic: +Net income +$ +68,371,000 +55,933,354 +$ +1.22 +$ +108,422,000 +48,754,840 +$ +2.22 +$ +47,363,000 +43,863,190 +$ +1.08 +Effect of dilutive securities: +Stock options and awards +— +484,134 +— +452,123 +— +392,902 +Diluted: +Net income +$ +68,371,000 +56,417,488 +$ +1.21 +$ +108,422,000 +49,206,963 +$ +2.20 +$ +47,363,000 +44,256,092 +$ +1.07 +There were no potential shares of common stock that were considered anti-dilutive for the years ended December 31, 2012 , 2011 and 2010 . +F -28 +Table of Contents +Index to Financial Statements +13. +HEDGING ACTIVITIES +Oil Price Hedging Activities +The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by entering into fixed price swaps and forward sales contracts. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. +The Company accounts for its oil derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related pronouncements. All derivative contracts are marked to market each quarter end and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. +During the fourth quarter of 2010 , the Company entered into fixed price swap contracts for 2011 with the purchaser of the Company’s WCBB oil and with a financial institution. The Company’s 2011 fixed price swap contracts were tied to the commodity prices on the New York Mercantile Exchange (“NYMEX”). The Company received the fixed price amount stated in the contract and paid to its counterparty the current market price for oil as listed on the NYMEX West Texas Index (“WTI”). During the third quarter of 2011 and in 2012, the Company entered into fixed price swap contracts for 2012 and 2013 with the purchaser of the Company’s oil and four financial institutions. The Company’s 2012 and 2013 fixed price swap contracts are tied to the commodity prices on the International Petroleum Exchange (“IPE”) and NYMEX. For the Company’s 2013 fixed price swap contracts, the Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price for oil as listed on the IPE for Brent Crude and the NYMEX WTI. At December 31, 2012 , the Company had the following fixed price swaps in place: +Daily Volume +(Bbls/day) +Weighted +Average Price +January - December 2013 +5,000 +$ +100.90 +At December 31, 2012 the fair value of derivative assets related to the fixed price swaps was as follows: +Short-term derivative instruments - asset +$ +664,000 +Short-term derivative instruments - liability +$ +10,442,000 +At December 31, 2011 , the fair value of derivative assets related to the fixed price swaps was as follows: +Short-term derivative instruments - asset +$ +1,601,000 +All fixed price swaps and forward sales contracts have been executed in connection with the Company’s oil price hedging program. For fixed price swaps qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract price is included in oil sales in the period for which the underlying production was hedged. +For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Amounts reclassified out of accumulated other comprehensive income into earnings as a component of oil and condensate sales for the years ended December 31, 2012 and 2011 are presented below. +Year ended December 31, +2012 +2011 +(Reduction) addition to oil and condensate sales +$ +(1,517,000 +) +$ +(4,720,000 +) +The Company expects to reclassify $9,660,000 out of accumulated other comprehensive income into earnings as a component of oil and condensate sales during the year ended December 31, 2013 related to fixed price swaps. +The following table presents the balances of the Company’s cumulative hedging activities included in other comprehensive income. +F -29 +Table of Contents +Index to Financial Statements +December 31, 2009 +$ +(18,736,000 +) +December 31, 2010 +$ +(4,720,000 +) +December 31, 2011 +$ +1,576,000 +December 31, 2012 +$ +(9,660,000 +) +Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company recognized a loss of $144,000 related to hedge ineffectiveness for the year ended December 31, 2012 , which is included in oil and condensate sales in the consolidated statements of operations. The Company recognized a gain of $25,000 related to hedge ineffectiveness for the year ended December 31, 2011 , which is included in oil and condensate sales in the consolidated statements of operations. The Company did not recognize into earnings any amount related to hedge ineffectiveness for the year ended December 31, 2010 . +For the period January 2010 through February 2010, the Company was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials. For the period March 2010 through December 2010, the Company was party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before transportation costs and differentials. For the period January 2011 through December 2011, the Company was party to fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel. For the period from January 2012 through February 2012, the Company was party to fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, the Company was party to fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, the Company was party to fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. +The Company delivered approximately 46% of its 2012 production under fixed price swaps. +14. +FAIR VALUE MEASUREMENTS +The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with FASB ASC 820. FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and disclosed in one of the following categories: +Level 1 – Quoted prices in active markets for identical assets and liabilities. +Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. +Level 3 – Significant inputs to the valuation model are unobservable. +Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. +The following tables summarize the Company’s financial and non-financial liabilities by FASB ASC 820 valuation level as of December 31, 2012 and 2011 : +F -30 +Table of Contents +Index to Financial Statements +December 31, 2012 +Level 1 +Level 2 +Level 3 +Assets: +Fixed price swaps +$ +— +$ +664,000 +$ +— +Equity investment in Diamondback +151,317,000 +— +— +Liabilities: +Fixed price swaps +$ +— +$ +10,442,000 +$ +— +December 31, 2011 +Level 1 +Level 2 +Level 3 +Assets: +Fixed price swaps +$ +— +$ +1,601,000 +$ +— +Liabilities: +Fixed price swaps +$ +— +$ +— +$ +— +The estimated fair value of the Company’s fixed price swap contracts was based upon forward commodity prices based on quoted market prices, adjusted for differentials. See Note 13 for further discussion of the Company's hedging activities. The estimated fair value of the Company's equity investment in Diamondback was based upon the public closing share price of Diamondback's common stock as of December 31, 2012 . +The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the twelve months ended December 31, 2012 were approximately $ 2,195,000 . +15. +RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business activities with certain related parties. +Diamondback operates the Permian Basin wells included in the Contribution as discussed above in Note 4. At December 2012 and 2011 , the Company owed Diamondback approximately $269,000 and $5,593,000 , respectively, related to reimbursement for services provided. Approximately $7,089,000 and $5,489,000 of services provided by Diamondback are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2012 and 2011 , respectively. Approximately $40,354,000 and $50,614,000 related to services performed by Diamondback are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 and 2011 , respectively. +As discussed in Note 3, Gulfport is the operator of its Niobrara Formation acreage under a development agreement with Windsor Niobrara. As operator, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2012 and 2011 , the Company billed Windsor Niobrara approximately $7,545,000 and $6,642,000 , respectively, for these services. At December 31, 2012 and 2011 , Windsor Niobrara owed the Company approximately $173,000 and $3,557,000 , respectively, for these services. +Windsor Ohio LLC ("Windsor Ohio"), an entity controlled by Wexford, participated with the Company in the acquisition of certain leasehold interest in acreage located in the Utica Shale in Ohio. The Company is the operator of this acreage in the Utica Shale. As operator, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2012 and 2011 , the Company billed Windsor Ohio approximately $163,650,000 and $93,871,000 , respectively, for these services. At December 31, 2012 , Windsor Ohio owed the Company approximately $6,520,000 for these services. No amounts were owed by Windsor Ohio at December 31, 2011 . Liddell Investments, LLC (“Liddell Investments”), an entity controlled by Gulfport's Chairman of the Board, has a 10% interest in Windsor Ohio. For the year ended December 31, 2012 , the Company billed Liddell Investments directly for these services in respect of this 10% interest in the amount of approximately $2,020,000 and, at December 31, 2012 , all of this amount was owed to the Company. For the year ended December 2012 , the Company paid Liddell Investments approximately $102,000 in respect of its interest in Windsor Ohio. +F -31 +Table of Contents +Index to Financial Statements +Rhino Exploration LLC ("Rhino"), an affiliate of Wexford, participated with the Company in the acquisition of certain leasehold interest in acreage located in the Utica Shale in Ohio. The Company is the operator of this acreage in the Utica Shale. As operator, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the years ended December 31, 2012 and 2011 , the Company billed Rhino approximately $4,443,000 and $25,862,000 , respectively, for these services. At December 31, 2012 , Rhino owed the Company approximately $4,257,000 for these services. No amounts were owed by Rhino at December 31, 2011 . +Athena Construction LLC (“Athena”), an entity controlled by Wexford, performs services for the Company at its WCBB and Hackberry fields. At December 31, 2012 and 2011 , the Company owed Athena approximately $1,453,000 and $676,000 , respectively, related to these services. Approximately $422,000 and $423,000 of services provided by Athena are included in lease operating expenses in the consolidated statements of operations for the years ended December 31, 2012 and 2011 , respectively. Approximately $5,009,000 and $2,851,000 related to services performed by Athena are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 and 2011 , respectively. +Great White Directional Services LLC (“Directional”) performed services for the Company at its WCBB and Hackberry fields. At December 31, 2011 , the Company owed Directional approximately $2,449,000 related to these services. Approximately $6,068,000 related to services performed by Directional were included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2011 . Directional was controlled by Wexford until it was sold to an unrelated third party in August 2011. +Black Fin P&A, LLC (“Black Fin”), an entity controlled by Wexford, performs plugging and abandonment services for the Company at its WCBB field. At December 31, 2011 , the Company owed Black Fin $436,000 related to these services. No amounts were owed to Black Fin at December 31, 2012 . Approximately $650,000 and $436,000 of services performed by Black Fin are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 and 2011 , respectively. +Caliber Development Company, LLC ("Caliber"), an entity controlled by Wexford, provides building maintenance services for the Company's headquarters in Oklahoma City, Oklahoma. Caliber also leases office space to the Company. At December 31, 2012 and 2011 , the Company owed Caliber approximately $12,000 and $2,000 , respectively, related to these services. Approximately $63,000 and $18,000 of services performed by Caliber and rent paid to Caliber are included in general and administrative expenses on the accompanying consolidated statements of operations for the years ended December 31, 2012 and 2011 , respectively. +16. +COMMITMENTS +Plugging and Abandonment Funds +In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of December 31, 2012 , the plugging and abandonment trust totaled approximately $3,113,000 . At December 31, 2012 , the Company has plugged 354 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its current minimum plugging obligation. +Contributions to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 100% of their total compensation up to the maximum pre-tax threshold through salary deferrals. Also under the plan, the Company will make a contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals and may also make additional discretionary contributions. During the years ended December 31, 2012 , 2011 and 2010 , Gulfport incurred $ 361,000 , $ 310,000 and $ 316,000 , respectively, in contributions expense related to this plan. +Employment Agreements +Effective November 1, 2012, the Company entered into employment agreements with its executive officers, each with an initial three -year term that expires on November 1, 2015 subject to automatic one -year extensions unless terminated by either +F -32 +Table of Contents +Index to Financial Statements +party to the agreement at least 90 days prior to the end of the then current term. These agreements provide for minimum salary and bonus levels which are subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's Amended and Restated 2005 Stock Incentive Plan (or other equity incentive plans that may be put in place for the benefit of employees) and other employee benefits. The aggregate minimum commitment for future salaries and bonuses at December 31, 2012 was approximately $7,050,000 . +Grizzly +On October 5, 2012, the Company entered into an agreement with Grizzly in which it committed to make monthly payments from October 2012 to May 2013 in the aggregate amount of approximately $8.5 million to fund the construction and development of the Algar Lake facility. The Company also agreed to fund its proportionate share of any unfunded cost overruns in excess of $2.0 million . The remaining aggregate commitment at December 31, 2012 was approximately $6.3 million . +Operating Leases +The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at December 31, 2012 are as follows: +2013 +$ +179,000 +2014 +178,000 +2015 +127,000 +2016 +68,000 +2017 +34,000 +Thereafter +— +Total +$ +586,000 +The following table presents rent expense for the years ended December 31, 2012 , 2011 and 2010 , respectively. +For the years ended December 31, +2012 +2,010 +2011 +2,010 +2010 +Minimum rentals +$ +139,000 +— +$ +52,000 +— +$ +65,000 +Less: Sublease rentals +7,000 +— +— +— +— +$ +132,000 +$ +52,000 +$ +65,000 +17. +CONTINGENCIES +The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 to 2007. The LDR maintains that Gulfport paid approximately $1,800,000 less in severance taxes under fixed price terms than the severance taxes Gulfport would have had to pay had it paid severance taxes on the oil at the contracted market rates only. Gulfport has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. Gulfport has maintained its right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against Gulfport seeking $2,275,729 in severance taxes, plus interest and court costs. Gulfport filed a response denying any liability to the LDR for underpayment of severance taxes and is defending itself in the lawsuit. The LDR had taken no further action on this lawsuit since filing its petition other than propounding discovery requests to which Gulfport has responded. Since serving discovery requests on the LDR and receiving the LDR's responses in 2012 there has been no further activity on the case and no trial date has been set. +In December 2010, the LDR filed two identical lawsuits against Gulfport in different venues to recover allegedly underpaid severance taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, Gulfport denies all liability and will vigorously defend the lawsuit. The cases are in the early stages, and Gulfport +F -33 +Table of Contents +Index to Financial Statements +has not yet filed a response to the recent lawsuits. Recently, the LDR filed motions to stay the lawsuits before Gulfport filed any responsive pleadings. The LDR has advised Gulfport that it intends to pursue settlement discussions with Gulfport and other similarly situated defendants in separate proceedings, but has taken no action to initiate settlement talks. There has been no activity on either of these lawsuits for more than a year. +Other Litigation +In November 2006, Cudd Pressure Control, Inc. (“Cudd”) filed a lawsuit against Gulfport, Great White Pressure Control LLC (“Great White”) and six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White’s employment of the former Cudd employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007. Gulfport filed a motion for summary judgment on October 5, 2007. The court entered a final interlocutory judgment in favor of all defendants, including Gulfport, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the case to the original state court, which motion was granted. Cudd subsequently filed amended petitions with the state court (a) alleging, among other things, that Gulfport conspired with the other defendants to misappropriate, and misappropriated Cudd’s trade secrets and caused its employees to breach their fiduciary duties, and (b) seeking monetary damages including $11.8 million as a reasonable royalty for the alleged use of its trade secrets. Cudd also sought disgorgement of the alleged benefits received by the various defendants. Cudd also sought its attorney's fees, which Cudd claimed were not less than $450,000 , plus 10% of any final judgment. This case went to trial on September 5, 2012 and on September 28, 2012 the jury rendered its verdict, awarding no damages to the plaintiffs. Gulfport along with all defendants filed a Motion for Entry of Judgment that is consistent with the jury's verdict. Cudd filed an Application for Disgorgement and a Motion for Judgment Notwithstanding the Verdict. The court denied all of Cudd's post-trial motions on October 12, 2012, and issued its final judgment on January 10, 2013. On that same day, Cudd filed motions for a new trial and to modify, correct of reform the judgment. Those motions remain pending. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al.,38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name Gulfport as a defendant, alleges that the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. Plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and response costs and stigma damages. On December 7, 2010, Gulfport was served with a copy of the plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including Gulfport, bringing the total number of defendants to 21 . It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income; attorney fees and expenses and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to Gulfport, current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, Gulfport filed a pleading challenging the legal sufficiency of the petitions on several grounds and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by Gulfport and similar pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue. In response, Gulfport and numerous defendants re-urged their pleadings challenging the legal sufficiency of the petitions. Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the court on May 25, 2011 and were denied. The +F -34 +Table of Contents +Index to Financial Statements +court signed the written judgment on December 9, 2011. Gulfport noticed its intent to seek supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application. Gulfport filed its supervisory writ, which was denied by the Louisiana Third Circuit Court of Appeal and the Louisiana Supreme Court. Gulfport has been active in serving discovery requests and responding to discovery requests from the plaintiffs. It is anticipated that the discovery phase of this case will become more active in the upcoming months. Plaintiffs' counsel is seeking a trial date in mid-2013. +Due to the early stages of the LDR and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that may result. In each case, management has determined the possibility of loss is remote. However, litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations and management cannot determine the amount of loss, if any, that may result. +The Company has been named as a defendant in various other lawsuits related to its business. In each such case, management has determined that the possibility of loss is remote. The resolution of these matters is not expected to have a material adverse effect on the Company financial condition or results of operations in future periods. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry principally in the state of Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000 . At December 31, 2012 , Gulfport held cash in excess of insured limits in these banks totaling $166,588,000 . +During the year ended December 31, 2012 , Gulfport sold approximately 92% and 8% of its oil production to Shell Trading Company (“Shell”) and Diamondback O&G, respectively, 91% of its natural gas liquids production to Diamondback O&G, and 41% , 18% and 16% of its natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During the year ended December 31, 2011 , Gulfport sold approximately 93% and 7% of its oil production to Shell and Diamondback O&G, respectively, 100% of its natural gas liquids production to Diamondback O&G and 50% , 27% , and 22% of its natural gas production to Hilcorp Energy Company, Chevron, and Diamondback O&G, respectively. During the year ended December 31, 2010 , Gulfport sold approximately 75% and 19% of its oil production to Shell and Diamondback O&G, respectively, and 50% , 32% , and 10% of its natural gas production to Diamondback O&G, Chevron, and Hilcorp, respectively. +18. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES +The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States: +Capitalized Costs Related to Oil and Gas Producing Activities +2012 +2011 +Proven properties +$ +984,795,000 +$ +897,130,000 +Unproven properties +626,295,000 +132,912,000 +1,611,090,000 +1,030,042,000 +Accumulated depreciation, depletion, amortization and impairment reserve +(661,442,000 +) +(571,213,000 +) +Net capitalized costs +$ +949,648,000 +$ +458,829,000 +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +F -35 +Table of Contents +Index to Financial Statements +2012 +2011 +2010 +Acquisition +$ +513,904,000 +$ +119,522,000 +$ +17,627,000 +Development of proved undeveloped properties +121,787,000 +123,489,000 +64,652,000 +Exploratory +93,397,000 +3,994,000 +— +Recompletions +24,643,000 +17,259,000 +16,917,000 +Capitalized asset retirement obligation +2,195,000 +1,390,000 +1,328,000 +Total +$ +755,926,000 +$ +265,654,000 +$ +100,524,000 +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production. +2012 +2011 +2010 +Revenues +$ +248,601,000 +$ +228,953,000 +$ +127,636,000 +Production costs +(53,708,000 +) +(47,230,000 +) +(31,580,000 +) +Depletion +(90,230,000 +) +(61,965,000 +) +(38,600,000 +) +104,663,000 +119,758,000 +57,456,000 +Income tax expense (benefit) +Current +730,000 +282,000 +40,000 +Deferred +25,633,000 +(372,000 +) +— +26,363,000 +(90,000 +) +40,000 +Results of operations from producing activities +$ +78,300,000 +$ +119,848,000 +$ +57,416,000 +Depletion per barrel of oil equivalent (BOE) +$ +35.07 +$ +26.56 +$ +19.54 +Oil and Gas Reserves (Unaudited) +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2012 , 2011 and 2010 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012 , 2011 and 2010 , in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The prices used for the 2012 reserve report are $ 91.32 per barrel and $ 2.76 per MMbtu, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2011 and 2010 for reserve report purposes are $ 96.19 per barrel and $ 4.12 per MMbtu and $ 76.16 per barrel and $ 4.38 per MMbtu, respectively. +Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. +F -36 +Table of Contents +Index to Financial Statements +2012 +2011 +2010 +Oil +Gas +Oil +Gas +Oil +Gas +(MBbls) +(MMcf) +(MBbls) +(MMcf) +(MBbls) +(MMcf) +Proved Reserves +Beginning of the period +16,745 +15,728 +19,704 +16,158 +17,488 +14,332 +Purchases in oil and gas reserves in place +— +— +2 +19 +3,913 +3,482 +Extensions and discoveries +4,880 +31,265 +3,940 +2,091 +5,574 +5,303 +Sales of oil and gas reserves in place +(10,604 +) +(11,757 +) +— +— +— +— +Revisions of prior reserve estimates +(382 +) +(357 +) +(4,714 +) +(1,662 +) +(5,426 +) +(6,171 +) +Current production +(2,388 +) +(1,108 +) +(2,187 +) +(878 +) +(1,845 +) +(788 +) +End of period +8,251 +33,771 +16,745 +15,728 +19,704 +16,158 +Proved developed reserves +5,219 +18,482 +7,485 +6,152 +7,230 +6,068 +Proved undeveloped reserves +3,032 +15,289 +9,260 +9,576 +12,474 +10,090 +The Company contributed its Permian Basin assets to Diamondback in 2012, as discussed in Note 4, resulting in a decrease of 12,564 thousand barrels of oil equivalent (MBOE) in estimated proved reserves in 2012. In addition, the Company experienced downward reserve revisions of 442 MBOE in estimated proved reserves in 2012 primarily due to a change in the drilling schedule of its Niobrara acreage. The Company also experienced downward reserve revisions in 2011. These downward revisions were primarily the result of the drilling of PUDs during the Company’s 2011 drilling program and ethane takeaway issues in the Permian Basin. The Company experienced downward reserve revisions in estimated proved reserves in 2010. These downward revisions were primarily the result of the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of Oil and Gas Reporting” Final Rule. +Discounted Future Net Cash Flows (Unaudited) +The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2012 , 2011 and 2010 using an unweighted average first-of-the-month price for the period January through December for 2012 , 2011 and 2010 . +Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +Year ended December 31, +2012 +2011 +2010 +Future cash flows +$ +954,833,000 +$ +1,594,050,000 +$ +1,479,295,000 +Future development and abandonment costs +(159,113,000 +) +(306,810,000 +) +(301,651,000 +) +Future production costs +(147,024,000 +) +(295,383,000 +) +(305,814,000 +) +Future production taxes +(89,175,000 +) +(124,739,000 +) +(136,323,000 +) +Future income taxes +(114,867,000 +) +(229,649,000 +) +(159,171,000 +) +Future net cash flows +444,654,000 +637,469,000 +576,336,000 +10% discount to reflect timing of cash flows +(96,013,000 +) +(260,788,000 +) +(260,849,000 +) +Standardized measure of discounted future net cash flows +$ +348,641,000 +$ +376,681,000 +$ +315,487,000 +In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers in Gulfport’s reserve report, the Company will need to spend $ 82,772,000 , $ 16,416,000 and $ 4,335,000 during years 2013 , 2014 and 2015 , respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) +F -37 +Table of Contents +Index to Financial Statements +Year ended December 31, +2012 +2011 +2010 +Sales and transfers of oil and gas produced, net of production costs +$ +(194,893,000 +) +$ +(181,723,000 +) +$ +(96,056,000 +) +Net changes in prices, production costs, and development costs +108,941,000 +136,071,000 +122,147,000 +Acquisition of oil and gas reserves in place +— +72,000 +63,043,000 +Extensions and discoveries +151,654,000 +107,110,000 +88,227,000 +Revisions of previous quantity estimates, less related production costs +(10,504,000 +) +(112,553,000 +) +(89,155,000 +) +Sales of reserves in place +(214,867,000 +) +— +— +Accretion of discount +37,668,000 +31,549,000 +24,077,000 +Net changes in income taxes +25,585,000 +(36,674,000 +) +(54,879,000 +) +Change in production rates and other +68,376,000 +117,342,000 +17,309,000 +Total change in standardized measure of discounted future net cash flows +$ +(28,040,000 +) +$ +61,194,000 +$ +74,713,000 +19. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The following table summarizes quarterly financial data for the years ended December 31, 2012 and 2011 : +2012 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +65,461,000 +$ +66,325,000 +$ +60,537,000 +$ +56,603,000 +Income from operations +27,263,000 +25,947,000 +18,178,000 +25,875,000 +Income tax expense +— +— +15,514,000 +10,849,000 +Net income +26,869,000 +25,117,000 +502,000 +15,883,000 +Income per share: +Basic +$ +0.48 +$ +0.45 +$ +0.01 +$ +0.28 +Diluted +$ +0.48 +$ +0.45 +$ +0.01 +$ +0.28 +2011 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +Revenues +$ +46,638,000 +$ +55,589,000 +$ +58,081,000 +$ +68,946,000 +Income from operations +22,105,000 +28,156,000 +29,118,000 +31,585,000 +Income tax expense (benefit) +— +1,000 +— +(91,000 +) +Net income +21,174,000 +27,265,000 +29,009,000 +30,974,000 +Income per share: +Basic +$ +0.47 +$ +0.57 +$ +0.58 +$ +0.59 +Diluted +$ +0.47 +$ +0.57 +$ +0.57 +$ +0.59 +20. +SUBSEQUENT EVENTS +As discussed in Note 8 above, the Company issued and sold 11,750,000 shares of its common stock in an underwritten public offering on December 24, 2012 which included the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares. The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of common stock subject to the over-allotment option in a second closing, which occurred on January 7, 2013. The net proceeds from the equity offering (including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) were approximately $460.7 million . The Company used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, as described above in Note 2 and for general corporate purposes, including the funding of a portion of its 2013 capital development plan. +On February 15, 2013, the Company completed the sale of an aggregate of 8,912,500 shares of its common stock in an underwritten public offering at a public offering price of $38.00 per share less the underwriting discount. The Company +F -38 +Table of Contents +Index to Financial Statements +received aggregate net proceeds of approximately $325.8 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of the net proceeds from this equity offering to fund its acquisition of additional Utica Shale acreage as described below, and intends to use the balance for general corporate purposes, including the funding of a portion of its 2013 capital development plan. +On February 15, 2013, the Company completed an acquisition for approximately 22,000 net acres in the Utica Shale in Eastern Ohio. The purchase price was approximately $220 million , subject to certain adjustments. This acquisition excluded the seller's interest in 14 existing wells and 16 proposed future wells together with certain acreage surrounding these wells. The Company acquired its initial acreage in the Utica Shale in February 2011 and subsequently acquired additional acreage in the area. Through a prior transaction in December 2012 discussed in Note 2, the Company acquired approximately 37,000 net acres in the Utica Shale, which increased the Company's working interest in the acreage to 77.7% . Through the February 2013 transaction, the Company acquired an additional approximately 16.2% interest in these leases, increasing its working interest in the acreage to 93.8% . All of the acreage included in this transaction is currently nonproducing and the Company is the operator of all of this acreage, subject to existing development and operating agreements between the parties. +F -39 +Table of Contents +Index to Financial Statements +EXHIBIT INDEX +Exhibit +Number +Description +2.1 +Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.2 +Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). +2.3 +Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012). +2.4 +Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 18, 2012). +2.5 +Amendment, dated December 19, 2012, to the Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 20, 2012). +2.6 +Purchase and Sale Agreement, dated February 11, 2013, by and between Windsor Ohio, LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 15, 2013). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009). +3.3 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). +4.2 +Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). +4.3 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +4.4 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.5 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +4.6 +Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +E -1 +Table of Contents +Index to Financial Statements +4.7 +Registration Rights Agreement, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.8 +First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +4.9 +Registration Rights Agreement, dated as of December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +10.1+ +Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+ +Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.4+ +Employment Agreement, dated November 7, 2012, between the Company and Mike Liddell (incorporated by reference to Exhibit 10.4 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.5+ +Employment Agreement, dated November 7, 2012, between the Company and James D. Palm (incorporated by reference to Exhibit 10.5 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.6+ +Employment Agreement, dated November 7, 2012, between the Company and Michael G. Moore (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.7 +Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). +10.8 +Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). +10.9 +First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, KeyBank National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2011). +10.10 +Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). +10.11 +Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). +10.12 +Fourth Amendment, dated May 2, 2012, to Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the Bank of Nova Scotia, as administrative agent and letter of credit issuer, Amegy Bank National Association, Key Bank National Association and Société Générale (incorporated by reference to Exhibit 10.1 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 10, 2012). +E -2 +Table of Contents +Index to Financial Statements +10.13 +Fifth Amendment to Credit Agreement, effective as of October 9, 2012, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 9, 2012). +10.14 +Sixth Amendment to Credit Agreement, effective as of October 17, 2012, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +10.15 +Seventh Amendment to Credit Agreement, effective as of December 18, 2012, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +10.16 +Investor Rights Agreement, dated as of October 11, 2012, between Gulfport Energy Corporation and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 17, 2012). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Ryder Scott Company. +23.4* +Consent of Pinnacle Energy Services, LLC. +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1** +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2** +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Ryder Scott Company. +101.INS** +XBRL Instance Document. +101.SCH** +XBRL Taxonomy Extension Schema Document. +101.CAL** +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF** +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB** +XBRL Taxonomy Extension Labels Linkbase Document. +101.PRE** +XBRL Taxonomy Extension Presentation Linkbase Document. +* +Filed herewith. +** +Furnished herewith, not filed. +E -3 +Table of Contents +Index to Financial Statements ++ +Management contract, compensatory plan or arrangement. +E -4 \ No newline at end of file diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/filing_metadata.csv b/raw/filings/0000874499/2012/0001445305-13-000396/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..44c051d1a07bf268dddfd30981c9553054aa88ef --- /dev/null +++ b/raw/filings/0000874499/2012/0001445305-13-000396/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2013-03-01,2012-12-31,2013-02-28T23:44:44.000Z,0001445305-13-000396,gpor-12312012x10k.htm,10-K,15646544,1,0,https://www.sec.gov/Archives/edgar/data/874499/000144530513000396/gpor-12312012x10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000144530513000396/,2012,2012,1 diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/item1.txt b/raw/filings/0000874499/2012/0001445305-13-000396/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..b50683c0537760532838596a3d35cb3ee059f0bd --- /dev/null +++ b/raw/filings/0000874499/2012/0001445305-13-000396/item1.txt @@ -0,0 +1,471 @@ +ITEM 1. +BUSINESS +General +We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, and in the Utica Shale in Eastern Ohio. During 2010, we acquired our initial acreage position in the Niobrara Formation of Northwestern Colorado and, during 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, a 21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO (see “- Recent Developments-Contribution ” below), and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +In 2012, at our WCBB field, we recompleted 61 wells and drilled 31 wells for a total cost of approximately $68.2 million as of December 31, 2012. Of the 31 new wells drilled at WCBB in 2012, 27 were completed as producing wells and four were non-productive. In the fourth quarter of 2012, production at WCBB was approximately 293,906 net barrels of oil equivalent, or BOE, or an average of 3,195 BOE per day, 98% of which was from oil and 2% of which was from natural gas. During January 2013, our average net daily production at WCBB was approximately 3,054 BOE, 98% of which was from oil and 2% of which was from natural gas. During 2013, we currently anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $42.0 million to $45.0 million. +In 2012, at our East Hackberry field, we recompleted 32 wells and drilled 23 wells for a total cost of approximately $70.1 million as of December 31, 2012. Of the 23 new wells drilled at East Hackberry during 2012, 19 were completed as producing wells, three were non-productive and one was being drilled at year end. In the fourth quarter of 2012, net production at East Hackberry was approximately 212,975 BOE, or an average of 2,315 BOE per day, 98% of which was from oil and 2% of which was from natural gas. During January 2013, our average net daily production at East Hackberry was approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas. During 2013, we currently anticipate drilling ten to twelve wells and recompleting 24 wells for an aggregate estimated cost of $26.0 million to $28.0 million. +At December 31, 2012, we were drilling one well at our West Hackberry field. In the fourth quarter of 2012, net production at West Hackberry was approximately 4,711 BOE, or an average of 51 BOE per day, 96% of which was from oil and 4% of which was from natural gas. During January 2013, our average net daily production at West Hackberry was approximately 29 BOE, 100% of which was from oil. +As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, and in February 2013 we acquired an additional approximately 22,000 net acres in the Utica Shale. See "-Recent Developments - February 2013 Utica Acreage Acquisition." We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2012, had drilled 14 wells, ten of which had been completed. As of February 15, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected to be producing by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells on-line have primarily been associated with MarkWest Energy Partners, L.P.'s challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012. +We have three rigs under contract on our Utica Shale acreage. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 2013 for approximately $382.0 million to $426.0 million. +Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 BOE per day, 35% of which was from oil and natural gas liquids, or NGLs, and 65% of which was from natural gas. During January 2013, our average daily net production from the Utica Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. The Wagner 1-28H well, our longest producing well in the Utica Shale, was assigned gross proved estimated ultimate recovery reserves at December 31, 2012 of 65.8 thousand barrels of oil, or MBbls, and 10.0 billion cubic feet, or Bcf, of unshrunk natural gas by Ryder Scott Company, +2 +Table of Contents +Index to Financial Statements +L.P., or Ryder Scott. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 million BOE, or MMBOE, of proved reserves. +From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was NGL's and 12% was natural gas. For more information regarding the contribution of our Permian Basin acreage to Diamondback, see “ -Recent Developments-Contribution ” below. +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and held leases for approximately 11,788 net acres as of December 31, 2012. During the year ended December 31, 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. In the fourth quarter of 2012, net production from our Niobrara Formation acreage was approximately 2,644 BOE, or an average of 29 BOE per day, 100% of which was from oil. During January 2013, our average net daily production from our Niobrara Formation acreage was approximately 43 BOE, 100% of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey and have received a processed version of the seismic. During 2013, we currently do not anticipate drilling any wells in the Niobrara Formation. +As of December 31, 2012, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in nine wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2012, our net production from this acreage was approximately 7,355 BOE, or an average of 80 BOE per day, of which 87% was from oil, 10% was from natural gas and 3% was from NGLs. During January 2013, our average daily net production from our Bakken Formation acreage was approximately 73 BOE, of which 89% was from oil and 11% was from natural gas. +We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oils Sands Inc., an entity owned by certain investment funds managed by Wexford Capital LP, or Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of December 5, 2011, and approximately 9.5% as of March 13, 2012, which ownership was reduced to less than 1% as of September 28, 2012. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately $172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the Alberta Energy Resources Conservation Board, or ERCB, to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake by the third quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid-2014 and first oil production by mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company's bitumen starting in the third quarter of 2013. +We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, +3 +Table of Contents +Index to Financial Statements +LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. +We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately 490,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet, or MMcf, per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013. +In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing. Stingray Pressure and Stingray Cementing provide well completion services. We also acquired a 50% equity interest in Blackhawk Midstream LLC, or Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. In March 2012, we acquired a 50% equity interest in Timber Wolf Terminals LLC, or Timber Wolf, for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In the fourth quarter of 2012, we acquired a 50% equity interest in Stingray Logistics LLC, or Stingray Logistics, which will provide well services. In 2011, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in Bison for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie Holdings LLC, or Muskie, which is engaged in the mining of hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. +As of December 31, 2012, we had 13.9 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $436.8 million and associated standardized measure of discounted future net cash flows of approximately $348.6 million , excluding reserves attributable to our interests in Diamondback, Grizzly, Tatex II and Tatex III. See "Item 2. Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Recent Developments +February 2013 Utica Acreage Acquisition +On February 11, 2013, we entered into a purchase and sale agreement, or the PSA, with Windsor Ohio, LLC, or Windsor Ohio, which is an affiliate of Wexford, pursuant to which Windsor Ohio agreed to sell, assign, transfer and convey to us approximately 22,000 net acres representing 100% of its right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio for approximately $220.4 million, subject to certain adjustments. This transaction, which closed on February 15, 2013, excluded Windsor Ohio's interest in 14 existing wells and 16 proposed future wells together with certain acreage surrounding these wells. We acquired our initial acreage in the Utica Shale in February 2011 and subsequently acquired additional acreage in the area. Windsor Ohio participated with us in the acquisition of these leases. Through a prior transaction with Windsor Ohio, as discussed below under the heading " —December 2012 Utica Acreage Acquisition, " we acquired approximately 37,000 net acres, which increased our working interest in the acreage at the time to 77.7%. Through this most recent transaction, we acquired an additional approximately 16.2% interest in these leases, increasing our working interest in the acreage to 93.8%. All of the acreage included in this transaction is currently nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. +Pending the completion of title review after the closing, approximately $33.6 million of the purchase price has been placed +4 +Table of Contents +Index to Financial Statements +in an escrow account. The escrow account will terminate on May 1, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review. Pursuant to the PSA, we and Windsor Ohio have agreed to indemnify each other, our respective affiliates and their respective officers, directors, employees and agents from and against all losses that such indemnified parties incur arising from any breach of representations, warranties or covenants in the PSA and certain other matters. The transaction was approved by a special committee of our board of directors, who engaged independent counsel and financial advisors to assist with their review. +December 2012 Utica Acreage Acquisition +On December 17, 2012, we entered into a purchase and sale agreement with Windsor Ohio, pursuant to which Windsor Ohio agreed to sell, assign, transfer and convey to us approximately 30,000 net acres which, at the time, represented 50% of its right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio. On December 19, 2012, the parties amended that agreement to provide for our acquisition of approximately 7,000 additional net acres. The aggregate purchase price for these interests was approximately $372.0 million, subject to certain adjustments. As discussed above, we acquired our initial acreage in the Utica Shale in February 2011 and subsequently acquired additional acreage in the area. Windsor Ohio has participated with us in the acquisition of these leases and through this transaction, we acquired an additional approximately 27.5% interest in these leases, increasing our working interest in the acreage to 77.7%. The transaction closed on December 24, 2012. All of the acreage included in this transaction is nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the completion of title review after the closing, approximately $53.9 million of the purchase price was placed in an escrow account. The escrow account will terminate on April 30, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review. +Contribution +On May 7, 2012, we entered into a contribution agreement with Diamondback, which is an affiliate of Wexford. Under the terms of the contribution agreement, we agreed to contribute to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and gas interests in the Permian Basin. On October 11, 2012, we completed this contribution, which we refer to in this Annual Report as the Contribution. At the closing of the Contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of the Contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of December 11, 2012, Wexford beneficially owned approximately 44.4% of Diamondback's outstanding common stock. +In connection with the Contribution, we and Diamondback entered into an investor rights agreement in which we have the right, for so long as we beneficially own more than 10% of Diamondback's outstanding common stock, to designate one individual as a nominee to serve on Diamondback's board of directors. Such nominee, if elected to Diamondback's board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as we have the right to designate a nominee to Diamondback's board and there is no nominee of ours actually serving as a Diamondback director, we will have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. We are also entitled to certain information rights and Diamondback granted us certain demand and “piggyback” registration rights obligating Diamondback to register with the Securities and Exchange Commission, or the SEC, any shares of Diamondback common stock that we own. Immediately upon completion of the Contribution, we owned a 35% equity interest in Diamondback, rather than leasehold interests in our Permian Basin acreage. Upon completion of the Diamondback IPO and the exercise in full by the underwriters of their over-allotment option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. +Notes Offerings +On October 17, 2012, we issued $250.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the October Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, which indenture we refer to as the senior note indenture. The offering of the October Notes is referred to herein as the October Notes Offering. On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the December Notes, to qualified institutional +5 +Table of Contents +Index to Financial Statements +buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, which offering we refer to herein as the December Notes Offering. The December Notes were issued as additional securities under the senior note indenture. The October Notes and the December Notes are referred to collectively herein as the Notes, and we refer to the October Notes Offering and the December Notes Offering collectively as the Notes Offerings. +Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. For more information regarding the Notes, see Item 7. “ Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Senior Notes .” +Equity Offerings +On December 24, 2012, we issued and sold 11,750,000 shares of our common stock in an underwritten public offering, or the December 2012 Equity Offering (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares). The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of common stock subject to the over-allotment option at a second closing, which occurred on January 7, 2013. The net proceeds from the December 2012 Equity Offering (including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) were approximately $460.7 million. We used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, as described above under the caption “ —December 2012 Utica Acreage Acquisition .” The remaining net proceeds will be used for general corporate purposes, including the funding of a portion of our 2013 capital development plan. +On February 15, 2013, we issued and sold 8,912,500 shares of our common stock (including the 1,162,500 shares issued upon the exercise in full of an over-allotment option granted to the underwriters) in an underwritten public offering, which we refer to in this report as the February 2013 Equity Offering. The net proceeds from the February 2013 Equity Offering were approximately $325.8 million. We used a portion of these net proceeds to fund the acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio, as described above under the caption “ -February 2013 Utica Acreage Acquisition. ” The remaining net proceeds will be used for general corporate purposes, including the funding of a portion of our 2013 capital development plan. +Senior Secured Credit Facility +Effective as of October 17, 2012, in connection with the completion of the October Notes Offering and the Contribution, our borrowing base under our senior secured credit facility was set at $45.0 million until the next borrowing base redetermination. Upon completion of the December Notes Offering, our borrowing base was further reduced to $40.0 million. As of December 31, 2012, no borrowings were outstanding under our senior secured credit facility. +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2012 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Utica Shale in Eastern Ohio, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. +6 +Table of Contents +Index to Financial Statements +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +MBOE +MBOE +MBOE +West Cote Blanche Bay Field (4) +80.108/100 +109 +109 +181 +181 +5,668 +5,668 +556 +4,266 +4,822 +E. Hackberry Field (5) +80.309/100 +41 +41 +96 +96 +3,931 +3,931 +151 +1,900 +2,051 +W. Hackberry Field +83.333/100 +3 +3 +23 +23 +1,192 +1,192 +3 +95 +98 +Utica Shale (6) +40.641/50.0 +2 +1 +— +— +2,441 +1,800 +4,886 +1,702 +6,588 +Niobrara Formation +36.2/41.5 +7 +3 +2 +1 +2,807 +1,404 +16 +204 +220 +Bakken Formation (7) +2.7/2.9 +8 +0.2 +— +— +1,862 +163 +10 +82 +92 +Overrides/Royalty Non-operated +Various +208 +0.4 +2 +0.06 +— +— +6 +2 +8 +Total +378 +157.6 +304 +301.06 +17,901 +14,158 +5,628 +8,251 +13,879 +(1) +Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. +(2) +Includes seven gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 11% of our acreage is developed acreage and has been perpetuated by production. +(4) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). +(5) +NRI shown is for producing wells. +(6) +Does not give effect to our February 2013 acquisition of approximately 22,000 additional net acres. See "—Recent Developments-February 2013 Utica Acreage Acquisition." +(7) NRI/WI is from wells that have been drilled or in which we have elected to participate. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,025 wells drilled as of December 31, 2012, 927 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2012, we drilled 214 new wells, 193 of which were productive, for a 90% success rate. As of December 31, 2012, estimated field cumulative gross production was 194.0 MMBOE and 236.9 Bcf of gas. Of the 1,025 wells drilled in WCBB as of December 31, 2012, 102 were producing, 181 were shut-in, seven were producing intermittently and five were being used as salt water disposal wells. The other 730 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition +7 +Table of Contents +Index to Financial Statements +and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,025 wells that had been drilled in the field as of December 31, 2012, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2012 included 36 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2015. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2012, we recompleted 61 gross and net wells and drilled 31 gross and net wells at WCBB. Of the 31 new wells drilled at WCBB in 2012, 27 were completed as producers and four were non-productive. As of February 15, 2013, we had recompleted 12 wells during 2013. Of the 31 wells drilled in 2012, 26 were considered deep wells. The 27 productive wells, with total depths ranging from 2,500 to 10,697 feet, have approximately 1,818 feet of aggregate apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2013. +Production Status +In the fourth quarter of 2012, our production at WCBB was approximately 293,906 net BOE, or an average of 3,195 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production at WCBB was approximately 3,054 BOE, 98% of which was from oil and 2% of which was from natural gas. As there was no production from new wells brought on line in January 2013, the decrease in average net daily production was due to normal production declines. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.309% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2012, we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic data. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production +8 +Table of Contents +Index to Financial Statements +through 2012 was over 2,754 MBOE and 330 Bcf of casinghead gas production. A total of 239 wells have been drilled on our portion of the field. As of December 31, 2012, 41 wells had daily production, 96 were shut-in and two had been converted to salt water disposal wells. The remaining 100 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, four natural gas compressors, dehydration units and salt water disposal systems. +Recent and Future Activity +During 2012 at East Hackberry, we recompleted 32 gross and net wells and drilled 14 gross and net land wells and nine gross and net wells on water. Of the 23 wells drilled during 2012, 19 were completed as producing wells, three were non-productive and one was being drilled at year end. As of February15, 2013, we had recompleted two wells during 2013, drilled two wells and were in the process of drilling one additional well in our East Hackberry field. We currently intend to drill ten to twelve gross and net wells and recomplete 24 gross and net wells in our East Hackberry field during 2013. +Production Status +In the fourth quarter of 2012, our net production at East Hackberry was approximately 212,975 BOE, or an average of 2,315 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production at East Hackberry was approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas. The increase in production in 2013 is a result of our 2012 drilling activities. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 83.333% NRI) in 1,192 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2012 was 307 MBOE and 140 Bcf of natural gas. There have been 37 wells drilled to date on our portion of West Hackberry. Currently, three of such wells are producing, 23 are shut-in and one has been converted to a saltwater disposal well. The remaining ten wells have been plugged and abandoned. At December 31, 2012, we were drilling one well at our West Hackberry field. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +9 +Table of Contents +Index to Financial Statements +Production Status +In the fourth quarter of 2012, our net production at West Hackberry was approximately 4,711 BOE, or an average of 51 BOE per day. From January 1, 2013 through January 31, 2013, our average net daily production at West Hackberry was approximately 29 BOE and was 100% from oil. +Facilities +We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. +Utica Shale (Eastern Ohio) +Location and Land +As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, including the approximately 37,000 net acres acquired in December 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. See "-Recent Developments-February 2013 Utica Acreage Acquisition." +Area History +Based on the estimates published by the Ohio Department of Natural Resources, or ODNR, in 2012, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2012, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio. As of February 9, 2013, the ODNR reported that in the Utica Shale in Ohio there were 65 producing horizontal wells, 236 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 15 horizontal wells that were being drilled and an additional 272 horizontal wells that had been permitted. +During 2012, most of the drilling activity in the Utica Shale occurred in Eastern Ohio, where our acreage is located. Based on the initial drilling results, the Utica Shale is prospective for oil and NGLs. Specifically, early wells drilled in the Utica Shale indicated potential for production of significant amounts of NGLs, which generally have a higher value, on an energy-equivalent basis, than natural gas. +Geology +The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. +Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. +The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west. +The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. +10 +Table of Contents +Index to Financial Statements +The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale. +Facilities +There are typical land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well locations including storage tank batteries, oil/gas/water separation equipment, vapor recovery line heaters and compression. +Recent and Future Activities +We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2012, had drilled 14 wells, ten of which had been completed. As of February 15, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected to be producing by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells online have primarily been associated with MarkWest Energy Partners, L.P.'s challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. +We have three rigs under contract on our Utica Shale acreage. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 2013. +Production Status +Aggregate net production from the Utica Shale during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 BOE per day, 35% of which was from oil and NGLs and 65% of which was from natural gas. During January 2013, our average daily net production from the Utica Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. The Wagner 1-28H well, our longest producing well in the Utica Shale, was assigned gross proved estimated ultimate recovery reserves at December 31, 2012 of 65.8 MBbls of oil and 10.0 Bcf of unshrunk natural gas by Ryder Scott. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 MMBOE of proved reserves. +Permian Basin (West Texas) +Location and Land +In 2007, we acquired approximately 4,100 net acres in West Texas in the Permian Basin with production at the time of acquisition from 32 gross (16 net) wells, predominately in the Wolfcamp formation. Subsequently, we acquired approximately 14,100 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 18,200 net acres as of September 30, 2012. From our initial acquisition in the Permian Basin through the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 118 gross (53.7 net) wells were drilled on our leasehold acreage in this area, primarily targeting the Wolfberry formation. We were not the operator of our Permian Basin acreage but were actively involved in the planning and execution of the drilling plans governed by a joint operating agreement with a subsidiary of Diamondback, which is the operator in this field. From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was NGLs and 12% was natural gas. +The Permian Basin area covers a significant portion of Western Texas and Eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. +11 +Table of Contents +Index to Financial Statements +Area History +The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum's Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum's program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. +Geology +The Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. +Facilities +There are typical land oil and natural gas processing facilities in the Permian Basin. The facilities located at well locations included storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +As discussed above under the heading “- Recent Developments-Contribution ,” on October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a subsidiary of Diamondback as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Following the Contribution, we account for our interest in Diamondback as an equity investment. +Niobrara Formation (Northwestern Colorado) +Location and Land +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado, and held leases for approximately 11,788 net acres as of December 31, 2012. In 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. +Area History +The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of +12 +Table of Contents +Index to Financial Statements +producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. +Geology +The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. +Production Status +In the fourth quarter of 2012, our net production from our Niobrara Formation acreage was approximately 2,644 BOE, or an average of 29 BOE per day, 100% of which was from oil. From January 1, 2013 through January 31, 2013, our average daily net production from our Niobrara Formation acreage was approximately 43 BOE, 100% of which was from oil. +Facilities +There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activity +We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We do not anticipate drilling any wells in the Niobrara Formation during 2013. +Bakken Formation +Location and Land +The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken's assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOE per day of production for approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2012, we held approximately 864 net acres, interests in nine wells and an overriding royalty interests in certain existing and future wells. +Production Status +In the fourth quarter of 2012, our net production from our Bakken Formation acreage was approximately 7,355 BOE, or an average of 80 BOE per day, of which 87% was from oil, 3% was from NGLs and 10% was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production from this acreage was approximately 73 BOE, of which 89% was from oil and 11% was from natural gas. +Facilities +There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +13 +Table of Contents +Index to Financial Statements +Recent and Future Activities +Three gross (.04 net) wells were drilled on our Bakken Formation acreage in 2012. As of February 15, 2013, two gross (.03 net) wells had been drilled on our Bakken Formation acreage in 2013. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2012: +Field +State +Parish/County +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Deer Island +Louisiana +Terrebonne +3.125 +% +— +% +1 +— +Napoleonville +Louisiana +Assumption +— +% +2.5 +% +3 +— +Crest +Texas +Ochiltree +2 +% +— +% +1 +— +Eagle City South +Oklahoma +Dewey +1.04 +% +— +% +1 +— +Fay South +Oklahoma +Blaine +0.301 +% +— +% +1 +— +Squaw Cheek +Oklahoma +Blaine +0.694 +% +— +% +1 +— +Our Equity Investments +Permian Basin . As discussed above under the heading “- Recent Developments-Contribution ,” on October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. +Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc., an entity owned by certain investment funds managed by Wexford. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca and Peace River oil sands region of Alberta, Canada. Our total net investment in Grizzly was approximately $172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the ERCB to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake during the third quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid-2014 and first oil production by mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN’s rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly’s Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company’s bitumen starting in the third quarter of 2013. +14 +Table of Contents +Index to Financial Statements +Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II, at a cost of $2.4 million. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. During the year ended December 31, 2012, we received $0.8 million in distributions, reducing our total investment in Tatex II to $0.2 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet per day. For 2012, net gas production was approximately 93 MMcf per day and condensate production was 428 barrels per day. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately 490,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the year ended December 31, 2012, we paid $0.6 million in cash calls, bringing our total investment in Tatex III to $8.7 million. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 MMcf per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013. +Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure and Stingray Cementing. Stingray Pressure and Stingray Cementing will provide well completion services. We also acquired a 50% equity interest in Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. In the fourth quarter of 2012, we also acquired a 50% equity interest in Stingray Logistics, which will provide well services. In March 2012, we acquired a 50% equity interest in Timber Wolf for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Midstream for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest in Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in Bison for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the mining of hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. +Competition and Markets +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. +15 +Table of Contents +Index to Financial Statements +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI trade month average differential less $2.00 per barrel for transportation. During the year ended December 31, 2012 , we sold approximately 92% and 8% of our oil production to Shell Trading Company, or Shell, and Diamondback O&G LLC (a wholly-owned subsidiary of Diamondback formerly known as Windsor Permian LLC), or Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G and 41% , 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G, and 22%, 27% and 50% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Diamondback O&G, respectively, and 50%, 32%, and 10% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. Shell has agreed to purchase our Utica Shale oil and we have agreements in place with various purchasers for our Utica Shale natural gas production. We may not continue to have ready access to suitable markets for our future oil and natural gas production and if a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. +Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. +To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, “ and related pronouncements. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +16 +Table of Contents +Index to Financial Statements +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, and in the Utica Shale in Eastern Ohio, the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property +17 +Table of Contents +Index to Financial Statements +contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. +The Oil Pollution Act, or OPA, is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. +Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail under the caption “ -Regulation of Hydraulic Fracturing .” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. +Climate Change . Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutants” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other +18 +Table of Contents +Index to Financial Statements +GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective in January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation's National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. +In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +19 +Table of Contents +Index to Financial Statements +Regulation of Hydraulic Fracturing +Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. +On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected between later in 2013 and 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. +Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota +20 +Table of Contents +Index to Financial Statements +Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 4, 2012, the U.S. Department of Interior, or DOI, issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. +Other Regulation of the Oil and Natural Gas Industry +The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. +The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. +Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices. +Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: +• +the location of wells; +• +the method of drilling and casing wells; +• +the timing of construction or drilling activities, including seasonal wildlife closures; +• +the rates of production or “allowables”; +• +the surface use and restoration of properties upon which wells are drilled; +21 +Table of Contents +Index to Financial Statements +• +the plugging and abandoning of wells; and +• +notice to, and consultation with, surface owners and other third parties. +State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. +Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. +Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. +Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. +Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. +Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. +22 +Table of Contents +Index to Financial Statements +Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. +State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. +The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows. +Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore WCBB properties, we also have a $25.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $12.5 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $1,000,000 per occurrence ($1.5 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. +At the depths and in the areas in which we operate, and in light of the vertical and directional drilling that we undertake, we typically do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for five specific Southern Louisiana wells. In addition, it is currently anticipated that we will carry control of well coverage for all of our Utica Shale wells. We also require all of our third +23 +Table of Contents +Index to Financial Statements +party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. +We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters. This emergency response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. It has previously reported that it owns over 164 response vehicles, 65 response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage barge sets, allowing for storage of up to 248 barrels of recovered oil each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for the retainer and clean up services during 2012 and 2011 were approximately $85,000 and $220,000, respectively. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure at our WCBB field, we believe other companies would be available to us in the event our primary remediation company was unable to perform. +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. Additionally, we lease approximately 6,500 square feet of office space in other buildings in Oklahoma City. We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We lease 1,400 square feet of office space in St. Clairsville, Ohio that serves as our Ohio headquarters. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2012, we had 128 employees. An unrelated Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. During 2012, certain of our employees performed management and administrative services for affiliated companies for which we were reimbursed approximately $3.2 million. +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. \ No newline at end of file diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/item13.txt b/raw/filings/0000874499/2012/0001445305-13-000396/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..4a2f04df11e3a34b80e43e7cb8a0c34418a99503 --- /dev/null +++ b/raw/filings/0000874499/2012/0001445305-13-000396/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/item9a.txt b/raw/filings/0000874499/2012/0001445305-13-000396/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ca0f10d23e2800ae9f1dc8624ef51cde9082c2f6 --- /dev/null +++ b/raw/filings/0000874499/2012/0001445305-13-000396/item9a.txt @@ -0,0 +1,40 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. +As of December 31, 2012, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that, as of December 31, 2012, our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +67 +Table of Contents +Index to Financial Statements +Management's Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2012. +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2012 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2012, as stated in their accompanying report. +/s/ James D. Palm +/s/ Michael G. Moore +Name: +James D. Palm +Name: +Michael G. Moore +Title: +Chief Executive Officer +Title: +Chief Financial Officer +68 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2012 and our report dated February 28, 2013 expressed an unqualified opinion on those financial statements. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 28, 2013 +69 +Table of Contents +Index to Financial Statements \ No newline at end of file diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/rp_note.txt b/raw/filings/0000874499/2012/0001445305-13-000396/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2012/0001445305-13-000396/rpt_disclosure.txt b/raw/filings/0000874499/2012/0001445305-13-000396/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..f25846d374aede0e7637bf02fab0a156de55c682 --- /dev/null +++ b/raw/filings/0000874499/2012/0001445305-13-000396/rpt_disclosure.txt @@ -0,0 +1,138 @@ +Certain Relationships and Related Transactions +Review and Approval of Related Party Transactions +The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be substantively applied to each transaction +reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the Company. Further, the Company’s Code of +Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party transactions. +The Company’s policy is that all of its employees and directors, as well as their family members, must avoid any activity that is or has the +appearance of conflicting with the Company’s business interest. This policy is included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform the +designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the Code +of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give rise to +a conflict of interest. +Further, under the Audit Committee Charter, the Audit Committee is responsible for reviewing and monitoring +compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the Audit Committee, reviews and approves all +relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members, +have a direct or indirect material interest. The board of directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as +they determine in the good faith exercise of their discretion. +Services Provided to Us by Affiliated Entities +We contract with Athena Construction, L.L.C., or Athena, to provide barge services in our West Cote Blanche Bay, or WCBB, and Hackberry +fields located along the Louisiana Gulf Coast. During 2012, we paid Athena $4,675,000 and owed an additional $1,453,000 for such services at December 31, 2012. Athena is controlled by Wexford Capital LP, or Wexford. Our relationship with +Wexford is described below under the heading “Our Relationships with Wexford and its Affiliates.” +Caliber Development Company, LLC, +or Caliber, provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. We also lease office space from Caliber. During 2012, we paid Caliber $73,000 and owed an additional $12,000 as of December 31, 2012. Caliber is +an entity controlled by Wexford. +During the first six months of 2012, Black Fin P&A, LLC, or Black Fin, performed plugging and +abandonment services for us at our WCBB field. We paid Black Fin $1,086,000 for such services. In mid-2012, we ceased using Black Fin’s services. Black Fin is an entity controlled by Wexford. +Our Investments in Affiliated Entities and Related Agreements +On May 7, 2012, we entered into a contribution agreement with Diamondback Energy, Inc., or Diamondback, in which we agreed to contribute to Diamondback, prior to the closing of its initial public +offering, or the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. On October 11, 2012, we completed this contribution, which we refer to in this proxy statement as the Contribution. At the closing of the +Contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a +38 +Table of Contents +promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash +adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of the Contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a +result of this post-closing adjustment. In connection with the Contribution, we and Diamondback entered into an investor rights agreement in which we have the right, for so long as we beneficially own more than 10% of Diamondback’s outstanding +common stock, to designate one individual as a nominee to serve on Diamondback’s board of directors. Such nominee, if elected to Diamondback’s board, will also serve on each committee of the board so long as he or she satisfies the +independence and other requirements for service on the applicable committee of the board. So long as we have the right to designate a nominee to Diamondback’s board and there is no nominee of ours actually serving as a Diamondback director, we +will have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. We are also entitled to certain information rights and Diamondback granted us certain demand and +“piggyback” registration rights obligating Diamondback to register with the SEC any shares of Diamondback common stock that we own. As of April 1, 2013, we held approximately 21.4% of Diamondback’s outstanding common stock. As of +December 11, 2012, Wexford beneficially owned approximately 44.4% of Diamondback’s outstanding common stock. Diamondback was the operator of all of the acreage in the Permian Basin that we contributed in the Contribution. As operator of +these properties, Diamondback was responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which we held an interest. For the year ended December 31, 2012, we paid Diamondback +approximately $49,418,000 for these services and, at December 31, 2012, we owed $269,000 for these services. +Effective as of +November 1, 2007, we and an entity then-known as Windsor Permian LLC (which is currently a wholly-owned subsidiary of Diamondback and now known as Diamondback O&G LLC) entered into an area of mutual interest agreement to jointly acquire oil +and gas leases in the Permian Basin. The agreement provided that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and +expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. During 2012, we acquired approximately 5,000 net acres from Windsor Permian LLC under the terms of this agreement for an +aggregate of $5,410,000. This area of mutual interest agreement was terminated in connection with the Contribution. +We own a 24.9999% +interest in Grizzly Oil Sands ULC, or Grizzly, a Canadian unlimited liability company, through our wholly owned subsidiary Grizzly Holdings, Inc. The remaining interests in Grizzly are owned by Grizzly Oils Sands Inc., an entity owned by certain +investment funds managed by Wexford. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray. On October 5, 2012, we entered into an agreement +with Grizzly in which we committed to make monthly payments from October 2012 to May 2013 in the aggregate amount of approximately $8.5 million to fund our proportionate share of the construction and development costs of the Algar Lake facility. We +also agreed to fund our proportionate share of any unfunded cost overruns in excess of $2.0 million. The remaining aggregate commitment at December 31, 2012 was approximately $6.3 million. During 2012, we paid an aggregate of $103,915,000 under +this agreement and in cash calls, increasing our total net investment in Grizzly to $172,766,000. +We have a 23.5% indirect ownership interest +in Tatex Thailand II, LLC, or Tatex II. The remaining indirect interests in Tatex II are owned by entities controlled by Wexford. Tatex II holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas +exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering 243,000 acres which includes the Phu Horm Field. During 2012, we received $820,000 in distributions in respect of our interest in +Tatex II. +We have a 17.9% ownership interest in Tatex Thailand III, or Tatex III. Tatex III owns a concession covering approximately 490,000 +acres in Thailand. Approximately 68.7% of the remaining interests in Tatex III are owned by an entity controlled by Wexford. During the year ended December 31, 2012, we paid $626,000 in cash calls to Tatex III. +39 +Table of Contents +During the third quarter of 2011, we purchased a 25% ownership interest in Bison Drilling and Field Services +LLC, or Bison. In April 2012, we increased our ownership interest in Bison to 40% for a payment of $6,152,000. The remaining interests in Bison are owned by entities controlled by Wexford. Bison owns and operates drilling rigs. During the year ended +December 31, 2012, we paid $1,373,000 in cash calls, increasing our total net investment in Bison to $13,518,000. In addition, we entered into a loan agreement with Bison, effective May 15, 2012, under which Bison may borrow funds from us. +Interest accrues at LIBOR plus 0.28% or 8%, whichever is lower, and is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan has a maturity date of January 31, 2015. We loaned Bison $1,594,000 in principal +amount during the first nine months of 2012, all of which was repaid by Bison during the third quarter of 2012 along with $1,000 in accrued interest. No borrowings were outstanding as of December 31, 2012 under this loan agreement with Bison. +We have a 25% ownership interest in Muskie Proppant LLC, or Muskie (formerly known as Muskie Holdings LLC). The remaining interests in Muskie +are owned by entities controlled by or affiliated with Wexford. Muskie holds certain assets, real estate and rights in a lease covering land in Wisconsin that is prospective for mining oil and natural gas fracture grade sand. During the year ended +December 31, 2012, we paid $6,213,000 in cash calls, increasing our total net investment in Muskie to $7,320,000. +During the first +quarter of 2012, we and entities controlled by or affiliated with Wexford formed Timber Wolf Terminals LLC, or Timber Wolf. We have a 50% interest in Timber Wolf and our initial investment during 2012 was $1,000,000. Timber Wolf was formed to +operate a crude/condensate terminal and a sand transloading facility in Ohio. +During the first quarter of 2012, we purchased a 22.5% +ownership interest in Windsor Midstream LLC, or Midstream, at a cost of $7,021,000. The remaining interests in Midstream are owned by entities controlled by Wexford. Midstream owns a 28.4% interest in MidMar Gas LLC, a gas processing plant in West +Texas. During the year ended December 31, 2012, we paid $1,819,000 in cash calls, increasing our total net investment in Midstream to $9,503,000. +During 2012, we and other individuals and entities formed Stingray Pressure Pumping LLC, or Stingray Pressure, Stingray Cementing LLC, or Stingray Cementing, and Stingray Logistics LLC, or Stingray +Logistics, which provide well completion services, well cementing services and well services, respectively. Our initial interest in each Stingray entity is 50% and we are the manager of each entity. During the year ended December 31, 2012, we +paid (a) $14,500,000 in cash calls to Stingray Pressure, increasing our total net investment in Stingray Pressure to $13,265,000, (b) $3,269,000 in cash calls to Stingray Cementing, increasing our net investment in Stingray Cementing to +$3,110,000, and (c) $983,000 in cash calls to Stingray Logistics, increasing our net investment in Stingray Logistics to $947,000. The remaining interests in each of the Stingray entities are owned by the president of the entity, by Mike +Liddell, our Chairman of the Board, and by individuals and entities affiliated with Wexford. Mr. Liddell is not entitled to any distribution in respect of his interest in any Stingray entity until we and the Wexford affiliates have received +repayment in full of our and their respective capital accounts with respect to such entity. Thereafter, all future distributions to which the Wexford affiliates may be entitled from the applicable entity will be paid 90% to the Wexford affiliates +and 10% to Mr. Liddell. Mr. Liddell will not receive, or be entitled to receive, any distributions in respect of our interest in any Stingray entity. +During the second quarter of 2012, we and Windsor Ohio LLC, an entity controlled by Wexford, formed Blackhawk Midstream LLC, or Blackhawk. We are the manager of Blackhawk and have an initial 50% ownership +interest. Blackhawk coordinates gathering, compression, processing and marketing activities for us in connection with the development of our Utica Shale acreage. During the year ended December 31, 2012, we paid $436,000 in cash calls to +Blackhawk. +40 +Table of Contents +Area of Mutual Interest and Related Agreements +Effective April 1, 2010, we entered into an area of mutual interest agreement with Windsor Niobrara LLC, or Windsor Niobrara, to jointly acquire oil +and gas leases in Northwest Colorado for the purpose of exploring, exploiting and producing oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a +50/50 basis. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this +agreement, we and Windsor Niobrara also entered into a development agreement, effective as of April 1, 2010, pursuant to which we and Windsor Niobrara agreed to jointly develop the contract area, and we agreed to act as the operator under the +terms of a joint operating agreement. As operator, we are responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2012, we billed Windsor Niobrara +$7,545,000 and, at December 31, 2012, Windsor Niobrara owed us $173,000 for these services. Windsor Niobrara is controlled by Wexford. +Effective July 1, 2008, we entered into an acquisition team agreement with Everest Operations Management LLC, or Everest, to identify and evaluate +potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, the Company and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, +the party whose acquisition team identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate +share of the acquisition or divestiture consideration. The agreement has a one-year term unless earlier terminated by either party upon 30 days notice. Affiliates of Everest were billed approximately $1,087,000 under this acquisition team agreement +during the year ended December 31, 2012. +Utica Shale Transactions +Windsor Ohio LLC, or Windsor Ohio, an entity controlled by Wexford, participated with us in the acquisition of certain leasehold interests in acreage located in the Utica Shale in Ohio. We are the +operator of this acreage in the Utica Shale. As operator, we are responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2012, we billed Windsor Ohio +approximately $163,650,000 for these services. At December 31, 2012, Windsor Ohio owed us approximately $6,520,000 for these services. Liddell Investments, LLC, or Liddell Investments, an entity controlled by our Chairman of the Board, has a +10% interest in Windsor Ohio. For the year ended December 31, 2012, we billed approximately $2,020,000 to Liddell Investments directly for these services and, at December 31, 2012, all of this amount was owed to us. For the year ended +December 31, 2012, we paid Liddell Investments approximately $102,000 in respect of its interest in Windsor Ohio. +In December 2012, we +entered into a purchase and sale agreement with Windsor Ohio pursuant to which Windsor Ohio agreed to sell to us approximately 30,000 net acres which, at the time, represented 50% of its right, title and interest in and to certain leasehold +interests in the Utica Shale in Eastern Ohio. The parties subsequently amended that agreement to provide for our acquisition of approximately 7,000 additional net acres. The aggregate purchase price for these interests was approximately $372.0 +million, subject to certain adjustments. Windsor Ohio retained its interest in 14 existing wells, along with certain acreage surrounding those wells. As discussed above, Windsor Ohio participated with us in the acquisition of our Utica Shale leases +and through this transaction, we acquired an additional approximately 27.5% interest in these leases, increasing our working interest in the acreage to 77.7%. The transaction closed on December 24, 2012. All of the acreage included in this +transaction was nonproducing at the time of the acquisition and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the completion of title review after the closing, +approximately $53.9 million of the purchase price was placed in an escrow account. The escrow account will terminate on April 30, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title +defects resulting from the title review. The transaction was approved by a special committee of our board of directors, which engaged independent counsel and financial advisors to assist with its review. +41 +Table of Contents +In February 2013, we entered into another purchase and sale agreement with Windsor Ohio pursuant to which +Windsor Ohio agreed to sell to us approximately 22,000 net acres representing 100% of its right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio for approximately $220.4 million, subject to certain +adjustments. This transaction, which closed on February 15, 2013, excluded Windsor Ohio’s interest in 14 existing wells and 16 proposed future wells together with certain acreage surrounding those wells. Through this most recent +transaction, we acquired an additional approximately 16.2% interest in our Utica Shale leases, increasing our working interest in the acreage to 93.8%. All of the acreage included in this transaction was nonproducing at the time of the acquisition +and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the completion of title review after the closing, approximately $33.6 million of the purchase price has been placed +in an escrow account. The escrow account will terminate on May 1, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review. The transaction was also +approved by a special committee of our board of directors, which engaged independent counsel and financial advisors to assist with its review. As noted above, Mr. Liddell, our Chairman of the Board, has a 10% interest in Windsor Ohio. We have +been advised by Windsor Ohio that Mr. Liddell received approximately $2.9 million in respect of this interest in connection with the December 2012 transaction and approximately $19.3 million in respect of this interest in connection with the +February 2013 transaction. Mr. Liddell may also receive up to an additional $5.4 million and $3.4 million in connection with these transactions, respectively, upon termination of the escrow accounts. +Rhino Exploration LLC, or Rhino, an affiliate of Wexford, has also participated with us in the acquisition of certain leasehold interest in acreage +located in the Utica Shale in Ohio. We are the operator of this acreage in the Utica Shale. As operator, we are responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended +December 31, 2012, we billed Rhino approximately $4,443,000 for these services. At December 31, 2012, Rhino owed us approximately $4,257,000 for these services. +Our Relationships with Wexford and its Affiliates +Charles E. Davidson is the Chairman +and Chief Investment Officer of Wexford. He beneficially owned approximately 13.3% of our outstanding common stock as of December 31, 2011 and approximately 9.5% of our outstanding common stock as of March 13, 2012, which ownership +interest was reduced to less than 1% of our outstanding common stock as of December 31, 2012. Wexford is the manager of the Wexford-controlled entities described above. As manager, Wexford has the exclusive authority to, among other things, +purchase, hold and dispose of the assets of each such entity. Mr. Liddell, our Chairman of the Board, was the operating member of Windsor Permian prior to the Contribution, is the operating member of Athena, Caliber, Black Fin, Windsor +Midstream, Windsor Ohio, DB Energy and Windsor Niobrara, which we refer to collectively as the “operating member companies,” and the chairman or an officer of Everest, Bison, Timber Wolf, Windsor Midstream, Windsor Ohio and Windsor +Niobrara. Mr. Liddell also holds an equity interest in each of the operating member companies, Bison, Muskie and Timber Wolf, and an indirect profits interest in Grizzly Oil Sands, Inc. As a result, all distributions made by these entities and +payable to the Wexford members are to be first made to the Wexford members in accordance with their respective ownership interests until they have received amounts equal to their respective capital contributions. Thereafter, distributions are to be +made 90% to the Wexford members in accordance with their respective ownership interests and 10% to Mr. Liddell. Except as described above with respect to Windsor Ohio, Mr. Liddell is not currently entitled to, and has not received, +distributions from any of these entities. Transactions between us and these entities are reviewed and approved by our independent directors. Mr. Liddell is not standing for re-election as one of our directors and his tenure as Chairman of the Board +will end upon the conclusion of our 2013 Annual Meeting of Stockholders. +42 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/filing.txt b/raw/filings/0000874499/2013/0001445305-14-000751/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..b0041d8aa1f58ac8943c174e4d381e9716b4d07b --- /dev/null +++ b/raw/filings/0000874499/2013/0001445305-14-000751/filing.txt @@ -0,0 +1,7020 @@ +10-K +1 +gpor-12312013x10k.htm +10-K +GPOR-12.31.2013-10K +Table of Contents +Index to Financial Statements +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +(Mark One) +ý +ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2013 +OR +¨ +TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to +Commission File Number 000-19514 +Gulfport Energy Corporation +(Exact Name of Registrant As Specified in Its Charter) +Delaware +73-1521290 +(State or Other Jurisdiction of +Incorporation or Organization) +(IRS Employer +Identification Number) +14313 North May Avenue, Suite 100 +Oklahoma City, Oklahoma +73134 +(Address of Principal Executive Offices) +(Zip Code) +(405) 848-8807 +(Registrant Telephone Number, Including Area Code) +Securities registered pursuant to Section 12(b) of the Act: +Title of Each Class +Name of Each Exchange on Which Registered +Common Stock, par value $0.01 per share +The NASDAQ Stock Market LLC +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. +Yes ý No ¨ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes ý No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): +Large Accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý +The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 28, 2013 , based on the closing price of the common stock on the NASDAQ Global Select Market on June 28, 2013 , the last business day of the registrant’s most recently completed second fiscal quarter ($47.09 per share), was $3,651,716,766,540.00 . +As of February 21, 2014 , 85,217,533 shares of the registrant’s common stock were outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of Gulfport Energy Corporation’s Proxy Statement for the 2014 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K. +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +TABLE OF CONTENTS +Page +FORWARD-LOOKING STATEMENTS +1 +PART I +2 +ITEM 1. +BUSINESS +2 +ITEM 1A. +RISK FACTORS +21 +ITEM 1B. +UNRESOLVED STAFF COMMENTS +42 +ITEM 2. +PROPERTIES +42 +ITEM 3. +LEGAL PROCEEDINGS +48 +ITEM 4. +MINE SAFETY DISCLOSURES +49 +PART II +50 +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +50 +ITEM 6. +SELECTED FINANCIAL DATA +51 +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +53 +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +66 +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +68 +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +68 +ITEM 9A. +CONTROLS AND PROCEDURES +68 +ITEM 9B. +OTHER INFORMATION +70 +PART III +71 +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +71 +ITEM 11. +EXECUTIVE COMPENSATION +71 +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +71 +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +71 +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +71 +PART IV +72 +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +72 +Signatures +S-1 +Index to Consolidated Financial Statements +F-1 +Exhibit Index +E-1 +i +Table of Contents +Index to Financial Statements +FORWARD-LOOKING STATEMENTS +Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. +These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. +Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “ Risk Factors ” and “ Management's Discussion and Analysis of Financial Condition and Results of Operations ” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. +1 +Table of Contents +Index to Financial Statements +PART I +ITEM 1. +BUSINESS +General +We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of crude oil, natural gas liquids and natural gas in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale in Eastern Ohio and along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. In addition, we have producing properties in the Niobrara Formation of Northwestern Colorado and the Bakken Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, an equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and natural gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO, and interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +On February 26, 2014, we entered into an agreement to acquire approximately 8,200 additional net acres in the Utica Shale. See "- Recent Developments" below. As of February 27, 2014, after giving pro forma effect to the acquisition, we would have owned leasehold interests in approximately 167,700 gross (165,400 net) acres in the Utica Shale in Eastern Ohio. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2013, had spud 66 wells, 38 of which were completed and are producing. In 2013, we spud 52 gross (39 net) wells, of which 24 were completed as producing wells, 11 were waiting on completion, one was non-productive, nine were waiting on horizontal rigs and seven were still being drilled as of December 31, 2013. As of February 14, 2014, we had spud six gross (five net) wells all of which were still drilling. In addition, 61 gross (3.5 net) wells were drilled by other operators on our Utica Shale acreage during 2012 and 2013. +We have seven rigs under contract on our Utica Shale acreage. We currently intend to drill 85 to 95 gross (64 to 71 net) wells on our Utica Shale acreage in 2014 for an estimated aggregate cost of $594.0 million to $634.0 million. +Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2013 was approximately 984,528 net barrels of oil equivalent, or BOE, or 10,701 BOE per day, 68% of which was from natural gas and 32% of which was from oil and natural gas liquids, or NGLs. During January 2014, our average daily net production from the Utica Shale was approximately 15,897 BOE, 27% of which was from oil and NGLs and 73% of which was from natural gas. +In 2013, at our WCBB field, we recompleted 87 wells and drilled 22 wells. Of the 22 new wells drilled at WCBB in 2013, 21 were completed as producing wells and one was being drilled at year end. In the fourth quarter of 2013, production at WCBB was approximately 346,736 BOE, or an average of 3,769 BOE per day, 97% of which was from oil and 3% of which was from natural gas. During January 2014, our average net daily production at WCBB was approximately 3,158 BOE, 100% of which was from oil. During 2014, we currently anticipate drilling 22 to 24 wells at our WCBB field for an estimated aggregate cost of $42.0 million to $45.0 million. +In 2013, at our East Hackberry field, we recompleted 61 wells and drilled 16 wells. Of the 16 new wells drilled at East Hackberry during 2013, 13 were completed as producing wells, one was non-productive, one was waiting on completion and one was being drilled at year end. In the fourth quarter of 2013, net production at East Hackberry was approximately 188,536 BOE, or an average of 2,049 BOE per day, 90% of which was from oil and 10% of which was from natural gas. During January 2014, our average net daily production at East Hackberry was approximately 2,431 BOE, 93% of which was from oil and 7% of which was from natural gas. During 2014, we currently anticipate drilling ten to twelve wells for an estimated aggregate cost of $24.0 million to $26.0 million. +In 2013, at our West Hackberry field, we recompleted two wells and drilled two wells as of December 31, 2013. Of the two new wells drilled at West Hackberry during 2013, both were productive. In the fourth quarter of 2013, net production at West Hackberry was approximately 6,466 BOE, or an average of 70 BOE per day, 100% of which was from oil. During January 2014, our average net daily production at West Hackberry was approximately 110 BOE, 100% of which was from oil. +2 +Table of Contents +Index to Financial Statements +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2013, we held leases for approximately 7,481 net acres. During the year ended December 31, 2013, there were no wells spud on our Niobrara Formation acreage. In the fourth quarter of 2013, net production from our Niobrara Formation acreage was approximately 4,552 BOE, or an average of 49 BOE per day, 100% of which was from oil. During January 2014, our average net daily production from our Niobrara Formation acreage was approximately 55 BOE, 100% of which was from oil. During 2014, we currently do not anticipate drilling any wells in the Niobrara Formation. +As of December 31, 2013, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 13 wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2013, our net production from this acreage was approximately 2,412 BOE, or an average of 26 BOE per day, of which 90% was from oil and 10% was from NGLs. During January 2014, our average daily net production from our Bakken Formation acreage was approximately 93 BOE, of which 88% was from oil and 12% was from natural gas. +As of December 31, 2013, we owned approximately 7.2% of the outstanding common stock of Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to the Diamondback IPO. See Notes 4 and 5 to our consolidated financial statements included elsewhere in this report for additional information regarding our investment in Diamondback. +We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2013 , Grizzly had approximately 830,000 net acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada and had drilled an aggregate of 255 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. Grizzly has three oil sands projects in various stages of development. At Grizzly's 11,300 barrel per day steam-assisted gravity drainage, or SAGD, oil sand project at Algar Lake, steam generation commenced and was circulating through the plant and well pad facilities by year-end 2013 and reservoir steam injection commenced in January 2014, with first production expected by the end of the first quarter of 2014. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. At May River, an initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. A 29 well delineation drilling program was completed in the first quarter of 2013 over the development application area and a 2D seismic program covering approximately 80 kilometers is currently underway to more fully define the development area. At the Thickwood thermal project, activities have included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is developing a rail loadout facility in Conklin, Alberta, which we refer to as the Windell Terminal, and a rail to barge off-load facility on the lower Mississippi River, which we refer to as the Paulina Terminal. Construction of the 15,000 barrel per day truck to rail transloading Windell Terminal proximate to its May River lease, is expected to be completed and ready for operation by the end of the first quarter of 2014. In the U.S. Gulf Coast, Grizzly has begun engineering design work of the 40,000 barrel per day rail/barge Paulina terminal project located on the lower Mississippi River and has filed development permits. +We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. +We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. In March 2011, the second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. However, despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. In October 2013, Tatex III spud the TEW-K well, located to the south of the TEW-E well. The well tested gas at non-commercial rates. During drilling, the well flowed gas with rates as high as 20 MMcf per day of gas; however, no acceptable sustainable rate was established. +3 +Table of Contents +Index to Financial Statements +In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the first quarter of 2013, we participated in the formation of Stingray Energy Services LLC, or Stingray Energy, with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure Pumping LLC, or Stingray Pressure, Stingray Cementing LLC, or Stingray Cementing, and Stingray Logistics LLC, or Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk Midstream LLC, or Blackhawk, and Timber Wolf Terminals, LLC, or Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie (formerly known as Muskie Holdings LLC), which is engaged in the processing and sale of hydraulic fracturing grade sand. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. +As of December 31, 2013, we had 38.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $696.9 million and associated standardized measure of discounted future net cash flows of approximately $578.5 million , excluding reserves attributable to our interests in Diamondback, Grizzly, Tatex II and Tatex III. See "Item 2. Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Recent Developments +On February 26, 2014, we entered into a binding letter of intent with Rhino Resources Partners LP, or Rhino, to acquire approximately 8,200 net acres in the Utica Shale of Eastern Ohio and approximately 1,000 BOEPD of production during January 2014 for a total purchase price of $185.0 million, subject to closing adjustments. These assets constitute all the rights, title and interest in leasehold and mineral interests covered by all oil and gas leases owned by Rhino in the Utica Shale in Eastern Ohio, together with all wells, production, data, equipment, contracts permits and privileges relating to the ownership of such properties. We are the operator of substantially all of this acreage. We plan to fund this acquisition from existing cash on hand. The acquisition is expected to close by the end of March 2014, however the transaction remains subject to completion of due diligence and other closing conditions, and there can be no assurance that the transaction will be completed. +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2013 reflecting our net interest in our principal producing oil and natural gas properties in the Utica Shale in Eastern Ohio, along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +NGLs +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +MBOE +MBOE +MBOE +MBOE +Utica Shale (4) +51.61/63.9 +38 +24 +1 +1 +10,627 +8,694 +23,983 +2,696 +5,674 +32,353 +West Cote Blanche Bay Field (5) +80.108/100 +110 +110 +201 +201 +5,668 +5,668 +241 +3,737 +— +3,978 +E. Hackberry Field (6) +80.309/100 +47 +47 +86 +86 +3,931 +3,931 +142 +1,170 +— +1,312 +W. Hackberry Field +83.333/100 +4 +4 +19 +19 +1,192 +1,192 +— +470 +— +470 +Niobrara Formation +36.77/47.85 +6 +3 +1 +1 +3,448 +1,724 +25 +186 +— +211 +Bakken Formation (4) +2.16/1.795 +13 +0.3 +— +— +1,862 +163 +13 +86 +— +99 +Overrides/Royalty Non-operated +Various +266 +0.45 +2 +0.06 +— +— +4 +1 +1 +6 +Total +484 +188.75 +310 +308.06 +26,728 +21,372 +24,408 +8,346 +5,675 +38,429 +(1) +Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. +(2) +Includes three gross and net wells at WCBB that are producing intermittently. +4 +Table of Contents +Index to Financial Statements +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 13% of our acreage is developed acreage and has been held by production. +(4) Includes NRI/WI from wells that have been drilled or in which we have elected to participate. +(5) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). +(6) +NRI shown is for producing wells. +Utica Shale (Eastern Ohio) +Location and Land +As of December 31, 2013, we had acquired leasehold interests in approximately 152,000 gross (143,000 net) acres in the Utica Shale in Eastern Ohio, +Area History +Based on the estimates published by the Ohio Department of Natural Resources, or ODNR, which were last updated in 2012, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2012 and 2013, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio. As of February 9, 2013, the ODNR reported that in the Utica Shale in Ohio there were 65 producing horizontal wells, 236 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 15 horizontal wells that were being drilled and an additional 272 horizontal wells that had been permitted. +Geology +The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. +Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. +The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west. +The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. +The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale. +5 +Table of Contents +Index to Financial Statements +Facilities +There are standard land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well site pads inclusive of storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression and applicable metering. +Recent and Future Activities +We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2013, had spud 66 wells, 38 of which were completed and are producing. In 2013, we spud 52 gross (39 net) wells, of which 24 were completed and are productive, 11 were waiting on completion, one was non-productive, nine were waiting on horizontal rigs and seven were still being drilled as of December 31, 2013. As of February 14, 2014, we had spud six gross (five net) wells during 2014 all of which were still drilling. In addition, 49 gross (2.6 net) wells were drilled by other operators on our Utica Shale acreage during 2013. +We have seven rigs under contract on our Utica Shale acreage. We currently intend to drill 85 to 95 gross (64 to 71 net) wells on our Utica Shale acreage in 2014. +Production Status +Aggregate net production from the Utica Shale during the three months ended December 31, 2013 was approximately 984,528 BOE, or 10,701 BOE per day, 68% of which was from natural gas and 32% of which was from oil and NGLs. From January 1, 2014 through January 31, 2014, our average daily net production from the Utica Shale was approximately 15,897 BOE, 27% of which was from oil and NGLs and 73% of which was from natural gas. The increase in January 2014 production is a result of our 2013 drilling activities. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,047 wells drilled as of December 31, 2013, 949 were completed as producing wells. As a result, the field has a historic success rate of 91% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2013, we drilled 236 new wells, 215 of which were productive, for a 91% success rate. As of December 31, 2013, estimated field cumulative gross production was 195.3 MMBOE and 237.0 Bcf of gas. Of the 1,047 wells drilled in WCBB as of December 31, 2013, 107 were producing, 201 were shut-in, three were producing intermittently and five were being used as salt water disposal wells. The other 731 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition +6 +Table of Contents +Index to Financial Statements +and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,047 wells that had been drilled in the field as of December 31, 2013, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2013, we recompleted 87 gross and net wells and drilled 22 gross and net wells at WCBB. Of the 22 new wells drilled at WCBB in 2013, 21 were completed as producers and one was being drilled at year end. As of February 14, 2014, we had recompleted nine wells during 2014, drilled one well and were in the process of drilling one additional well in our WCBB field. Of the 22 wells drilled in 2013, 22 were considered deep wells. The 21 productive wells, with total depths ranging from 8,100 to 10,104 feet, have approximately 2,225 feet of aggregate apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells at WCBB during 2014. +Production Status +In the fourth quarter of 2013, our production at WCBB was approximately 346,736 net BOE, or an average of 3,769 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2014 through January 31, 2014, our average net daily production at WCBB was approximately 3,158 BOE, 100% of which was from oil. The decrease in average net daily production in January 2014 was due to normal production declines and the impact of extreme winter conditions. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.309% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2013, we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic data. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production +7 +Table of Contents +Index to Financial Statements +through 2013 was over 3,426 MBOE and 330.4 Bcf of casinghead gas production. A total of 254 wells have been drilled on our portion of the field. As of December 31, 2013, 47 wells had daily production, 86 were shut-in and three had been converted to salt water disposal wells. The remaining 118 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, five natural gas compressors, dehydration units and salt water disposal systems. +Recent and Future Activity +During 2013 at East Hackberry, we recompleted 61 gross and net wells and drilled 14 gross and net land wells and two gross and net wells on water. Of the 16 wells drilled during 2013, 13 were completed as producing wells, one was non-productive, one was waiting on completion and one was being drilled at year end. As of February14, 2014, we had recompleted seven wells during 2014, drilled one well and were in the process of drilling one additional well in our East Hackberry field. We currently intend to drill ten to twelve gross and net wells in our East Hackberry field during 2014. +Production Status +In the fourth quarter of 2013, our net production at East Hackberry was approximately 188,536 BOE, or an average of 2,049 BOE per day, 90% of which was from oil and 10% of which was from natural gas. From January 1, 2014 through January 31, 2014, our average net daily production at East Hackberry was approximately 2,431 BOE, 93% of which was from oil and 7% of which was from natural gas. The increase in production in 2014 is a result of our 2013 drilling and recompletion activities. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 83.333% NRI) in 1,192 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2013 was 344 MBOE and 140 Bcf of natural gas. There have been 40 wells drilled to date on our portion of West Hackberry. Currently, four of such wells are producing, 19 are shut-in and one has been converted to a saltwater disposal well. The remaining 16 wells have been plugged and abandoned. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +8 +Table of Contents +Index to Financial Statements +Recent and Future Activity +During 2013 at West Hackberry, we recompleted two gross and net wells and drilled two gross and net wells both of which were productive as of year end. As of February14, 2014, no new wells had been drilled in our West Hackberry field. +Production Status +In the fourth quarter of 2013, our net production at West Hackberry was approximately 6,466 BOE, or an average of 70 BOE per day, 100% of which was from oil. From January 1, 2014 through January 31, 2014, our average net daily production at West Hackberry was approximately 110 BOE and was 100% from oil. +Facilities +We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. +Niobrara Formation (Northwestern Colorado) +Location and Land +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2013, we held leases for approximately 7,481 net acres. In 2013, no wells were spud on our Niobrara Formation acreage. +Area History +The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. +Geology +The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect to oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. +Production Status +In the fourth quarter of 2013, our net production from our Niobrara Formation acreage was approximately 4,552 BOE, or an average of 49 BOE per day, 100% of which was from oil. From January 1, 2014 through January 31, 2014, our average daily net production from our Niobrara Formation acreage was approximately 55 BOE, 100% of which was from oil. +Facilities +There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +9 +Table of Contents +Index to Financial Statements +Recent and Future Activity +We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We do not anticipate drilling any wells in the Niobrara Formation during 2014. +Bakken Formation +Location and Land +The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. As of December 31, 2013, we held approximately 864 net acres, interests in 13 wells and an overriding royalty interests in certain existing and future wells. +Production Status +In the fourth quarter of 2013, our net production from our Bakken Formation acreage was approximately 2,412 BOE, or an average of 26 BOE per day, of which 90% was from oil and 10% was from NGLs. From January 1, 2014 through January 31, 2014, our average net daily production from this acreage was approximately 93 BOE, of which 88% was from oil and 12% was from natural gas. +Facilities +There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activities +Six gross (1.3 net) wells were drilled on our Bakken Formation acreage in 2013. As of February 14, 2014, no new wells had been drilled on our Bakken Formation acreage in 2014. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2013: +Field +State +Parish/County +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Deer Island +Louisiana +Terrebonne +3.125 +% +— +% +1 +— +Napoleonville +Louisiana +Assumption +— +% +2.5 +% +3 +— +Crest +Texas +Ochiltree +2 +% +— +% +1 +— +Eagle City South +Oklahoma +Dewey +1.04 +% +— +% +1 +— +Fay South +Oklahoma +Blaine +0.301 +% +— +% +1 +— +Squaw Cheek +Oklahoma +Blaine +0.694 +% +— +% +1 +— +Our Equity Investments +Permian Basin . On October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of December 31, 2013, we owned approximately 7.2% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. +10 +Table of Contents +Index to Financial Statements +Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc., an entity owned by certain investment funds managed by Wexford Capital LP, or Wexford. As of December 31, 2013 , Grizzly had approximately 830,000 net acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada and had three oil sands projects in various stages of development and had drilled an aggregate of 255 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. Regulatory approval of Grizzly's 11,300 barrel per day steam-assisted gravity drainage, or SAGD, oil sand project at Algar Lake was received in the fourth quarter of 2011. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Steam generation commenced and was circulating through the plant and well pad facilities by year-end 2013. Reservoir steam injection commenced in January 2014 with first production expected by the end of the first quarter of 2014. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. A 29 well delineation drilling program was completed in the first quarter of 2013 over the development application area and a 2D seismic program covering approximately 80 kilometers is currently underway to more fully define the development area. At the Thickwood thermal project, Grizzly's activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is developing the Windell Terminal, a rail loadout facility in Conklin, Alberta, and the Paulina Terminal, a rail to barge off-load facility on the lower Mississippi River. Construction of the 15,000 barrel per day Windell Terminal, proximate to its May River lease, is expected to be completed and ready for operation by the end of the first quarter of 2014. In the U.S. Gulf Coast, Grizzly has begun engineering design work of the 40,000 barrel per day Paulina Terminal project located on the lower Mississippi River and has filed development permits. +Thailand . We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet per day. For 2013, net gas production was approximately 88 MMcf per day and condensate production was 382 barrels per day. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +We own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. In March 2011, the second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. However, despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. In October 2013, Tatex III spud the TEW-K well, located to the south of the TEW-E well. The well tested gas at non-commercial rates. During drilling, the well flowed gas with rates as high as 20 MMcf per day of gas; however, no acceptable sustainable rate was established. +Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the first quarter of 2013, we participated in the formation of Stingray Energy with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure, Stingray Cementing and Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk and Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our +11 +Table of Contents +Index to Financial Statements +Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Midstream which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. +Competition +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. +Marketing and Customers +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our Southern Louisiana oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI trade month average differential less $2.00 per barrel for transportation. Shell is the purchaser of our Utica Shale oil and pays us NYMEX less $10.00 per barrel. Markwest Utica purchases our Utica Shale NGLs. We have agreements in place with various purchasers for our Utica Shale natural gas production. In 2013, our Utica Shale natural gas was sold under monthly, seasonal and long term contracts and, as needed, through trades. Pricing was based on Dominion South Point (Dominion Eastern and Dominion Transmission) or Texas Eastern M2 Zone, plus or minus the market differential. As discussed below under "- Transportation and Takeaway Capacity," we have entered into agreements to transport our natural gas production out of the Utica Basin in 2014 and beyond. +During the year ended December 31, 2013, we sold approximately 99% of our oil production to Shell Trading Company, or Shell, 100% of our natural gas liquids production to Markwest Utica and 32%, 31% and 17% of our natural gas production to Sequent Energy Management, L.P., or Sequent, Hess and Interstate Gas Supply, Inc., or Interstate Gas, respectively. During the year ended December 31, 2012, we sold approximately 92% and 8% of our oil production to Shell and Diamondback O&G LLC (a wholly-owned subsidiary of Diamondback formerly known as Windsor Permian LLC), or Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G and 41%, 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G, and 50%, 27% and 22% of our natural gas production to Hilcorp Energy Company, Chevron and Diamondback O&G, respectively. +As of December 31, 2013, we had approximately 183,00 MMBtu per day of firm sales contracted with third parties. Of these sales, 33,000 MMBtu per day, 100,000 MMBtu per day and 50,000 MMBtu per day expire in 2015, 2016 and 2017, respectively. +Transportation and Takeaway Capacity +In Ohio, as of December 31, 2013, we had entered into firm transportation contracts for 2014, 2015 and 2016 for an aggregate of approximately 427,000 MMBtu per day, 677,000 MMBtu per day and 650,000 MMBtu per day, respectively. We are actively seeking to secure additional firm transportation contracts for incremental volumes from our Utica Shale acreage +12 +Table of Contents +Index to Financial Statements +and expect to finalize additional contracts in the first half of 2014. Our primary long-haul firm transportation commitments include the following: +• +194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities that will allow us to reach the Michigan, Chicago and Wisconsin natural gas markets in 2014. +• +200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities beginning in mid-2014 and, by the end of 2014, we expect to be able to reach Gulf Coast delivery points with the full contracted volumes; and +• +50,000 MMBtu per day of firm capacity to the Gulf Coast through Texas Gas Transmission facilities beginning in 2016. +Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Utica Basin position. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, and in the Utica Shale in Eastern Ohio, the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in +13 +Table of Contents +Index to Financial Statements +conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. In November 2012, we and other entities involved in our WCBB field operations received a government subpoena, to which we have responded, for the production of documents and other information related primarily to a discharge of produced water that was allegedly identified by the U.S. Coast Guard in March 2012. We have had continuing communications with the government concerning these events and have been informed that the government may pursue claims against us and certain of our field personnel. We are continuing to cooperate with the investigation. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in April 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. +The Oil Pollution Act, or OPA, is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential +14 +Table of Contents +Index to Financial Statements +environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. +Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail under the caption “ -Regulation of Hydraulic Fracturing .” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. +Climate Change . Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutants” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court granted review of certain issues related to EPA’s authority to regulate such emissions from stationary sources. Oral argument on the issues before the Supreme Court was heard on February 24, 2014, and a decision is expected by July 2014. +Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. +In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our +15 +Table of Contents +Index to Financial Statements +operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +Endangered Species Act +Environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities on federal lands may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. +Occupational Safety and Health Act +We are also subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements. +Regulation of Hydraulic Fracturing +Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. On February 12, 2014, the EPA published revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. The EPA is encouraging state programs to review and consider use of the draft guidance. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. +16 +Table of Contents +Index to Financial Statements +In August 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that may be responsive to some of these requests. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. +Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 16, 2013, the U.S. Department of Interior, or DOI, issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. DOI is expected to issue a final rule in 2014. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any +17 +Table of Contents +Index to Financial Statements +failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. +Other Regulation of the Oil and Natural Gas Industry +The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. +The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. +Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices. +Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: +• +the location of wells; +• +the method of drilling and casing wells; +• +the timing of construction or drilling activities, including seasonal wildlife closures; +• +the rates of production or “allowables”; +• +the surface use and restoration of properties upon which wells are drilled; +• +the plugging and abandoning of wells; and +• +notice to, and consultation with, surface owners and other third parties. +State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. +Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. +18 +Table of Contents +Index to Financial Statements +Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. +Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. +Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. +Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. +Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. +State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. +The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. +19 +Table of Contents +Index to Financial Statements +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows. +Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million which includes sudden and accidental pollution for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore WCBB properties, we also have a $38.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $12.5 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $12.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $250,000 per occurrence ($1.25 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. +We carry control of well insurance for all of our Utica Shale wells and several Southern Louisiana wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. +We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean up services during 2013 and 2012 were approximately $0.7 million and $0.1 million, respectively. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. To supplement our planning and operation activities in Ohio, we also actively manage an incident response planning program and coordinate with applicable state agency personnel on spills and releases. We also participate in Ohio's Emergency Planning and Community Right to Know Act (EPCRA) program, which includes reporting of various materials used or stored on-site as well as notification to state and local emergency response centers, such as local fire departments, for emergency planning purposes. +20 +Table of Contents +Index to Financial Statements +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. Additionally, we lease approximately 20,800 square feet of office space in other buildings in Oklahoma City. We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We recently completed construction of an approximately 5,700 square foot office building in St. Clairsville, Ohio that will serve as our Ohio headquarters. In addition, we lease 1,400 square feet of office space in St. Clairsville, Ohio. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2013 , we had 118 employees. An unrelated Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. During 2013, certain of our employees performed management and administrative services for affiliated companies for which we were reimbursed approximately $1.4 million. +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. +ITEM 1A. +RISK FACTORS +Risks Related to our Business and Industry +The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability. +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including: +• +worldwide and domestic supplies of oil and natural gas; +• +the level of prices, and expectations about future prices, of oil and natural gas; +• +the cost of exploring for, developing, producing and delivering oil and natural gas; +• +the expected rates of declining current production; +• +weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas operations over a wide area; +• +the level of consumer demand; +• +the price and availability of alternative fuels; +• +technical advances affecting energy consumption; +• +risks associated with operating drilling rigs; +• +the availability of pipeline capacity and other transportation facilities; +• +the price and level of foreign imports; +• +domestic and foreign governmental regulations and taxes; +• +the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; +• +speculative trading in crude oil and natural gas derivative contracts; +• +political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and Russia; and +• +the overall domestic and global economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past six years, the posted price for West Texas intermediate light sweet crude oil, which we refer to herein as West Texas Intermediate or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $13.31 per MMBtu in July 2008. During 2012, West Texas Intermediate prices ranged from $80.48 to $108.99 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.80 to $3.80 per MMBtu. On December 31, 2013, the West Texas Intermediate posted price for crude oil was $98.55 per barrel and the Henry Hub spot market price of natural gas was $4.19 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. +21 +Table of Contents +Index to Financial Statements +Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition. +Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition. +Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves. +Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. For example, we currently estimate our exploration and production capital expenditures for 2014 to be in the range of $675.0 million to $725.0 million and an additional $225.0 million to $275.0 million for acreage acquisitions in the Utica Shale. +Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity and debt securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including: +• our proved reserves; +• the volume of oil and natural gas we are able to produce from existing wells; +• the prices at which oil and natural gas are sold; and +• our ability to acquire, locate and produce new reserves; and +• our ability to borrow under our credit facility. +We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2014 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all. +If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies. +22 +Table of Contents +Index to Financial Statements +Our success depends on finding, developing or acquiring additional reserves, which requires significant capital expenditures. +Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. If we are unable to replace our current production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase. +Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth. +There is intense competition for acquisition opportunities in our industry. The successful acquisition of producing properties requires an assessment of several factors, including: +• recoverable reserves; +• future oil and natural gas prices and their applicable differentials; +• operating costs; and +• potential environmental and other liabilities. +The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. +Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. +No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods. +23 +Table of Contents +Index to Financial Statements +Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities. +Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. +We may incur losses as a result of title defects in the properties in which we invest. +It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. +Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss. +If we are unable to complete capital projects in a timely manner, our business, financial condition, results of operations and cash flows could be materially and adversely affected. +Delays related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays may arise as a result of unpredictable factors, many of which are beyond our control, including: +• +denial of or delay in receiving requisite regulatory approvals and/or permits; +• +unplanned increases in the cost of construction materials or labor; +• +disruptions in transportation of components or construction materials; +• +adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers; +• +shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; +• +market-related increases in a project's debt or equity financing costs; and +• +nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors. +Any one or more of these factors could have a significant impact on our ongoing capital projects. +Our Canadian oil sands projects are complex undertakings and may not be completed at our estimated cost or at all. +We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc., an entity owned by certain investment funds managed by Wexford. As of December 31, 2013 Grizzly had approximately 830,000 net acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately $191.5 million as of December 31, 2013 . Grizzly has three oil sands projects in various states of development. At Grizzly's 11,300 barrel per day SAGD oil sand project at Algar Lake, reservoir steam injection commenced in January 2014 with first production expected by the end of the first quarter of 2014. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres and an initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. At Grizzly's Thickwood thermal project, a development application +24 +Table of Contents +Index to Financial Statements +for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. In addition, Grizzly is developing a rail loadout facility in Conklin, Alberta and a rail to barge off-load facility on the lower Mississippi River. These are complex projects and additional financing may be required. There can be no assurance that such financing, if required, could be obtained on commercially reasonable terms or at all, or that if one or more of these projects are completed that they will be successful or that we realize a return on our investment. +The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations. +The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for and wage rates of qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations. +We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues. +Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Michael G. Moore, our Interim Chief Executive Officer, President and Chief Financial Officer, our geophysicists or our lead operations personnel, could disrupt our operations resulting in a loss of revenues . Our executives are not restricted from competing with us if they cease to be employed by us, except under certain limited circumstances prohibiting competition while making use of our trade secrets. We are party to an employment agreement with each of these executive officers. As a practical matter, however, employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees. +Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production. +There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information herein represents estimates prepared by (i) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields at each of December 31, 2013, 2012 and 2011, (ii) Ryder Scott with respect to our Utica Shale acreage at December 31, 2013 and 2012 and our Permian Basin acreage at December 31, 2011 (which acreage has been contributed to Diamondback as described in Item 1. “Our Equity Investments”) and (iii) our personnel with respect to our overriding royalty and non-operated interests at December 31, 2013, 2012 and 2011. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. +Estimates of reserves as of year-end 2013, 2012 and 2011 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2013, 2012 and 2011, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. +25 +Table of Contents +Index to Financial Statements +The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2013, 2012 and 2011 on an average price equal to the unweighted arithmetic average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2013, 2012 and 2011, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as: +• +actual prices we receive for oil and natural gas; +• +the amount and timing of actual production; +• +supply of and demand for oil and natural gas; and +• +changes in governmental regulations or taxation. +The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. +SEC rules could limit our ability to book additional proved undeveloped reserves in the future. +SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe. +The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. +Approximately 35.2% of our total estimated proved reserves at December 31, 2013, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be realized. +There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. +Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly's lands cannot be determined at this time. +26 +Table of Contents +Index to Financial Statements +The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced. +The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field and from our Utica Shale acreage. In October 2006, for example, a natural gas line in our WCBB field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. With respect to our Utica Shale acreage where we are focusing a significant portion of our exploration and development activity, historically there has been no or only limited infrastructure in this area and the commencement of production from our initial and subsequent wells on our Utica Shale acreage has been delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we will be required to shut in or curtail production from the impacted field(s). Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations. +Substantially all of our producing properties are located in Eastern Ohio and Louisiana, making us vulnerable to risks associated with operating in these regions. +Our largest fields by production are located in Eastern Ohio and approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available. +Our identified drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. +We have identified over 800 drilling locations on our Louisiana, Ohio and Western Colorado properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business. +Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations. +Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including: +• +unusual or unexpected geological formations; +• +loss of drilling fluid circulation; +27 +Table of Contents +Index to Financial Statements +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delivery delays of equipment and services; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. +Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits. +Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. We may face liability for environmental damage caused by previous owners of properties purchased by us, which liabilities may or may not be covered by insurance. For example, we are a defendant in a private civil lawsuit in Cameron Parish, Louisiana brought against over 20 oil and natural gas companies for alleged surface contamination as distributed elsewhere in this report. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. +In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. +Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities. +We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to +28 +Table of Contents +Index to Financial Statements +significant liabilities, penalties and other sanctions under applicable laws. In November 2012, we and other entities involved in our WCBB field operations received a government subpoena, to which we have responded, for the production of documents and other information related primarily to an alleged discharge of produced water in March 2012. We have had continuing communications with the government concerning these events and have been informed that the government may pursue claims against us and certain of our field personnel. We are continuing to cooperate with the investigation. Additionally, in September 2013, we entered a compliance agreement with the Ohio Division of Oil and Gas Resources Management concerning aspects of our operations at seven drilling sites in Ohio. See “-We have entered into a compliance agreement with the Ohio Division of Oil and Gas Resources Management and, if we fail to comply with the conditions of the compliance agreement, all or part of our drilling and producing operations in the State of Ohio may be suspended.” +Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected. +We have entered into a compliance agreement with the Ohio Division of Oil and Gas Resources Management and, if we fail to comply with the conditions of the compliance agreement, all or part of our drilling and producing operations in the State of Ohio may be suspended. +In September 2013, we entered into a compliance agreement with the Ohio Division of Oil and Gas Resources Management, or the Division, concerning aspects of our operations at seven drilling sites in Ohio. We had previously notified the Division of brine contamination at these drilling sites. After receipt of this notification, the Division conducted an investigation and determined that certain contaminants were escaping from underneath the containment liners at these locations. In the compliance agreement, we agreed, among other things, to conduct our production operations in compliance with all requirements of applicable regulations, implement a remediation plan and make a payment of $250,000. We are continuing to work with the Division to fulfill our obligations under the compliance agreement and to enhance our materials handling protocols. If the Chief of the Division determines that we have failed to comply with the conditions set forth in the compliance agreement, the Chief may suspend all or part of our drilling and production operations in the State of Ohio for a period determined by the Chief, and we could incur additional penalties and costs. +Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns. +We acquire significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells. +Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations. +29 +Table of Contents +Index to Financial Statements +Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production. +Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas. +Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future. +We have been an early entrant into the Utica Shale in Eastern Ohio. As a result, our drilling results in this area may vary, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. +We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2013, had spud 66 wells, 38 of which had been completed and were producing. In 2013, we spud 52 gross (39 net) wells, of which 24 were completed and are productive, one was non-productive, nine were waiting on a horizontal rig, 11 were waiting on completion and seven were still being drilled as of December 31, 2013. As of February 14, 2014, we had spud six gross (five net) wells during 2014 all of which were still drilling. In addition, 49 gross (2.6 net) wells were drilled by other operators on our Utica Shale acreage during 2013. We have seven rigs under contract on our Utica Shale acreage. We currently intend to drill 85 to 95 gross (64 to 71 net) wells on our Utica Shale acreage in 2014. While our costs to acquire undeveloped acreage in this emerging play have generally been less than those of later entrants into a developing play, our drilling results in this area are more uncertain than drilling results in areas that are developed and producing. Since the Utica Shale has limited production history and since we have limited experience drilling in this play, it is difficult to predict our future drilling results. Our cost of drilling, completing and operating wells in this area may be higher than initially expected, and the value of our undeveloped acreage in the Utica Shale may decline if drilling results are unsuccessful. We cannot assure you that unproved property acquired, or undeveloped acreage leased, by us in the Utica Shale or other emerging plays will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells. +Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application. +Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, the following: +• effectively controlling the level of pressure flowing from particular wells; +• landing our wellbore in the desired drilling zone; +• staying in the desired drilling zone while drilling horizontally through the formation; +• running our casing the entire length of the wellbore; and +• being able to run tools and other equipment consistently through the horizontal wellbore. +30 +Table of Contents +Index to Financial Statements +Risks that we face while completing our wells include, but are not limited to, the following: +• the ability to fracture stimulate the planned number of stages; +• the ability to run tools the entire length of the wellbore during completion operations; and +• the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage +The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future. +We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties. +We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including: +• +the timing and amount of capital expenditures; +• +the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; +• +the operator's expertise and financial resources; +• +approval of other participants in drilling wells; +• +selection of technology; and +• +the rate of production of the reserves. +In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited. +A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income. +A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. While none of our Utica Shale acreage leases are scheduled to expire until 2015, at that time 32% of our total Utica Shale undeveloped acreage as of December 31, 2013 will be subject to expiration, with 68% of such acreage expiring thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. As of December 31, 2013, leases representing 33%, 4%, 22%, 4% and 37%, respectively, of our total Niobrara Formation undeveloped acreage are scheduled to expire in 2014, 2015, 2016, 2017 and thereafter. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable +31 +Table of Contents +Index to Financial Statements +terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. +Conservation measures and technological advances could reduce demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. +Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities. +Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. +Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive. +Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See Item 1. "Business-Regulations-Environmental Matters and Regulation" and Item 1. "Business-Regulation-Other Regulation of The Oil and Natural Gas Industry" for a description of the laws and regulations that affect us. See also “-Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities” above regarding a pending U.S. Environmental Protection Agency investigation regarding an alleged discharge of produced water in our WCBB field and a consent order we entered into with the Ohio Department of Natural Resources regarding our operations in the Utica Shale. +Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. +Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and natural gas commissions. The Environmental Protection Agency, or EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. On February 12, 2014, the EPA published revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address +32 +Table of Contents +Index to Financial Statements +the purported unique risks of diesel fuel injection during the hydraulic fracturing process. The EPA is encouraging state programs to review and consider use of the draft guidance. At the same time, the White House Council on Environmental Quality is conducting an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. +In August 2012, the EPA published final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. +Several states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources, or ODNR, issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area and the ODNR continues to monitor earthquake activity in proximity to wells undergoing hydraulic fracturing. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 6, 2013, the U.S. Department of Interior, or DOI, issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. DOI is expected to issue a final rule +33 +Table of Contents +Index to Financial Statements +in 2014. We plan to use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. +Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate. +Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves +The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. +The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading Commission, or CFTC, has issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The CFTC's final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, although the CFTC has indicated that it intends to appeal the court's decision and that it believes the Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position limits, which may reduce our ability to enter into hedging transactions. +In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose +34 +Table of Contents +Index to Financial Statements +other requirements that are more burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. +The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows. +Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation. +The fiscal year 2014 budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. +The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations. +In February 2013, the Governor of the State of Ohio proposed a plan to enact new severance taxes in fiscal 2014 and 2015. However, the Ohio State Senate did not include a severance tax increase in the version of the budget bill that it passed on June 7, 2013. The possibility remains that the severance tax increase on horizontal wells will resurface during compromise talks on the budget. +The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce. +Continuing political and social attention to the issue of climate change has resulted in existing and pending international agreements and national, regional, state and local regulation associated with greenhouse gas emissions. While we are subject to certain federal GHG monitoring and reporting requirements, we do not believe that our operations are adversely impacted by existing climate change requirements and initiatives and, at this time, it is not possible to predict with certainty how potential future laws or regulations addressing GHG emissions would impact our businesses or demand for the oil and natural gas we produce. In particular, for example, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court granted review of certain issues related to EPA’s authority to regulate such emissions from stationary sources. Oral argument on the issues before the Supreme Court was heard on February 24, 2014, and a decision is expected by July 2014. +35 +Table of Contents +Index to Financial Statements +Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. The EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards for new coal-fired and natural-gas fired power plants, which could have an adverse effect on our financial condition and results of operations. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. +In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. +Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations. +We face extensive competition in our industry. +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. +36 +Table of Contents +Index to Financial Statements +We depend upon a limited number of customers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce. +The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI differential less $2.00 per barrel for transportation. Shell is the purchaser of our Utica Shale oil and pays us NYMEX less $10.00 per barrel. Markwest Utica purchases our Utica Shale NGLs. We have agreements in place with various purchasers for our Utica Shale natural gas production. In 2013, our Utica Shale natural gas was sold under monthly, seasonal and long term contracts and, as needed, through trades. Pricing is based on Dominion South Point (Dominion Eastern and Dominion Transmission) or Texas Eastern M2 Zone, plus or minus the market differential. As discussed above under "- Transportation and Takeaway Capacity," we have entered into agreements to transport our natural gas production out of the Utica Basin in 2014 and beyond. During the year ended December 31, 2013 , we sold approximately 99% of our oil production to Shell, 100% of our natural gas liquids production to Markwest Utica, and 32% , 31% and 17% of our natural gas production to Sequent, Hess and Interstate Gas, respectively. During 2012, we sold approximately 92% and 8% of our oil production to Shell and Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G, and 41%, 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G and 22%, 27% and 50% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. +Our method of accounting for oil and natural gas properties may result in impairment of asset value. +We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting natural gas to barrels at the ratio of six Mcf of natural gas to one barrel of oil. +Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for 2013, 2012 and 2011 adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. If prices of oil, natural gas and natural gas liquids decrease, we may be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of operations. +Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. +Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. +37 +Table of Contents +Index to Financial Statements +We have entered into forward sales contracts and fixed price swaps and may in the future enter into additional contracts for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. +We use fixed price derivative contracts to reduce price volatility associated with certain of our oil and natural gas sales. For the period from January 2014 through March 2014, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $104.75. For the period from April 2014 through December 2014 we entered into fixed price contracts for 2,000 barrels of oil per day at a weighted average price of $101.50. For January of 2014, we entered into fixed price swaps for 65,000 MMBtu per day at a weighted average price of $4.04. For the period from February 2014 through December 2014, we entered into fixed price swaps for 105,000 MMBtu per day at a weighted average price of $4.01. For the period from January 2015 through December 2015, we entered into fixed price swaps for 125,000 MMBtu per day at a weighted average price of $4.03. For the period from January 2016 through March 2016, we entered into fixed price swaps for 105,000 MMBtu per day at a weighted average price of $4.04. For April of 2016 we entered into fixed price swaps for 95,000 MMBtu per day at a weighted average price of $4.04. Under the 2014 contracts, we have hedged approximately 41% to 49% of our estimated 2014 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging ,” and related pronouncements. +Our hedging transactions expose us to counterparty credit risk. +Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. +A terrorist attack or armed conflict could harm our business. +Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. +Conservation measures and technological advances could reduce demand for oil and natural gas. +Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. +Loss of our information and computer systems could adversely affect our business. +We are dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business. +38 +Table of Contents +Index to Financial Statements +Risks Relating to Our Indebtedness +Our substantial level of indebtedness could adversely affect our business, financial condition, results of operations and prospects. +As of December 31, 2013, we had total indebtedness (net of associated accrued discount and premium) of approximately $299.2 million , including $297.2 million attributable to our senior notes, and borrowing base availability of $150.0 million under our secured revolving credit facility, under which no borrowings are outstanding. +Our outstanding indebtedness could have important consequences to you, including the following: +• +our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including restrictive covenants, could result in a default under our secured revolving credit facility or the senior note indenture; +• +the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business; +• +our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets; +• +we must use a substantial portion of our cash flow from operations to pay interest on the Notes and our other indebtedness, which will reduce the funds available to us for operations and other purposes; +• +our high level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt; +• +our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited; +• +our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and +• +we may be vulnerable to interest rate increases, as our borrowings under our secured revolving credit facility are at variable interest rates. +Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations and prospects. +In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically, the lenders under our secured revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or litigation. +Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness. +Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including the senior notes, depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our revolving credit facility and the indenture governing the senior notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to +39 +Table of Contents +Index to Financial Statements +engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition. +Restrictive covenants in our secured revolving credit facility, the indenture governing the senior notes and in future debt instruments may restrict our ability to pursue our business strategies. +Our secured revolving credit facility and the indenture governing the senior notes limit, and the terms of any future indebtedness may limit, our ability, among other things, to: +• +incur or guarantee additional indebtedness; +• +make certain investments; +• +declare or pay dividends or make distributions on our capital stock; +• +prepay subordinated indebtedness; +• +sell assets including capital stock of restricted subsidiaries; +• +agree to payment restrictions affecting our restricted subsidiaries; +• +consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; +• +enter into transactions with our affiliates; +• +incur liens; +• +engage in business other than the oil and gas business; and +• +designate certain of our subsidiaries as unrestricted subsidiaries. +We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indenture governing the senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business. +A breach of any of these restrictive covenants could result in default under our revolving credit facility. If default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indenture governing the senior notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving credit facility and the senior notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness. +Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination. +Availability under our revolving credit facility is currently subject to a borrowing base of $150.0 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2013, we had no outstanding borrowings under our revolving credit facility. We intend to continue borrowing under our revolving credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further if, the outstanding borrowings under our revolving credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results. +We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate the risks that we and our subsidiaries face. +We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of our revolving credit facility and the indenture governing the senior notes restrict, but in each case do not completely prohibit, us from doing so. As of December 31, 2013, our borrowing base under our revolving credit facility was set at $150.0 million and we had no +40 +Table of Contents +Index to Financial Statements +borrowings outstanding under this facility. In addition, the indenture governing the senior notes allows us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indenture governing the senior notes also allows us to incur certain other additional secured debt and allows us to have subsidiaries that do not guarantee the senior notes and which may incur additional debt, which would be structurally senior to the senior notes. In addition, the indenture governing the senior notes does not prevent us from incurring other liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks equally with the senior notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the senior notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. +Our borrowings under our revolving credit facility expose us to interest rate risk. +Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility. Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the eurodollar rates are elected, the eurodollar rates. As of December 31, 2013, we had no variable interest rate borrowings outstanding; therefore, an increase in interest rates would not have impacted our interest expense. As of December 31, 2013, we did not hedge our interest rate risk. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our revolving credit facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. +Risks Related to Our Common Stock +If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile. +Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: +• +changes in oil and natural gas prices; +• +changes in production levels; +• +changes in governmental regulations and taxes; +• +geopolitical developments; +• +the level of foreign imports of oil and natural gas; and +• +conditions in the oil and natural gas industry and the overall economic environment. +Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. +We do not currently pay dividends on our common stock and do not anticipate doing so in the future. +We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock. +A change of control could limit our use of net operating losses. +As of December 31, 2013, we had a net operating loss, or NOL, carry forward of approximately $4.2 million for federal income tax purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. +41 +Table of Contents +Index to Financial Statements +Future sales of our common stock may depress our stock price. +We have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of February 21, 2014, there were 85,217,533 shares of our common stock issued and outstanding, excluding 503,636 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan and 210,241 shares issuable upon exercise of outstanding options to purchase our common stock granted under our Amended and Restated 2005 Stock Incentive Plan. +We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects. +We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock. +In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders. +The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. +ITEM 1B. +UNRESOLVED STAFF COMMENTS +None. +ITEM 2. +PROPERTIES +Additional information regarding our properties is included in Item 1. "Business" above and in Note 4 of the notes to our consolidated financial statements included in this report, which information is incorporated herein by reference. +Proved Oil and Natural Gas Reserves +SEC Rule-Making Activity +In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the following: +• +Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis. +• +Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. +• +Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history. +42 +Table of Contents +Index to Financial Statements +• +Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. +• +Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction. +We adopted the rules effective December 31, 2009, as required by the SEC. +Evaluation and Review of Reserves. +Reserve estimates at December 31, 2013 were prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields (16% of our proved reserves at December 31, 2013 ), by Ryder Scott with respect to our assets in the Utica Shale in Eastern Ohio (84% of our proved reserves at December 31, 2013 ) and by our personnel with respect to our overriding royalty and non-operated interests (less than 1% of our proved reserves at December 31, 2013 ). +NSAI and Ryder Scott are independent petroleum engineering firms. Copies of their summary reserve reports are included as Exhibit 99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. +We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI and Ryder Scott, our independent reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our WCBB, Hackberry and Niobrara fields and our assets in the Utica Shale. Our internal technical team members meet with NSAI and Ryder Scott periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI and Ryder Scott for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our proved reserves attributable to our other minority interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 35 years of reservoir and operations experience and our geophysical staff has over 60 years combined industry experience. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. +Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following: +• +review and verification of historical production data, which data is based on actual production as reported by us; +• +preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision; +• +review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; +• +direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; and +• +verification of property ownership by our land department. +The following table sets forth our estimated proved reserves at December 31, 2013 , 2012 and 2011 : +Year Ended December 31, +2013 +2012 +2011 +Oil +(MBbls) +Natural +Gas +(MMcf) +Natural Gas Liquids (MBbls) +Oil +(MBbls) +Natural +Gas +(MMcf) +Natural Gas Liquids (MBbls) +Oil +(MBbls) +Natural +Gas +(MMcf) +Natural Gas Liquids (MBbls) +Proved developed +5,609 +94,552 +3,527 +5,175 +18,482 +44 +6,780 +6,152 +705 +Proved undeveloped +2,737 +51,894 +2,148 +2,931 +15,289 +101 +7,174 +9,576 +2,086 +Total (1) +8,346 +146,446 +5,675 +8,106 +33,771 +145 +13,954 +15,728 +2,791 +43 +Table of Contents +Index to Financial Statements +Year Ended December 31, +2013 +2012 +2011 +Total net proved oil and natural gas reserves (MBOE) (1) +38,429 +13,879 +19,367 +PV-10 value (in millions) (2) +$ +696.9 +$ +436.8 +$ +490.5 +Standardized measure (in millions) (3) +$ +578.5 +$ +348.6 +$ +376.7 +_____________________ +(1) +Estimates of reserves as of year-end 2013 , 2012 and 2011 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2013 , 2012 and 2011 , respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2013 , 2012 and 2011 . Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. +(2) +Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports for the years ended December 31, 2013 , 2012 and 2011 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $96.78 per barrel and $3.67 per MMBtu for 2013 , $91.32 per barrel and $2.76 per MMBtu for 2012 and $96.19 per barrel and $4.12 per MMBtu for 2011 , and in each case adjusted by lease for transportation fees and regional price differentials. +PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measure-standardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value: +December 31, +2013 +2012 +2011 +(In thousands) +Standardized measure of discounted future net cash flows +$ +578,466 +$ +348,641 +$ +376,681 +Add: Present value of future income tax discounted at 10% +118,445 +88,206 +113,791 +PV-10 value +$ +696,911 +$ +436,847 +$ +490,472 +(3) +The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. +The above table does not include proved reserves net to our interest in Diamondback, Tatex II, Tatex III or Grizzly. For further discussion of our interest in Tatex II, Tatex III and Grizzly, see Item 1. “ Business-Our Equity Investments .” +The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “ Risk Factors ” contained elsewhere in this Form 10-K. We have not filed any +44 +Table of Contents +Index to Financial Statements +estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year. +Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves, or PUDs, at December 31, 2013 , 2012 and 2011 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 19 to our consolidated financial statements included in this report. Also contained in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves. Additional information regarding our proved reserves can be found in Item 7. “ Management's Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations ” and “- Critical Accounting Policies and Estimates ” included in this report. +Proved Undeveloped Reserves (PUDs) +As of December 31, 2013 , our proved undeveloped reserves totaled 2,737 MBOE of oil, 51,894 MMcf of natural gas and 2,148 MBOE of NGLs, for a total of 13,534 MBOE. Approximately 87% of our PUDs at year-end 2013 were located in our Utica field, 6% were located in WCBB, 5% were located in our East Hackberry field and 1% of our PUDs were located in our Niobrara field. PUDs will be converted from undeveloped to developed as the applicable wells begin production. Changes in PUDs that occurred during 2013 were primarily due to: +• +Additions of 8,331 MBOE attributable to 2013 acquisitions and extensions in our Utica field and additions of 403 MBOE attributable to 2013 extensions in our Louisiana fields; +• +Conversion of approximately 341 MBOE attributable to PUDs into proved developed reserves; +• +Downward revisions to estimates of approximately 213 MBOE; and +• +Exclusion of 225 MBOE attributable to 13 PUD locations that were not scheduled to be drilled within the next five years. +Costs incurred relating to the development of PUDs were approximately $43.5 million in 2013 . Estimated future development costs relating to the development of PUDs are projected to be approximately $135.4 million in 2014, $68.7 million in 2015, $8.5 million in 2016 and $8.5 million in 2017. +All PUD drilling locations are scheduled to be drilled prior to the end of 2018. +As of December 31, 2013 , 7% of our total proved reserves were classified as proved developed non-producing. +Production, Prices, and Production Costs +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +2013 +2012 +2011 +Production Volumes: +Oil (MBbls) +2,317 +2,323 +2,128 +Gas (MMcf) +8,891 +1,108 +878 +Natural gas liquids (MGal) +13,416 +2,714 +2,468 +Oil equivalents (MBOE) +4,118 +2,573 +2,333 +Average Prices: +Oil (per Bbl) +$ +96.74 +(1) +$ +104.46 +(1) +$ +104.33 +(1) +Gas (per Mcf) +$ +2.36 +(1) +$ +2.91 +$ +4.37 +Natural gas liquids (per Gal) +$ +1.27 +$ +0.98 +$ +1.25 +Oil equivalents (per BOE) +$ +63.68 +$ +96.63 +$ +98.13 +Production Costs: +Average production costs (per BOE) +$ +6.48 +$ +9.45 +$ +8.96 +Average production taxes and midstream costs (per BOE) +$ +9.22 +$ +11.43 +$ +11.29 +Total production and midstream costs and production taxes (per BOE) +$ +15.70 +$ +20.88 +$ +20.25 +45 +Table of Contents +Index to Financial Statements +(1) +Includes various derivative contracts at a weighted average price of: +Per barrel +January – December 2013 +$ +100.90 +January – December 2012 +$ +108.31 +January – December 2011 +$ +86.96 +Per MMBtu +January – December 2013 +$ +4.00 +Excluding the effect of fixed price swaps, the average price for 2013 would have been $104.51 per barrel of oil, $3.73 per Mcf of gas and $70.99 per BOE. The total volume hedged for 2013 represented approximately 48% of our total sales volumes for the year. Excluding the effect of fixed price swaps, the average oil price for 2012 would have been $106.11 per barrel of oil and $98.12 per BOE. The total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the effect of fixed price swap contracts, the average oil price for 2011 would have been $107.13 per barrel of oil and $100.68 per BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. +The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2013: +Year Ended December 31, +2013 +2012 +2011 +WCBB +Net Production +Oil (MBbls) +1,251 +1,126 +1,258 +Gas (MMcf) +77 +260 +237 +NGL (Mgal) +— +— +— +Total (MBOE) +1,264 +1,169 +1,298 +Average Sales Price: +Oil (per Bbl) +$ +93.80 +$ +105.19 +$ +104.49 +Gas (per Mcf) +$ +3.55 +$ +2.89 +$ +4.16 +NGL (per Gal) +$ +— +$ +— +$ +— +Average Production Cost (per BOE) +$ +10.11 +$ +9.66 +$ +8.71 +Utica Shale +Net Production +Oil (MBbls) +315 +25 +— +Gas (MMcf) +8,439 +365 +— +NGL (Mgal) +13,384 +80 +— +Total (MBOE) +2,040 +87 +— +Average Sales Price: +Oil (per Bbl) +$ +83.67 +$ +78.21 +$ +— +Gas (per Mcf) +$ +2.29 +$ +2.99 +$ +— +NGL (per Gal) +$ +1.27 +$ +1.56 +$ +— +Average Production Cost (per BOE) +$ +3.57 +$ +8.30 +$ +— +46 +Table of Contents +Index to Financial Statements +Productive Wells and Acreage +The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the total gross and net developed and undeveloped acres as of December 31, 2013. +NRI/WI (1) +Productive +Oil Wells (2) +Productive +Gas Wells +Non-Productive +Oil Wells +Non-Productive +Gas Wells +Developed +Acreage (3) +Undeveloped +Acreage +Field +Percentages +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Gross +Net +Utica Shale (4) +51.61/63.9 +27 +17 +11 +7 +— +— +1 +1 +10,627 +8,694 +141,639 +134,541 +West Cote Blanche Bay Field (5) +80.108/100 +110 +110 +— +— +183 +183 +18 +18 +5,668 +5,668 +— +— +E. Hackberry Field (6) +80.309/100 +47 +47 +— +— +86 +86 +— +— +3,931 +3,931 +581 +581 +W. Hackberry Field +83.333/100 +4 +4 +— +— +19 +19 +— +— +1,192 +1,192 +— +— +Niobrara Formation (7) +36.77/47.85 +6 +3 +— +— +1 +1 +— +— +3,448 +1,724 +11,680 +5,757 +Bakken Formation (8) +2.16/1.795 +13 +0.3 +— +— +— +— +— +— +1,862 +163 +3,505 +701 +Overrides/Royalty Non-operated +Various +266 +0.45 +— +— +2 +0.06 +— +— +— +— +— +— +Total +473 +181.75 +11 +7 +291 +289.06 +19 +19 +26,728 +21,372 +157,405 +141,580 +(1) +Net Revenue Interest (NRI)/Working Interest (WI). +(2) +Includes three gross and net wells at WCBB that are producing intermittently. +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 13% of our acreage is developed acreage and has been perpetuated by production. +(4) +None of our Utica acreage is scheduled to expire until 2015, at which time 32% of our total Utica Shale undeveloped acreage as of December 31, 2013 will be subject to expiration, with 68% of such acreage expiring thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. NRI/WI is from wells that have been drilled or in which we have elected to participate. +(5) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). +(6) +NRI shown is for producing wells. +(7) +The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. Leases representing 33%, 4%, 22%, 4% and 37% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2014, 2015, 2016, 2017 and thereafter, respectively. +(8) +NRI/WI is from wells that have been drilled or in which we have elected to participate. +Completed and Present Drilling and Recompletion Activities +The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return. +47 +Table of Contents +Index to Financial Statements +2013 +2012 +2011 +Gross +Net +Gross +Net +Gross +Net +Recompletions: +Productive +150 +150 +92 +92 +100 +96 +Dry +— +— +1 +0.5 +— +— +Total +150 +150 +93 +92.5 +100 +96 +Development: +Productive +132 +67 +70 +57 +82 +57 +Dry +2 +2 +8 +7 +3 +3 +Total +134 +69 +78 +64 +85 +60 +Exploratory: +Productive +3 +2.7 +19 +6 +1 +1 +Dry +— +— +— +— +— +— +Total +3 +2.7 +19 +6 +1 +1 +Title to Oil and Natural Gas Properties +It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations. +ITEM 3. +LEGAL PROCEEDINGS +In September 2013, we entered into a compliance agreement with the Ohio Division of Oil and Gas Resources Management, or the Division, concerning aspects of our operations at seven drilling sites in Ohio. See "Item 1A. Risk Factors" for a description of this matter, the compliance agreement and certain risks involved. +The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR maintains that we paid approximately $1.8 million less in severance taxes under fixed price terms than the severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any liability to the LDR for underpayment of severance taxes and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. We have maintained our right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against us seeking $2.3 million in severance taxes, plus interest and court costs. We filed a response denying any liability to the LDR for underpayment of severance taxes. The LDR had taken no further action on this lawsuit since filing its petition other than propounding discovery requests to which we have responded. Since serving discovery requests on the LDR and receiving the LDR's responses in 2012, there has been no further activity on the case and no trial date has been set. +In December 2010, the LDR filed two identical lawsuits against us in different venues to recover allegedly underpaid severance taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the lawsuit filed by the LDR in 2009 discussed in the paragraph above, we deny all liability and will vigorously defend the lawsuit. The cases are in the early stages, and we have not yet filed a response to the recent lawsuits. The LDR filed motions to stay the lawsuits before we filed any responsive pleadings. Although there had been no activity on either of these lawsuits for years, in September 2013, the LDR moved to dismiss one of the identical lawsuits it filed in the 19th Judicial District Court in 2010, amended the petition it filed in the 15th Judicial District Court in 2010, and served discovery requests on us. The LDR asserts that we underpaid severance taxes by nearly $12 million from 2007 to 2010. The LDR also asserts that we owe an additional $4.4 million and may be subject to additional penalties. The LDR's claims are still in their infancy and there has been no formal discovery. In February 2014, the LDR has asserted that Gulfport owes additional severance taxes for the cash settlements it received to terminate +48 +Table of Contents +Index to Financial Statements +forward sales contracts. We maintain that the LDR's claims are not well-grounded in fact or law and intend to aggressively defend the lawsuits. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for surface contamination in areas where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al.,38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name us as a defendant, alleges that the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. The plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and response costs and stigma damages. On December 7, 2010, we were served with a copy of the plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including us, bringing the total number of defendants to 21. It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income; attorney fees and expenses and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to us, current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, we filed a pleading challenging the legal sufficiency of the petitions on several grounds and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by us and similar pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue. In response, we and numerous defendants re-urged our pleadings challenging the legal sufficiency of the petitions. Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the court on May 25, 2011 and were denied. The court signed the written judgment on December 9, 2011. We noticed our intent to seek supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application. We filed our supervisory writ, which was denied by the Louisiana Third Circuit Court of Appeal and the Louisiana Supreme Court. The parties engaged in a non-binding mediation in July 2013 to discuss settlement and discussions are on-going. At this time, the parties are continuing to conduct discovery. The trial date has been continued to July 2014. +Due to the current stages of the LDR and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that may result. Adverse decisions in one or more of the above matters could have a material adverse effect on our financial condition or results of operations and management cannot determine the amount of loss, if any, that may result. +We have been named as a defendant in various other lawsuits related to our business. The resolution of these matters is not expected to have a material adverse effect on our financial condition or results of operations in future periods. +ITEM 4. +MINE SAFETY DISCLOSURES +Not applicable. +49 +Table of Contents +Index to Financial Statements +PART II +ITEM 5. +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Price Range of Common Stock +Our common stock is quoted on the NASDAQ Global Select Market under the symbol “GPOR.” The following table sets forth the high and low sale prices of our common stock for the periods presented: +Price Range of +Common Stock +High +Low +2012 +First Quarter +$ +37.63 +$ +27.66 +Second Quarter +29.66 +15.79 +Third Quarter +33.11 +18.17 +Fourth Quarter +40.73 +28.94 +2013 +First Quarter +$ +47.19 +$ +35.24 +Second Quarter +54.07 +43.98 +Third Quarter +64.73 +46.85 +Fourth Quarter +69.81 +53.93 +2014 +First Quarter (through February 27, 2014) +$ +65.78 +$ +52.28 +On February 27, 2014, the last reported sale price of our common stock on the NASDAQ Global Select Market was $62.13. +Unregistered Sales of Equity Securities and Use of Proceeds +None. +Repurchases of Equity Securities +None. +Holders of Record +At the close of business on February 25, 2014, there were 318 stockholders of record holding 85,217,533 shares of our outstanding common stock. There were approximately 36,191 beneficial owners of our common stock as of February 25, 2014. +Dividend Policy +We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends to the holders of our common stock. +50 +Table of Contents +Index to Financial Statements +ITEM 6. +SELECTED FINANCIAL DATA +You should read the following selected consolidated financial data in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the related notes appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2013 , December 31, 2012 and December 31, 2011 and the selected consolidated balance sheet data at December 31, 2013 and December 31, 2012 are derived from our audited consolidated financial statements appearing elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2010 and December 31, 2009 and the selected consolidated balance sheet data at December 31, 2011 , December 31, 2010 and December 31, 2009 are derived from our audited consolidated financial statements that are not included in this report. The historical data presented below is not indicative of future results. We did not pay any cash dividends on our common stock during any of the periods set forth in the following table. +Fiscal Year Ended December 31, +2013 +2012 +2011 +2010 +2009 +(In thousands, except share data) +Selected Consolidated Statements of Operations Data: +Revenues +$ +262,753 +$ +248,926 +$ +229,254 +$ +127,921 +$ +85,968 +Costs and expenses: +Lease operating expenses +26,703 +24,308 +20,897 +17,614 +16,316 +Production taxes +26,933 +28,957 +26,054 +13,823 +9,673 +Midstream transportation, processing and marketing +11,030 +443 +279 +143 +124 +Depreciation, depletion and amortization +118,880 +90,749 +62,320 +38,907 +29,225 +General and administrative +22,519 +13,808 +8,074 +6,063 +4,992 +Accretion expense +717 +698 +666 +617 +582 +Loss (gain) on sale of assets +508 +(7,300 +) +— +— +— +207,290 +151,663 +118,290 +77,167 +60,912 +Income from Operations +55,463 +97,263 +110,964 +50,754 +25,056 +Other (Income) Expense: +Interest expense +17,490 +7,458 +1,400 +2,761,000 +2,309,000 +Insurance recoveries +— +— +— +— +(1,050 +) +Interest income +(297 +) +(72 +) +(186 +) +(387 +) +(564 +) +(Income) loss from equity method investments +(213,058 +) +(8,322 +) +1,418 +977 +706 +(195,865 +) +(936 +) +2,632 +3,351 +1,401 +Income from Continuing Operations before Income Taxes +251,328 +98,199 +108,332 +47,403 +23,655 +Income Tax Expense (Benefit) +98,136 +26,363 +(90 +) +40 +28 +Income from Continuing Operations +153,192 +71,836 +108,422 +47,363 +23,627 +Discontinued Operations: +Loss on disposal of Belize properties, net of tax +— +3,465 +— +— +— +Net Income Available to Common Stockholders +$ +153,192 +$ +68,371 +$ +108,422 +$ +47,363 +$ +23,627 +Net Income Per Common Share—Basic: +$ +1.98 +$ +1.22 +$ +2.22 +$ +1.08 +$ +0.55 +Net Income Per Common Share—Diluted: +$ +1.97 +$ +1.21 +$ +2.20 +$ +1.07 +$ +0.55 +51 +Table of Contents +Index to Financial Statements +At December 31, +2013 +2012 +2011 +2010 +2009 +(In thousands) +Selected Consolidated Balance Sheet Data: +Total assets +$ +2,693,136 +$ +1,578,368 +$ +691,158 +$ +319,693 +$ +227,344 +Total debt, including current maturity +$ +299,187 +$ +299,038 +$ +2,283 +$ +51,917 +$ +52,428 +Total liabilities +$ +642,898 +$ +451,960 +$ +58,808 +$ +108,637 +$ +102,293 +Stockholders’ equity +$ +2,050,238 +$ +1,126,408 +$ +632,350 +$ +125,051 +$ +114,101 +52 +Table of Contents +Index to Financial Statements +ITEM 7. +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors” and the section entitled “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. +Overview +We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of crude oil, natural gas liquids and natural gas in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale in Eastern Ohio and along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. In addition, we have producing properties in the Niobrara Formation of Northwestern Colorado and the Bakken Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, an equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and natural gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO, and interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +2013 and 2014 Year to Date Highlights +• +Oil and natural gas revenues increased 5% to $262.2 million for the year ended December 31, 2013 from $248.6 million for the year ended December 31, 2012 . +• +Production increased 60% to approximately 4,118,131 BOE for the year ended December 31, 2013 from approximately 2,572,618 BOE for the year ended December 31, 2012 . +• +During 2013, we drilled 98 gross (79 net) wells, participated in an additional 49 gross (2.6 net) wells that were drilled by other operators on our Utica Shale acreage and recompleted 150 gross and net wells. Of our 98 new wells drilled at year end 2013, 64 were completed as producing wells, two were non-productive, 14 were waiting on completion, nine were waiting on a horizontal rig and nine were drilling. +• +On February 26, 2014, we entered into a binding letter of intent with Rhino to acquire approximately 8,200 net acres in the Utica Shale of Eastern Ohio and approximately 1,000 BOEPD of production during January 2014 for a total purchase price of $185.0 million, subject to closing adjustments. We are the operator of substantially all of this acreage. +• +Through February 27, 2014, after giving pro forma effect to our pending acquisition disclosed above, we would have acquired leasehold interests in approximately 167,700 gross (165,400 net) acres in the Utica Shale in Eastern Ohio. During 2013, we drilled 52 gross (39 net) wells on our Utica Shale acreage and, as of February 14, 2014, we had spud six gross (five net) wells during 2014, all of which were being drilled. +• +In June and November 2013, we sold shares of our Diamondback common stock in underwritten public offerings for an aggregate of $192.7 million in net proceeds. As of December 31, 2013, we owned approximately 7.2% of Diamondback's outstanding common stock. +• +In February 2013, we completed an underwritten public offering of an aggregate of 8,912,500 shares of our common stock and received net proceeds of approximately $325.8 million. We used approximately $220.4 million to fund our acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio and the remaining net proceeds for general corporate purposes, which included funding a portion of our 2013 capital development plan. +• +In November 2013, we completed an underwritten public offering of an aggregate of 7,475,000 shares of our common stock and received net proceeds of approximately $408.0 million. We have used, and intend to continue to use, the net proceeds from this equity offering for general corporate purposes, which may include expenditures associated with our 20 14 drilling program and additional acreage acquisitions in the Utica Shale. +53 +Table of Contents +Index to Financial Statements +Critical Accounting Policies and Estimates +Our disc ussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements: +Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds and totaled $950.6 million at December 31, 2013 and $626.3 million at December 31, 2012 . These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and available funds for exploration and development. +Ceiling Test . Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the prior twelve months of the applicable year beginning with 2009, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural gas and natural gas liquids decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our results of operations. No ceiling test impairment was required for the year ended December 31, 2013 . +Asset Retirement Obligations . We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. +We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the +54 +Table of Contents +Index to Financial Statements +obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates. +Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Netherland, Sewell & Associates, Inc., Ryder Scott Company, L.P. and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2013 on a well-by-well basis for our properties. +Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been prepared in accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of our reserve estimates is a function of many factors including the following: +• +the quality and quantity of available data; +• +the interpretation of that data; +• +the accuracy of various mandated economic assumptions; and +• +the judgments of the individuals preparing the estimates. +Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. +Income Taxes . We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2013, a valuation allowance of $4.7 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized. +Revenue Recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is received. Historically, our actual payments have not significantly deviated from our accruals. +Investments—Equity Method. Investments in entities greater than 20% and less than 50% and/or investments in which we have significant influence are accounted for under the equity method. Under the equity method, our share of investees’ earnings +55 +Table of Contents +Index to Financial Statements +or loss is recognized in the statement of operations. In accordance with FASB ASC 825 , "Financial Instruments," we have elected the fair value option of accounting for our equity method investment in Diamondback's stock. At the end of each reporting period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by us and the resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations. +We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we recognize an impairment provision. There was no impairment of equity method investments at December 31, 2013 or 2012 . +Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities. +Derivative Instruments and Hedging Activities . We seek to reduce our exposure to unfavorable changes in oil and natural gas prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, “ Derivatives and Hedging ,” as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. +See "Item 7. Commodity Price Risk" for a summary of our fixed price swaps and swaptions in place as of December 31, 2013. +RESULTS OF OPERATIONS +Results of Operations +The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. +The following table presents our production volumes, average prices received and average production costs during the periods indicated: +56 +Table of Contents +Index to Financial Statements +2013 +2012 +2011 +Production Volumes: +Oil (MBbls) +2,317 +2,323 +2,128 +Gas (MMcf) +8,891 +1,108 +878 +Natural gas liquids (MGal) +13,416 +2,714 +2,468 +Oil equivalents (MBOE) +4,118 +2,573 +2,333 +Average Prices: +Oil (per Bbl) +$ +96.74 +(1) +$ +104.46 +(1) +$ +104.33 +(1) +Gas (per Mcf) +$ +2.36 +(1) +$ +2.91 +$ +4.37 +Natural gas liquids (per Gal) +$ +1.27 +$ +0.98 +$ +1.25 +Oil equivalents (per BOE) +$ +63.68 +$ +96.63 +$ +98.13 +Production Costs: +Average production costs (per BOE) +$ +6.48 +$ +9.45 +$ +8.96 +Average production taxes and midstream costs (per BOE) +$ +9.22 +$ +11.43 +$ +11.29 +Total production and midstream costs and production taxes (per BOE) +$ +15.70 +$ +20.88 +$ +20.25 +_____________________ +(1) +Includes various derivative contracts at a weighted average price of: +Per barrel +January – December 2013 +$ +101.90 +January – December 2012 +$ +108.31 +January – December 2011 +$ +86.96 +Per MMBtu +January – December 2013 +$ +4.00 +Excluding the net effect of fixed price swaps, the average price for 2013 would have been $104.51 per barrel of oil, $3.73 per Mcf of gas and $70.99 per BOE. The total volume hedged for 2013 represented approximately 48% of our total sales volumes for the year. Excluding the net effect of fixed price swap contracts, the average oil price for 2012 would have been $106.11 per barrel of oil and $98.12 per BOE. The total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the net effect of forward sales contracts, the average oil price for 2011 would have been $107.13 per barrel of oil and $100.68 per BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. +From 2012 to 2013, our net equivalent oil production increased 60% from 2,572,618 BOE to 4,118,131 BOE primarily as a result of the development of our Utica Shale acreage. From 2011 to 2012, our net equivalent oil production also increased 10% from 2,333,208 BOE to 2,572,618 BOE due to the results of our 2012 drilling and recompletion activities. We currently estimate that our 2014 production will be between 18,250,000 and 21,900,000 BOE. However, our actual production may be different due to changes in our currently anticipated drilling and recompletion activities, changing economic climate, adverse weather conditions or other unforeseen events. +Comparison of the Years Ended December 31, 2013 and December 31, 2012 +We reported net income of $153.2 million for the year ended December 31, 2013 as compared to $68.4 million for the year ended December 31, 2012 . This 124% increase in period-to-period net income was due primarily to $220.1 million of income recognized from our equity method investment in Diamondback and a 60% increase in net production to 4,118,131 BOE from 2,572,618 , partially offset by a 34% decrease in realized BOE prices to $63.68 from $96.63 , a $2.4 million increase in lease operating expenses, a $10.6 million increase in midstream transportation, processing and marketing expenses, an $8.7 million increase in general and administrative expenses, a $10.0 million increase in interest expense and a $71.8 million increase in income tax expense for the year ended December 31, 2013 as compared to the year ended December 31, 2012 . +57 +Table of Contents +Index to Financial Statements +Oil and Gas Revenues . For the year ended December 31, 2013 , we reported oil and natural gas revenues of $262.2 million as compared to oil and natural gas revenues of $248.6 million during 2012 . This $13.6 million , or 5% , increase in revenues was primarily attributable to a 60% increase in net production to 4,118,131 BOE from 2,572,618 BOE, partially offset by a 34% decrease in realized BOE prices to $63.68 from $96.63 , for the year ended December 31, 2013 as compared to the year ended December 31, 2012 . +The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2013 and December 31, 2012: +Year Ended +December 31, +2013 +2012 +Oil production volumes (MBbls) +2,317 +2,323 +Gas production volumes (MMcf) +8,891 +1,108 +Natural gas liquids production volumes (MGal) +13,416 +2,714 +Oil equivalents (MBOE) +4,118 +2,573 +Average oil price (per Bbl) +$ +96.74 +$ +104.46 +Average gas price (per Mcf) +$ +2.36 +$ +2.91 +Average natural gas liquids (per Gal) +$ +1.27 +$ +0.98 +Oil equivalents (per BOE) +$ +63.68 +$ +96.63 +Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes increased to $26.7 million for the year ended December 31, 2013 from $24.3 million for the year ended December 31, 2012 . This increase was mainly the result of an increase in expenses related to property taxes, compressor rentals, compressor repairs and maintenance, contract pumpers, environmental services, insurance expense, and salt water disposal. +Production Taxes . Production taxes decreased to $26.9 million for the year ended December 31, 2013 from $29.0 million for 2012. This decrease was primarily related to changes in our product mix and production location. +Midstream Transportation, Processing and Marketing Expenses . Midstream transportation, processing and marketing expenses increased by $10.6 million to $11.0 million for the year ended December 31, 2013 from $0.4 million for 2012. This increase was primarily the result of midstream expenses related to our production volumes in the Utica Shale resulting from our 2013 drilling activities. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $118.9 million for the year ended December 31, 2013 , and consisted of $118.1 million in depletion of oil and natural gas properties and $0.8 million in depreciation of other property and equipment, as compared to total DD&A expense of $90.7 million for 2012. This increase was due to an increase in our full cost pool as a result of our capital activities as well as an increase in our production, partially offset by an increase in our total proved reserves volume used to calculate our total DD&A expense. +General and Administrative Expenses . Net general and administrative expenses increased to $22.5 million for the year ended December 31, 2013 from $13.8 million for the year ended December 31, 2012. This $8.7 million increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in legal expenses, corporate fees, consulting fees and fees for auditing services and a reduction in administrative services reimbursements under the acquisition team agreement, partially offset by an increase in general and administrative costs related to exploration and development activity capitalized to the full cost pool. +Accretion Expense . Accretion expense remained relatively flat at $0.7 million for the years ended December 31, 2013 and 2012 . +Interest Expense . Interest expense increased to $17.5 million for the year ended December 31, 2013 from $7.5 million for the year ended December 31, 2012 due largely to a full year of interest on our 7.75% Senior Notes due 2020. During 2013 , we had no debt outstanding under our revolving credit facility as compared to total weighted average debt outstanding under our +58 +Table of Contents +Index to Financial Statements +revolving credit facility of $45.0 million in 2012 , which bore a weighted average interest rate of 2.85%. On October 17, 2012, we issued $250.0 million aggregate principal amount of our 7.75% Senior Notes due 2020, a portion of the proceeds from which was used to repay all outstanding borrowings under our revolving credit facility. On December 21, 2012, we issued an additional $50.0 million aggregate principal amount of our 7.75% Senior Notes due 2020. Additionally, we capitalized approximately $7.1 million in interest expense to undeveloped oil and natural gas properties during the year ended December 31, 2013 as a result of increased interest costs incurred on our 7.75% Senior Notes. We did not capitalize any interest costs for the year ended December 31, 2012 . +Income Taxes . As of December 31, 2013 , we had a net operating loss carry forward of approximately $4.2 million , in addition to numerous temporary differences, which gave rise to a net deferred tax liability. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2013 , a valuation allowance of $4.7 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized. We recognized an income tax expense from continuing operations of $98.1 million for the year ended December 31, 2013 . +Comparison of the Years Ended December 31, 2012 and December 31, 2011 +We reported net income of $68.4 million for the year ended December 31, 2012 as compared to net income of $108.4 million for the year ended December 31, 2011. This 37% decrease in period-to-period net income was due primarily to a 2% decrease in realized BOE prices to $96.63 for the year ended December 31, 2012, a 16% increase in lease operating expenses, a 71% increase in general and administrative expenses, an 11% increase in production taxes, an approximately $6.0 million increase in interest expense, a $3.5 million loss on the disposal of our Belize properties, net of tax, and a $24.2 million increase in income taxes from continuing and discontinued operations, partially offset by a 10% increase in net production to 2,572,618 BOE, a gain on sale of assets of $7.3 million and income from equity method investments of $8.3 million. +Oil and Gas Revenues . For the year ended December 31, 2012, we reported oil and natural gas revenues of $248.6 million as compared to oil and natural gas revenues of $229.0 million during 2011. This $19.6 million, or 9%, increase in revenues was primarily attributable to a 10% increase in net production to 2,572,618 BOE from 2,333,208 BOE, partially offset by a 2% decrease in realized BOE prices to $96.63 from $98.13, for the year ended December 31, 2012 as compared to the year ended December 31, 2011. +The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2012 and December 31, 2011: +Year Ended +December 31, +2012 +2011 +Oil production volumes (MBbls) +2,323 +2,128 +Gas production volumes (MMcf) +1,108 +878 +Natural gas liquids production volumes (MGal) +2,714 +2,468 +Oil equivalents (MBOE) +2,573 +2,333 +Average oil price (per Bbl) +$ +104.46 +$ +104.33 +Average gas price (per Mcf) +$ +2.91 +$ +4.37 +Average natural gas liquids (per Gal) +$ +0.98 +$ +1.25 +Oil equivalents (per BOE) +$ +96.63 +$ +98.13 +Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes increased to $24.3 million for the year ended December 31, 2012 from $20.9 million for 2011. This increase was mainly the result of an increase in expenses related to property taxes, chemicals and fuel, compressor rentals, contract pumpers, field supervision, equipment repairs and maintenance, salt water disposal and well workovers. +59 +Table of Contents +Index to Financial Statements +Production Taxes . Production taxes increased to $29.0 million for the year ended December 31, 2012 from $26.1 million for 2011. This increase was primarily related to a 10% increase in production partially offset by a 2% decrease in the average realized BOE price received, resulting in a 9% increase in oil and gas revenues. +Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $90.7 million for the year ended December 31, 2012, and consisted of $90.2 million in depletion of oil and natural gas properties and $0.5 million in depreciation of other property and equipment, as compared to total DD&A expense of $62.3 million for 2011. This increase was due to an increase in our full cost pool as a result of our capital activities, an increase in our production and a decrease in our total proved reserves volume used to calculate our total DD&A expense. +General and Administrative Expenses . Net general and administrative expenses increased to $13.8 million for the year ended December 31, 2012 from $8.1 million for 2011. This $5.7 million increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased number of employees, increases in legal expenses, franchise taxes and fees for auditing and tax services, partially offset by an increase in administrative services reimbursements under the acquisition team agreement and an increase in general and administrative costs related to exploration and development activity capitalized to the full cost pool. +Accretion Expense . Accretion expense remained relatively flat at $0.7 million for the years ended December 31, 2012 and 2011. +Interest Expense . Interest expense increased to $7.5 million for the year ended December 31, 2012 from $1.4 million for 2011 due to higher outstanding debt balances and higher weighted average interest rates. During 2011, total weighted debt outstanding under our revolving credit facility was approximately $21.1 million and bore a weighted average interest rate of 3.32%. During 2012, total weighted average debt outstanding under our revolving credit facility was approximately $45.0 million and bore a weighted average interest rate of 2.85%. On October 17, 2012, we issued $250.0 million aggregate principal amount of our 7.75% Senior Notes due 2020, a portion of the proceeds from which was used to repay all outstanding borrowings under our revolving credit facility. On December 21, 2012, we issued an additional $50.0 million aggregate principal amount of our 7.75% Senior Notes due 2020. In addition, we wrote off approximately $1.1 million of unamortized loan fees associated with our revolving credit facility in conjunction with the lowering of our borrowing base during the year ended December 31, 2012. +Income Taxes . As of December 31, 2012, we had a net operating loss carry forward of approximately $4.3 million, in addition to numerous temporary differences, which gave rise to a net deferred tax liability. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2012, a valuation allowance of $4.6 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these assets may be realized. We recognized an income tax expense from continuing and discontinued operations of $24.1 million for the year ended December 31, 2012. +Liquidity and Capital Resources +Overview . Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our credit facility and the issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and natural gas production. During 2012, we received aggregate net proceeds (before offering expenses) of approximately $427.9 million from the sale of shares of our common stock and approximately $290.3 million from the sale of our 7.75% Senior Notes due 2020. In January 2013, we received $32.8 million of net proceeds from the underwriters' exercise of their option to purchase the remaining shares of common stock subject to the over-allotment option granted in connection with our December 2012 equity offering. In 2013, we received an aggregate of $733.8 million from the sale of shares of our common stock. In addition, we received an aggregate of $192.7 million in net proceeds from the sale of shares of our Diamondback common stock in 2013. +Net cash flow provided by operating activities was $ 191.1 million for the year ended December 31, 2013 as compared to net cash flow provided by operating activities of $ 199.2 million for 2012 . This decrease was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 34% decrease in net realized BOE prices, partially offset by a 60% increase in our net BOE production. +60 +Table of Contents +Index to Financial Statements +Net cash flow provided by operating activities was $199.2 million for the year ended December 31, 2012 , as compared to net cash flow provided by operating activities of $158.1 million for 2011. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 10% increase in our net BOE production, partially offset by a 2% decrease in net realized BOE prices. +Net cash used in investing activities for the year ended December 31, 2013 was $ 664.3 million as compared to $ 840.6 million for 2012 . During the year ended December 31, 2013 , we spent $ 808.2 million in additions to oil and natural gas properties, of which $335.2 million was spent on our 2013 drilling and recompletion programs, $93.4 million was spent on expenses attributable to the wells drilled and recompleted during 2012, $5.8 million was spent on compressors and other facility enhancements, $2.0 million was spent on plugging costs, $340.4 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale, and $5.2 million was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, $ 33.9 million was invested in Grizzly and $13.1 million was invested in our other equity investments during the year ended December 31, 2013 . We also received $192.7 million from the sale of shares of our Diamondback common stock during 2013. During the year ended December 31, 2013 , we used cash from operations and proceeds from our 2012 and 2013 equity and debt offerings for our investing activities. +Net cash used in investing activities for the year ended December 31, 2012 was $840.6 million as compared to $323.2 million for 2011. During the year ended December 31, 2012, we spent $757.2 million in additions to oil and natural gas properties, of which $175.4 million was spent on our 2012 drilling and recompletion programs, $38.8 million was spent on expenses attributable to the wells drilled and recompleted during 2011, $13.3 million was spent on compressors and other facility enhancements, $1.7 million was spent on plugging costs, $509.8 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale, and $5.0 million was spent on tubulars, with the remainder attributable mainly to capitalized general and administrative expenses. In addition, during the year ended December 31, 2012 , $103.9 million was invested in Grizzly and an aggregate of $43.4 million was invested in our other equity investments. During the year ended December 31, 2012 , we used cash from operations and proceeds from the Notes Offerings and the December 2012 Equity Offering for our investing activities. +Net cash provided by financing activities for the year ended December 31, 2013 was $ 765.1 million as compared to net cash provided by financing activities of $ 714.6 million for 2012. The 2013 amount provided by financing activities is primarily attributable to the net proceeds of $765.1 million from our 2013 equity offerings. +Net cash provided by financing activities for the year ended December 31, 2012 was $714.6 million as compared to $256.5 million for 2011. The 2012 amount provided by financing activities was primarily attributable to the net proceeds of $426.9 million from the December 2012 Equity Offering (not including the $32.8 received in January 2013 following the exercise by the underwriters of the December 2012 Equity Offering of their option to purchase an additional 900,000 shares of our common stock to cover over-allotments), $296.8 million from our offerings of 7.750% Senior Notes due 2020 and $0.2 million from the exercise of stock options. +Credit Facility . On September 30, 2010, we entered into a senior secured revolving credit facility with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association, or Amegy Bank. The revolving credit facility initially matured on September 30, 2013, had a maximum commitment amount of $100.0 million and had a borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24, 2010. On May 3, 2011, we entered into a first amendment to the revolving credit facility with The Bank of Nova Scotia, Amegy Bank, KeyBank National Association, or KeyBank, and Société Générale. Under the terms of the first amendment, KeyBank and Société Générale were added as additional lenders, the maximum amount of the revolving credit facility was increased to $350.0 million, the borrowing base was increased to $90.0 million, certain fees and rates payable by us under the credit facility were decreased, and the maturity date was extended until May 3, 2015. On October 31, 2011, we entered into additional amendments to our revolving credit facility pursuant to which, among other things, the borrowing base under the facility was increased to $125.0 million. On December 14, 2011, we repaid all outstanding borrowings under the credit facility with a portion of the net proceeds of our equity offering completed on December 5, 2011 pending the application of such proceeds to fund certain Utica Shale lease acquisitions and for general corporate purposes. On May 2, 2012, we entered into an amendment to the revolving credit facility under which, among other things, the borrowing base was increased to $155.0 million. In addition, Credit Suisse, Deutsche Bank Trust Company Americas and IBERIABANK were added as additional lenders and Société Générale left the bank group. +On October 9, 2012, we entered into an amendment to our revolving credit facility that modified certain covenants to permit our October offering of 7.75% Senior Notes due 2020. The offering closed on October 17, 2012 and we repaid all indebtedness outstanding under our revolving credit facility on that date with a portion of the proceeds from the offering. +61 +Table of Contents +Index to Financial Statements +Effective as of October 17, 2012, we amended our revolving credit facility to lower the applicable rates (i) from a range of 1.00% to 1.75% to a range of 0.75% to 1.50% for the base rate loans and (ii) from a range of 2.00% to 2.75% to a range of 1.75% to 2.50% for the eurodollar rate loans and letters of credit. This amendment also lowered the commitment fees for Level 1 and Level 2 usage levels, in each case, from 0.50% per annum to 0.375% per annum. Also, effective as of October 17, 2012, in connection with the completion of our October offering and the contribution of our Permian Basin properties to Diamondback, our borrowing base under the credit facility was reduced to $45.0 million until the next borrowing base redetermination. Effective as of December 18, 2012, we entered into another amendment to our revolving credit facility that modified certain covenants to permit our December offering of 7.75% Senior Notes due 2020 and reduce the borrowing base under our revolving credit facility to $40.0 million until the next borrowing base redetermination. +In connection with the spring borrowing base redetermination of our revolving credit facility, completed as of June 6, 2013, we entered into an amendment to our revolving credit facility pursuant to which, among other things, our borrowing base under this facility was increased from $40.0 million to $50.0 million, an improved pricing grid was provided for and the maturity date of the facility was extended to June 2018. See also Note 7 to our financial statements included elsewhere in this report. +On December 27, 2013, we entered into an Amended and Restated Credit Agreement with The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders, which amends and restates in its entirety our existing credit agreement, dated as of September 30, 2010, as amended. The Amended and Restated Credit Agreement provides for an increase in the maximum facility amount from $350.0 million to $1.5 billion, with an increase in borrowing base availability as of December 27, 2013 from $50.0 million to $150.0 million. The Amended and Restated Credit Agreement matures on June 6, 2018. +Advances under our revolving credit facility, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.5% to 1.50%, plus (2) the highest of: (a) the federal funds rate plus 0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.5% to 2.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. We have had no outstanding borrowings under our revolving credit facility since October 17, 2012, on which date the outstanding borrowings, prior to repayment, bore interest at the eurodollar rate (2.97%) per annum. +As of December 31, 2013 , there were no borrowings outstanding under our revolving credit facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility. +Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries' ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2013 . +Senior Notes . On October 17, 2012, we issued $250.0 million in aggregate principal amount of our 7.75% Senior Notes due 2020, or the October Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain +62 +Table of Contents +Index to Financial Statements +non-U.S. persons in accordance with Regulation S under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee. +On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of our 7.75% Senior Notes due 2020, or the December Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The December Notes were issued as additional securities under the existing senior note indenture. The December Notes and the October Notes are treated as a single class of debt securities under the senior note indenture and are referred to collectively herein as the "Notes". We used a portion of the net proceeds from the October Notes Offering to repay all amounts outstanding at such time under our revolving credit facility. We used the remaining net proceeds of the October Notes Offering and the net proceeds of the December Notes Offering for general corporate purposes, which includes funding a portion of our 2013 capital development plan. +Under the senior note indenture, interest on the Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are senior unsecured obligations and rank equally in the right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the Notes. +We may redeem some or all of the Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, we may redeem the Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Notes initially issued remains outstanding immediately after such redemption. +If we experience a change of control (as defined in the senior note indenture), we will be required to make an offer to repurchase the Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds in a manner specified in the senior note indenture, we will be required to use the remaining proceeds to make an offer to repurchase the Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. +The senior note indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. +Capital Expenditures . Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions (primarily in the Utica Shale), to fund Grizzly's delineation drilling program and initial preparation of the Algar Lake facility and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue acquisition and disposition opportunities and (3) pursue business integration opportunities. +Of our net reserves at December 31, 2013 , 35.2% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use third parties to accomplish those activities. +During 2013, we spud 52 gross (39 net) wells in the Utica Shale for a total cost of approximately $301.9 million. We currently expect our 2014 capital expenditures to be $594.0 million to $634.0 million to drill 85 to 95 gross (64 to 71 net) wells +63 +Table of Contents +Index to Financial Statements +on our Utica Shale acreage. In addition, we currently expect to spend $225.0 million to $275.0 million in 2014 to acquire additional acreage in the Utica Shale. +During 2013, we recompleted 87 existing wells and spud 22 new wells for a total cost of approximately $70.0 million at our WCBB field. We currently intend to drill 22 to 24 new wells during 2014 at our WCBB field for aggregate estimated drilling and recompletion expenditures during 2014 of $42.0 million to $45.0 million. +In our Hackberry fields, in 2013, we recompleted 63 existing wells and spud 18 new wells for a total cost of approximately $62.6 million. We currently intend to drill ten to twelve wells in our Hackberry fields in 2014. Total capital expenditures for our Hackberry fields during 2014 are estimated to be approximately $24.0 million to $26.0 million. +During 2013, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in the Niobrara Formation in 2014. +During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2013 , our net investment in Grizzly was approximately $191.5 million. Our capital requirements in 2013 for Grizzly were approximately $33.9 million , primarily for the expenses associated with the construction of the Algar Lake facility and drilling activity during the 2013-2014 winter drilling season. Effective October 5, 2012, Grizzly entered into a $125.0 million revolving credit facility, of which $75.0 million has been borrowed to fund additional infrastructure relating to the Algar Lake facility and other future development projects. Our capital requirements in 2014 related to Grizzly's activities are currently estimated to be approximately $15.0 million to $20.0 million. +We had capital expenditures of approximately $1.8 million during the year ended December 31, 2013 related to our interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2014. +In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the first quarter of 2013, we participated in the formation of Stingray Energy with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure, Stingray Cementing and Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk and Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Midstream which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. In the year ended December 31, 2013, we invested approximately $10.0 million in these entities. In 2014, we expect to invest approximately $15.0 million to $20.0 million in these entities. We are currently evaluating strategic alternatives with respect to these oil field service entities. A registration statement on Form S-1 has been submitted to the SEC on a confidential basis in connection with certain of these interests, and we may choose to pursue an initial public offering of these interest later this year subject to market conditions. In January 2014, Blackhawk completed the sale of its equity interests in Ohio Gathering Company, LLC and Ohio Condensate Company, LLC for a purchase price of $190.0 million, of which we received $84.8 million in net proceeds. +Our total capital expenditures for 2014 are currently estimated to be in the range of $675.0 million to $725.0 million. In addition, we currently expect to spend $225.0 million to $275.0 million in 2014 to acquire additional Utica Shale acreage, which includes the $185.0 million acquisition discussed in Item 1. "Business - Recent Developments". Approximately 88% of our 2014 estimated capital expenditures are currently expected to be spent in the Utica Shale. This range is up from the $513.5 million spent on 2013 activities, excluding Utica leasehold acquisitions, primarily due to the significant increase in our acreage position in the Utica Shale and our contemplated Utica development plans. We intend to continue to monitor pricing and cost developments and make adjustments to our future capital expenditure programs as warranted. +We believe that our cash on hand, cash flow from operations, proceeds from our recent offerings of debt and equity securities, the sale of our Diamondback common stock, distributions from Blackhawk and borrowings under our revolving credit facility will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling program or pursue additional acquisitions, or Grizzly's +64 +Table of Contents +Index to Financial Statements +oil sands projects are accelerated, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions that may be favorable to us. +Commodity Price Risk +The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past six years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $13.31 per MMBtu in July 2008. On February 21, 2014, the West Texas Intermediate posted price for crude oil was $102.20 per barrel and the Henry Hub spot market price of natural gas was $6.14 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swaps and swaptions at December 31, 2013 : +Volume (barrels per day) +Weighted Average Price ($ per Bbl) +Fixed Price Swaps: +January 2014 - March 2014 +4,000 +$ +104.75 +April 2014 - December 2014 +2,000 +$ +101.50 +Volume (MMBtu per day) +Weighted Average Price ($ per MMBtu) +Fixed Price Swaps and Swaptions: +January 2014 +65,000 +$ +4.04 +February 2014 - December 2014 +105,000 +$ +4.01 +January 2015 - December 2015 +125,000 +$ +4.03 +January 2016 - March 2016 +105,000 +$ +4.04 +April 2016 +95,000 +$ +4.04 +Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 fixed price swap contracts, we hedged approximately 48% of our 2013 production. Under the 2014 contracts, we have hedged approximately 41% to 49% of our expected 2014 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. +Commitments +In connection with our acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller's (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As of December 31, 2013 , the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2013 , we have plugged 354 +65 +Table of Contents +Index to Financial Statements +wells at WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. +Contractual and Commercial Obligations +The following table sets forth our contractual and commercial obligations at December 31, 2013 : +Payment due by period (1) +Contractual Obligations +Total +Less than 1 year +1-3 years +3-5 years +More than 5 +years +(In thousands) +7.75% senior unsecured notes due 2020 +$ +461,846 +$ +23,250 +$ +46,500 +$ +46,500 +$ +345,596 +Asset retirement obligations +15,083 +795 +1,383 +793 +12,112 +Employment agreements +3,467 +1,800 +1,667 +— +— +Building loan (2) +1,995 +159 +1,836 +— +— +Firm transportation contracts +1,101,260 +40,783 +133,898 +138,033 +788,546 +Operating leases +1,854 +536 +920 +398 +— +Total +$ +1,585,505 +$ +67,323 +$ +186,204 +$ +185,724 +$ +1,146,254 +_____________________ +(1) Does not include short-term derivative instruments of $12.0 million, which are due in less than one year. +(2) +Does not include estimated interest of $112,000 due in less than one year and $118,000 due in 1-3 years. +Off-balance Sheet Arrangements +We had no off-balance sheet arrangements as of December 31, 2013 . +New Accounting Pronouncements +In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 , "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," which requires additional information about amounts reclassified out of accumulated other comprehensive income by component. This ASU requires the presentation, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, a cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The requirements of this ASU are effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. We have adopted the provisions of this ASU for reporting periods in 2013. Adoption of this ASU had no impact on our financial position or results of operations. +ITEM 7A. +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. +These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the West Texas Intermediate posted price for crude oil +66 +Table of Contents +Index to Financial Statements +has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $13.31 per MMBtu in July 2008. On February 21, 2014, the West Texas Intermediate posted price for crude oil was $102.20 per barrel and the Henry Hub spot market price of natural gas was $6.14 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. +To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the following open fixed price swaps and swaptions at December 31, 2013 : +Volume (barrels per day) +Weighted Average Price ($ per Bbl) +Fixed Price Swaps: +January 2014 - March 2014 +4,000 +$ +104.75 +April 2014 - December 2014 +2,000 +$ +101.50 +Volume (MMBtu per day) +Weighted Average Price ($ per MMBtu) +Fixed Price Swaps and Swaptions: +January 2014 +65,000 +$ +4.04 +February 2-14 - December 2014 +105,000 +$ +4.01 +January 2015 - December 2015 +125,000 +$ +4.03 +January 2016 - March 2016 +105,000 +$ +4.04 +April 2016 +95,000 +$ +4.04 +In January 2014, we entered into fixed price swaps for 25,000 MMBtu of natural gas per day at a weighted average price of $4.20 per MMBtu for the period from May 2014 through December 2015. For the period from June 2014 through December 2015, we entered into fixed price swaps for 25,000 MMBtu of natural gas per day at a weighted average price of $4.21 per MMBtu. Our fixed price swap contracts are tied to the commodity prices on NYMEX. We will receive the fixed price amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for natural gas. +Under our 2014 contracts, we have hedged approximately 41% to 49% of our estimated 2014 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. At December 31, 2013 , we had a net liability derivative position of $22.8 million as compared to a net liability derivative position of $9.5 million as of December 31, 2012 , related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments by approximately $44.4 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $44.4 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. +Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the eurodollar rates are elected, the eurodollar rates. As of December 31, 2013 , we had no variable interest rate borrowings outstanding; therefore, an increase in interest rates would not have impacted our interest expense. As of December 31, 2013 , we did not have any interest rate swaps to hedge our interest risks. +67 +Table of Contents +Index to Financial Statements +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +The information required by this item appears beginning on page F-1 following the signature pages of this Report. +ITEM 9. +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Interim Chief Executive Officer, President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Interim Chief Executive Officer, President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. +As of December 31, 2013 , an evaluation was performed under the supervision and with the participation of management, including our Interim Chief Executive Officer, President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Interim Chief Executive Officer, President and Chief Financial Officer has concluded that, as of December 31, 2013 , our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management's Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 1992 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2013 . +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2013 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2013 , as stated in their accompanying report. +/s/ Michael G. Moore +Name: +Michael G. Moore +Title: +Interim Chief Executive Officer, President and Chief Financial Officer +68 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2013 , based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 , based on criteria established in the 1992 Internal Control-Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2013 and our report dated February 28, 2014 expressed an unqualified opinion on those financial statements. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 28, 2014 +69 +Table of Contents +Index to Financial Statements +ITEM 9B. +OTHER INFORMATION +On February 14, 2014, as previously announced, James D. Palm resigned as our Chief Executive Officer and from our Board of Directors. Michael G. Moore, our President and Chief Financial Officer, assumed the additional title and responsibilities of our Interim Chief Executive Officer upon Mr. Palm's resignation, pending the completion of our search process for and appointment of a new chief executive officer. On February 24, 2014, the Compensation Committee of our Board of Directors granted Mr. Moore a retention award of 24,868 shares of our common stock (the "Restricted Shares") pursuant to a restricted stock award certificate (the "Award Certificate") under our 2013 Restated Stock Incentive Plan. The Restricted Shares vest in two equal installments on the first and second anniversary of the grant date, subject to Mr. Moore's continuous service with us. Vesting of the Restricted Shares will accelerate upon the earlier of Mr. Moore's involuntary termination without cause, termination for good reason, death, disability or termination for any reason except cause or voluntary termination without good reason within 24 months after a change in control, as described in the form of award certificate, a copy of which is filed as an exhibit to this Annual Report on Form 10-K. +70 +Table of Contents +Index to Financial Statements +PART III +ITEM 10. +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +For information concerning Item 10-Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 11. +EXECUTIVE COMPENSATION +For information concerning Item 11-Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 12. +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +For information concerning Item 12-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +ITEM 14. +PRINCIPAL ACCOUNTING FEES AND SERVICES +For information concerning Item 14-Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). +71 +Table of Contents +Index to Financial Statements +PART IV +ITEM 15. +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +The following documents are filed as part of this report or incorporated by reference herein: +(1) +Financial Statements +Reference is made to the Index to Financial Statements appearing on Page F-1. +Reference is also made to the Financial Statements of Diamondback Energy, Inc. (“Diamondback”) that have been included on pages F-1 to F-39 in Diamondback’s Annual Report on Form 10-K (File No. 001-35700) filed with the SEC on February 19, 2014, which Financial Statements are incorporated herein by reference. +(2) +Financial Statement Schedules +All financial statement schedules have been omitted because they are not applicable or the required disclosure is presented in the financial statements or notes thereto. +(3) +Exhibits +Exhibit +Number +Description +2.1 +Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012). +2.2 +Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 18, 2012). +2.3 +Amendment, dated December 19, 2012, to the Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 20, 2012). +2.4 +Purchase and Sale Agreement, dated February 11, 2013, by and between Windsor Ohio, LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 15, 2013). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009). +3.3 +Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013). +3.4 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +3.5 +First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). +4.2 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +72 +Table of Contents +Index to Financial Statements +4.3 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.4 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +4.5 +Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.6 +Registration Rights Agreement, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.7 +First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +4.8 +Registration Rights Agreement, dated as of December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +10.1+ +2013 Restated Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form S-4, File No. 333-189992, filed by the Company with the SEC on July 17, 2013). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+* +Form of Restricted Stock Award Agreement. +10.4+ +Consulting Agreement, effective as of June 14, 2013, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 19, 2013). +10.5+ +Separation and Release Agreement, dated as of January 31, 2014, by and between the Company and James D. Palm (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 4, 2014). +10.6+ +Employment Agreement, dated November 7, 2012, between the Company and Michael G. Moore (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.7 +Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 3, 2014). +10.8 +Investor Rights Agreement, dated as of October 11, 2012, between Gulfport Energy Corporation and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 17, 2012). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Ryder Scott Company. +73 +Table of Contents +Index to Financial Statements +23.4* +Consent of Grant Thornton LLP with respect to financial statements of Diamondback Energy, Inc. +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1** +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2** +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Ryder Scott Company. +101.INS* +XBRL Instance Document. +101.SCH* +XBRL Taxonomy Extension Schema Document. +101.CAL* +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF* +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB* +XBRL Taxonomy Extension Labels Linkbase Document. +101.PRE* +XBRL Taxonomy Extension Presentation Linkbase Document. +* +Filed herewith. +** +Furnished herewith, not filed. ++ +Management contract, compensatory plan or arrangement. +74 +Table of Contents +Index to Financial Statements +SIGNATURES +In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Date: February 28, 2014 +GULFPORT ENERGY CORPORATION +By: +/s/ MICHAEL G. MOORE +Michael G. Moore +Interim Chief Executive Officer +In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Date: +February 28, 2014 +By: +/s/ MICHAEL G. MOORE +Michael G. Moore +Interim Chief Executive Officer +(Principal Executive Officer) +Date: +February 28, 2014 +By: +/s/ DAVID L. HOUSTON +David L. Houston +Chairman of the Board and Director +Date: +February 28, 2014 +By: +/s/ MICHAEL G. MOORE +Michael G. Moore +President and Chief Financial Officer +(Principal Financial and Accounting Officer) +Date: +February 28, 2014 +By: +/s/ DONALD DILLINGHAM +Donald Dillingham +Director +Date: +February 28, 2014 +By: +/s/ CRAIG GROESCHEL +Craig Groeschel +Director +Date: +February 28, 2014 +By: +/s/ SCOTT E. STRELLER +Scott E. Streller +Director +S-1 +Table of Contents +Index to Financial Statements +ITEM 8. +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +INDEX TO FINANCIAL STATEMENTS +Page +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets, December 31, 2013 and December 31, 2012 +F-3 +Consolidated Statements of Operations, Years Ended December 31, 2013, 2012 and 2011 +F-4 +Consolidated Statements of Comprehensive Income, Years Ended December 31, 2013, 2012 and 2011 +F-5 +Consolidated Statements of Stockholders’ Equity, Years Ended December 31, 2013, 2012 and 2011 +F-6 +Consolidated Statements of Cash Flows, Years Ended December 31, 2013, 2012 and 2011 +F-7 +Notes to Consolidated Financial Statements +F-8 +F-1 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy Corporation and Subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2014 expressed an unqualified opinion. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 28, 2014 +F-2 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED BALANCE SHEETS +December 31, +2013 +December 31, +2012 +(In thousands, except share data) +Assets +Current assets: +Cash and cash equivalents +$ +458,956 +$ +167,088 +Accounts receivable—oil and gas +58,824 +25,615 +Accounts receivable—related parties +2,617 +34,848 +Prepaid expenses and other current assets +2,581 +1,506 +Deferred tax asset +6,927 +— +Short-term derivative instruments +324 +664 +Note receivable - related party +875 +— +Total current assets +531,104 +229,721 +Property and equipment: +Oil and natural gas properties, full-cost accounting, $950,590 and $626,295 excluded from amortization in 2013 and 2012, respectively +2,477,178 +1,611,090 +Other property and equipment +11,131 +8,662 +Accumulated depletion, depreciation, amortization and impairment +(784,717 +) +(665,884 +) +Property and equipment, net +1,703,592 +953,868 +Other assets: +Equity investments ($178,708 and $151,317 attributable to fair value option in 2013 and 2012, respectively) +440,068 +381,484 +Derivative instruments +521 +— +Other assets +17,851 +13,295 +Total other assets +458,440 +394,779 +Total assets +$ +2,693,136 +$ +1,578,368 +Liabilities and Stockholders’ Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +190,707 +$ +110,244 +Asset retirement obligation—current +795 +60 +Short-term derivative instruments +12,280 +10,442 +Current maturities of long-term debt +159 +150 +Total current liabilities +203,941 +120,896 +Long-term derivative instrument +11,366 +— +Asset retirement obligation—long-term +14,288 +13,215 +Deferred tax liability +114,275 +18,607 +Long-term debt, net of current maturities +299,028 +298,888 +Other non-current liabilities +— +354 +Total liabilities +642,898 +451,960 +Commitments and contingencies (Notes 16 and 17) +Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding +— +— +Stockholders’ equity: +Common stock - $.01 par value, 200,000,000 authorized, 85,177,532 issued and outstanding in 2013 and 67,527,386 in 2012 +851 +674 +Paid-in capital +1,813,058 +1,036,245 +Accumulated other comprehensive loss +(9,781 +) +(3,429 +) +Retained earnings +246,110 +92,918 +Total stockholders’ equity +2,050,238 +1,126,408 +Total liabilities and stockholders’ equity +$ +2,693,136 +$ +1,578,368 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF OPERATIONS +For the Year Ended December 31, +2013 +2012 +2011 +(In thousands, except share data) +Revenues: +Oil and condensate sales +$ +224,129 +$ +242,708 +$ +222,025 +Gas sales +21,015 +3,225 +3,838 +Natural gas liquid sales +17,081 +2,668 +3,090 +Other income +528 +325 +301 +262,753 +248,926 +229,254 +Costs and expenses: +Lease operating expenses +26,703 +24,308 +20,897 +Production taxes +26,933 +28,957 +26,054 +Midstream transportation, processing and marketing +11,030 +443 +279 +Depreciation, depletion and amortization +118,880 +90,749 +62,320 +General and administrative +22,519 +13,808 +8,074 +Accretion expense +717 +698 +666 +(Gain) loss on sale of assets +508 +(7,300 +) +— +207,290 +151,663 +118,290 +INCOME FROM OPERATIONS +55,463 +97,263 +110,964 +OTHER (INCOME) EXPENSE: +Interest expense +17,490 +7,458 +1,400 +Interest income +(297 +) +(72 +) +(186 +) +(Income) loss from equity method investments +(213,058 +) +(8,322 +) +1,418 +(195,865 +) +(936 +) +2,632 +INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES +251,328 +98,199 +108,332 +INCOME TAX EXPENSE (BENEFIT) +98,136 +26,363 +(90 +) +INCOME FROM CONTINUING OPERATIONS +153,192 +71,836 +108,422 +DISCONTINUED OPERATIONS +Loss on disposal of Belize properties, net of tax +— +3,465 +— +NET INCOME +$ +153,192 +$ +68,371 +$ +108,422 +NET INCOME PER COMMON SHARE: +Basic net income from continuing operations per share +$ +1.98 +$ +1.28 +$ +2.22 +Basic net income from discontinued operations, net of tax, per share +$ +— +(0.06 +) +— +Basic net income per share +$ +1.98 +$ +1.22 +$ +2.22 +Diluted net income from continuing operations per share +$ +1.97 +$ +1.27 +$ +2.20 +Diluted net income from discontinued operations, net of tax, per share +— +(0.06 +) +— +Diluted net income per share +$ +1.97 +$ +1.21 +$ +2.20 +Weighted average common shares outstanding—Basic +77,375,683 +55,933,354 +48,754,840 +Weighted average common shares outstanding—Diluted +77,861,646 +56,417,488 +49,206,963 +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +For the Year Ended December 31, +2013 +2012 +2011 +(In thousands) +Net income +$ +153,192 +$ +68,371 +$ +108,422 +Foreign currency translation adjustment +(12,223 +) +1,355 +(1,865 +) +Change in fair value of derivative instruments (1) +(4,419 +) +(8,452 +) +1,576 +Reclassification of settled contracts (2) +10,290 +1,005 +4,720 +Other comprehensive income (loss) +(6,352 +) +(6,092 +) +4,431 +Comprehensive income +$ +146,840 +$ +62,279 +$ +112,853 +(1) Net of $4.3 million and $(4.3) million in taxes for the years ended December 31, 2013 and 2012 , respectively. No taxes were recorded in the year ended 2011 . +(2) Net of $(0.5) million and $0.5 million in taxes for the years ended December 31, 2013 and 2012 , respectively. No taxes were recorded in the year ended 2011 . +See accompanying notes to consolidated financial statements. +F-5 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY +Paid-in +Capital +Accumulated +Other +Comprehensive +Income (Loss) +Retained +Earnings +Total +Stockholders’ +Equity +Common Stock +Shares +Amount +(In thousands, except share data) +Balance at January 1, 2011 +44,645,435 +$ +446 +$ +296,253 +$ +(1,768 +) +$ +(83,875 +) +$ +211,056 +Net income +— +— +— +— +108,422 +108,422 +Other Comprehensive Income +— +— +— +4,431 +— +4,431 +Stock Compensation +— +— +1,287 +— +— +1,287 +Issuance of Common Stock in public offerings, net of related expenses +10,810,000 +108 +306,053 +— +— +306,161 +Issuance of Common Stock through exercise of warrants +566 +— +— +— +— +— +Issuance of Restricted Stock +63,370 +1 +(1 +) +— +— +— +Issuance of Common Stock through exercise of options +102,000 +1 +992 +— +— +993 +Balance at December 31, 2011 +55,621,371 +556 +604,584 +2,663 +24,547 +632,350 +Net income +— +— +— +— +68,371 +68,371 +Other Comprehensive Loss +— +— +— +(6,092 +) +— +(6,092 +) +Stock Compensation +— +— +4,688 +— +— +4,688 +Issuance of Common Stock in public offerings, net of related expenses +11,750,000 +118 +426,789 +— +— +426,907 +Issuance of Restricted Stock +135,015 +— +— +— +— +— +Issuance of Common Stock through exercise of options +21,000 +— +184 +— +— +184 +Balance at December 31, 2012 +67,527,386 +674 +1,036,245 +(3,429 +) +92,918 +1,126,408 +Net income +— +— +— +— +153,192 +153,192 +Other Comprehensive Loss +— +— +— +(6,352 +) +— +(6,352 +) +Stock Compensation +— +— +10,495 +— +— +10,495 +Issuance of Common Stock in public offerings, net of related expenses +17,287,500 +173 +764,922 +— +— +765,095 +Issuance of Restricted Stock +237,646 +3 +(3 +) +— +— +— +Issuance of Common Stock through exercise of options +125,000 +1 +1,399 +1,400 +Balance at December 31, 2013 +85,177,532 +$ +851 +$ +1,813,058 +$ +(9,781 +) +$ +246,110 +$ +2,050,238 +See accompanying notes to consolidated financial statements. +F-6 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +CONSOLIDATED STATEMENTS OF CASH FLOWS +Year Ended December 31, +2013 +2012 +2011 +(In thousands) +Cash flows from operating activities: +Net income +$ +153,192 +$ +68,371 +$ +108,422 +Adjustments to reconcile net income to net cash provided by operating activities: +Accretion of discount—Asset Retirement Obligation +717 +698 +666 +Depletion, depreciation and amortization +118,880 +90,749 +62,320 +Stock-based compensation expense +6,297 +2,813 +772 +(Gain) loss from equity investments +(212,714 +) +(8,322 +) +1,418 +Interest income - note receivable +(26 +) +(2 +) +(147 +) +Unrealized loss (gain) on derivative instruments +18,189 +144 +(25 +) +Deferred income tax expense (benefit) +84,951 +24,120 +(372 +) +Amortization of loan commitment fees +1,012 +640 +540 +Amortization of note discount and premium +298 +59 +— +Write off of loan commitment fees +— +1,143 +— +Loss on disposal of assets +— +5,702 +— +Gain on sale of assets +— +(7,300 +) +— +Changes in operating assets and liabilities: +(Increase) decrease in accounts receivable +(33,209 +) +2,404 +(13,067 +) +Decrease (increase) in accounts receivable—related party +32,231 +(30,117 +) +(4,158 +) +(Increase) decrease in prepaid expenses +(1,075 +) +(179 +) +405 +Increase in other assets +(4,523 +) +— +— +Increase in accounts payable and accrued liabilities +29,310 +50,506 +1,612 +Settlement of asset retirement obligation +(2,465 +) +(2,271 +) +(248 +) +Net cash provided by operating activities +191,065 +199,158 +158,138 +Cash flows from investing activities: +Deductions to cash held in escrow +8 +8 +8 +Additions to other property and equipment +(2,322 +) +(638 +) +(415 +) +Additions to oil and gas properties +(808,183 +) +(757,192 +) +(287,292 +) +Proceeds from sale of other property and equipment +113 +140 +— +Proceeds from sale of oil and gas properties +— +63,590 +1,384 +Advances on note receivable to related party +(875 +) +— +(3,182 +) +Proceeds from sale of investments +192,737 +— +— +Contributions to equity method investments +(47,014 +) +(147,307 +) +(34,621 +) +Distributions from equity method investments +1,276 +820 +870 +Net cash used in investing activities +(664,260 +) +(840,579 +) +(323,248 +) +Cash flows from financing activities: +Principal payments on borrowings +(149 +) +(158,639 +) +(97,634 +) +Borrowings on line of credit +— +158,500 +48,000 +Proceeds from bond issuance +— +296,835 +— +Debt issuance costs and loan commitment fees +(1,283 +) +(9,175 +) +(981 +) +Proceeds from issuance of common stock, net of offering costs +766,495 +427,091 +307,154 +Net cash provided by financing activities +765,063 +714,612 +256,539 +Net increase in cash and cash equivalents +291,868 +73,191 +91,429 +Cash and cash equivalents at beginning of period +167,088 +93,897 +2,468 +Cash and cash equivalents at end of period +$ +458,956 +$ +167,088 +$ +93,897 +Supplemental disclosure of cash flow information: +Interest payments +$ +24,280 +$ +1,461 +$ +991 +Income tax payments +$ +2,761 +$ +261 +$ +1 +Supplemental disclosure of non-cash transactions: +Capitalized stock based compensation +$ +4,198 +$ +1,875 +$ +515 +Asset retirement obligation capitalized +$ +3,556 +$ +2,195 +$ +1,390 +Interest capitalized +$ +7,132 +$ +— +$ +— +Foreign currency translation (loss) gain on investment in Grizzly Oil Sands ULC +$ +(12,223 +) +$ +1,355 +$ +(855 +) +Foreign currency translation (loss) gain on note receivable - related party +$ +— +$ +— +$ +(1,085 +) +See accompanying notes to consolidated financial statements. +F-7 +Table of Contents +Index to Financial Statements +GULFPORT ENERGY CORPORATION +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2013 , 2012 AND 2011 +1. +SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Business +Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production company with its principal properties located in the Utica Shale in Eastern Ohio, along the Louisiana Gulf Coast and in Western Colorado in the Niobrara Formation, and has investments in companies operating in the Permian Basin in West Texas, Canada and Thailand. +Cash and Cash Equivalents +The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC and Puma Resources, Inc. All intercompany balances and transactions are eliminated in consolidation. +Accounts Receivable +The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its receivables are from one purchaser of the Company’s oil and gas and receivables from joint interest owners on properties the Company operates. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2013 and December 31, 2012 . +Oil and Gas Properties +The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for 2013 , 2012 and 2011 , adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. +Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $950.6 million and $626.3 million at December 31, 2013 and December 31, 2012 , respectively. These costs are reviewed quarterly by management for impairment. +F-8 +Table of Contents +Index to Financial Statements +If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development. +The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. +Other Property and Equipment +Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range from 3 to 30 years. +Foreign Currency +The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented and equity contributions are translated at the current exchange rate in effect at the date of the contribution. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive income (loss). +(In thousands) +December 31, 2010 +$ +2,952 +December 31, 2011 +$ +1,087 +December 31, 2012 +$ +2,442 +December 31, 2013 +$ +(9,781 +) +Net Income per Common Share +Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. Calculations of basic and diluted net income per common share are illustrated in Note 12. +Income Taxes +Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. +The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1999 – 2013 U.S. federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2013 , the Company has no unrecognized tax benefits that would have a material impact on the effective rate. +F-9 +Table of Contents +Index to Financial Statements +The Company recognizes interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended December 31, 2013 , there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements. +Revenue Recognition +Natural gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as a receivable. At December 31, 2013 , the Company had no gas imbalance liability. At December 31, 2012 , the Company had a gas imbalance liability of approximately $0.4 million . Oil revenues are recognized when ownership transfers, which occurs in the month produced. +Investments—Equity Method +Investments in entities in which the Company owns an equity interest greater than 20% and less than 50% and/or investments in which it has significant influence are accounted for under the equity method. Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations. In accordance with FASB ASC 825 , "Financial Instruments ," the Company has elected the fair value option of accounting for its equity method investment in the common stock of Diamondback Energy Inc. ("Diamondback"). At the end of each reporting period, the quoted closing market price of Diamondback's common stock is multiplied by the total shares owned by the Company and the resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations. +The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. There was no impairment of equity method investments at December 31, 2013 or 2012 . +Accounting for Stock-Based Compensation +The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, “ Compensation—Stock Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options and restricted stock, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The vesting periods for the options range between three to five years and have a maximum contractual term of ten years. The vesting periods for restricted shares range between three to five years with either quarterly or annual vesting installments. +Accounting for Derivative Instruments and Hedging Activities +The Company may seek to reduce its exposure to unfavorable changes in oil and natural gas prices by utilizing energy swaps and collars, or fixed-price contracts. The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. +The Company estimates the fair value of all derivative instruments using established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values reported in the consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors. +The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows there from, the amount and +F-10 +Table of Contents +Index to Financial Statements +timing of asset retirement obligations, the realization of deferred tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties. +Reclassification +Certain reclassifications have been made to prior period financial statements to conform to current period presentation. +Recent Accounting Pronouncements +In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 , "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income," which requires additional information about amounts reclassified out of accumulated other comprehensive income by component. This ASU requires the presentation, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, a cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. The requirements of this ASU are effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. Adoption of the provisions of this ASU did not have a material effect on the Company's consolidated financial statements. +In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides amendments to FASB ASC Topic 820, “Fair Value Measurements and Disclosure” (“FASB ASC 820”) . The purpose of the amendments in this update is to create common fair value measurement and disclosure requirements between GAAP and IFRS. The amendments change certain fair value measurement principles and enhance the disclosure requirements. The amendments to FASB ASC 820 were effective for interim and annual periods beginning after December 15, 2011. Adoption of this ASU for reporting periods in 2012 had no impact on the Company's financial position or results of operations. +In June 2011, the FASB issued ASU 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. The amendments to FASB ASC 220 were effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The Company adopted this ASU for reporting periods in 2012 and reports the components of net income and the components of other comprehensive income in two separate but consecutive statements. Adoption of this ASU had no impact on the Company's financial position or results of operations. +2. +ACQUISITIONS +Beginning in February 2011, the Company entered into agreements to acquire certain leasehold interests located in the Utica Shale in Ohio. Certain of the agreements also granted the Company an exclusive right of first refusal for a period of six months to acquire certain additional tracts leased by the seller. Affiliates of Gulfport initially participated with the Company on a 50/50 basis in the acquisition of all leases described above. On December 17, 2012, Gulfport entered into a definitive agreement with one of the affiliates to purchase approximately 30,000 net acres in the Utica Shale in Eastern Ohio for approximately $302.0 million . On December 19, 2012, the parties amended that agreement to provide for Gulfport's acquisition of approximately 7,000 additional net acres for approximately $70.0 million , resulting in a total purchase price of approximately $372.0 million , subject to certain adjustments. This transaction closed on December 24, 2012. At closing, approximately $53.9 million of the purchase price was placed in escrow pending completion of title review after the closing. Gulfport funded this acquisition with a portion of the net proceeds from its common stock offering that closed on December 24, 2012 (with a second closing for the underwriters' purchase of 900,000 shares pursuant to their over-allotment option on January 7, 2013). The Company received aggregate net proceeds of approximately $460.7 million from this equity offering, as discussed below in Note 8. +On February 15, 2013, the Company completed an acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio. The purchase price was approximately $220.0 million , subject to certain adjustments. At closing, approximately +F-11 +Table of Contents +Index to Financial Statements +$33.6 million of the purchase price was placed in escrow pending completion of title review after the closing. Gulfport funded this acquisition with a portion of the net proceeds from its common stock offering that closed on February 15, 2013. The Company received aggregate net proceeds of approximately $325.8 million from this equity offering. All of the acreage included in these transactions was nonproducing at the time of the applicable transaction and the Company is the operator of all of this acreage, subject to existing development and operating agreements between the parties. These acquisitions excluded the seller's interest in 14 existing wells and 16 proposed future wells together with certain acreage surrounding these wells. +In May 2013, both escrow accounts terminated and an aggregate of $10.0 million was returned to the Company. The balance of the escrow accounts was distributed to the seller based on the results of the title review. +3. +ACCOUNTS RECEIVABLE—RELATED PARTIES +Included in the accompanying consolidated balance sheets as of December 31, 2013 and 2012 are amounts receivable from related parties of the Company. These receivables consist primarily of amounts billed by the Company to related parties as operator of such parties' Ohio and Colorado oil and natural gas properties. At December 31, 2013 and 2012 , these receivables totaled $2.6 million and $34.8 million , respectively. +Effective April 1, 2010, the Company entered into an area of mutual interest agreement with Windsor Niobrara LLC (“Windsor Niobrara”), an entity in which Gulfport's former Chairman is the operating member and holds a 10% contingent participating interest, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, exploiting and producing oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50% / 50% basis. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, Gulfport and Windsor Niobrara also entered into a development agreement, effective as of April 1, 2010, pursuant to which the Company and Windsor Niobrara agreed to jointly develop the contract area, and Gulfport agreed to act as the operator under the terms of a joint operating agreement. +For the year ended December 31, 2011 , the Company was reimbursed approximately $66,000 by Orange Leaf Holdings, LLC, a company controlled by Gulfport's prior Chairman, for office space which is included in other income (expense) in the consolidated statements of operations. +4. +PROPERTY AND EQUIPMENT +The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 2013 and 2012 are as follows: +December 31, +2013 +2012 +(In thousands) +Oil and natural gas properties +$ +2,477,178 +$ +1,611,090 +Office furniture and fixtures +6,093 +4,476 +Building +4,626 +3,926 +Land +412 +260 +Total property and equipment +2,488,309 +1,619,752 +Accumulated depletion, depreciation, amortization and impairment +(784,717 +) +(665,884 +) +Property and equipment, net +$ +1,703,592 +$ +953,868 +No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 2013 , 2012 or 2011 . +Included in oil and natural gas properties at December 31, 2013 and 2012 is the cumulative capitalization of $ 47.5 million and $32.6 million in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities +F-12 +Table of Contents +Index to Financial Statements +were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $ 14.9 million , $9.1 million and $5.4 million for the years ended December 31, 2013 , 2012 and 2011 , respectively. +The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2013 : +Costs Incurred in +2013 +2012 +2011 +Prior to 2011 +Total +(in thousands) +Acquisition costs +$ +342,857 +$ +493,981 +$ +106,704 +$ +1,068 +$ +944,610 +Exploration costs +— +— +— +— +— +Development costs +— +— +— +— +— +Capitalized interest +5,980 +— +— +— +5,980 +Total oil and gas properties not subject to amortization +$ +348,837 +$ +493,981 +$ +106,704 +$ +1,068 +$ +950,590 +The following table summarizes the Company’s non-producing properties excluded from amortization by area at December 31, 2013 : +December 31, 2013 +(In thousands) +Colorado +$ +6,054 +Bakken +295 +Southern Louisiana +542 +Ohio +943,654 +Other +45 +$ +950,590 +At December 31, 2012 , approximately $626.3 million of non-producing leasehold costs was not subject to amortization. +During the year ended December 31, 2012, the Company determined that further development of its non-producing leasehold assets located in Belize was not in alignment with its current strategic operating plan, and therefore, recognized a loss on disposal of assets, net of tax, of approximately $3.5 million which is included in discontinued operations on the accompanying consolidated statements of operations for the year ended December 31, 2012. +The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to occur within three to five years. +A reconciliation of the Company's asset retirement obligation for the years ended December 31, 2013 and 2012 is as follows: +December 31, +2013 +2012 +(In thousands) +Asset retirement obligation, beginning of period +$ +13,275 +$ +12,653 +Liabilities incurred +3,556 +2,195 +Liabilities settled +(2,465 +) +(2,271 +) +Accretion expense +717 +698 +Asset retirement obligation as of end of period +15,083 +13,275 +Less current portion +795 +60 +Asset retirement obligation, long-term +$ +14,288 +$ +13,215 +F-13 +Table of Contents +Index to Financial Statements +On May 7, 2012, the Company entered into a contribution agreement with Diamondback. Under the terms of the contribution agreement, the Company agreed to contribute to Diamondback, prior to the closing of the Diamondback initial public offering (“Diamondback IPO”), all its oil and natural gas interests in the Permian Basin (the "Contribution"). The Contribution was completed on October 11, 2012. At the closing of the Contribution, Diamondback issued to the Company (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $ 63.6 million , which was repaid to the Company at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of Diamondback O&G LLC, formerly Windsor Permian LLC ("Diamondback O&G"), as of the date of the Contribution. In January 2013, the Company received an additional payment from Diamondback of approximately $18.6 million as a result of this post-closing adjustment. Diamondback O&G is a wholly-owned subsidiary of Diamondback. Under the contribution agreement, the Company is generally responsible for all liabilities and obligations with respect to the contributed properties arising prior to the Contribution and Diamondback is responsible for such liabilities and obligations with respect to the contributed properties arising after the Contribution. +In accordance with the Company's policy under the full cost method of accounting to only recognize a gain or loss upon the disposal of oil and natural gas properties if such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves, the Company recognized a gain on the sale of its Permian Basin assets of approximately $7.3 million , which is included in the accompanying consolidated statements of operations for the year ended December 31, 2012 . In addition, the Company recorded a reduction to its full cost pool of approximately $213.0 million as a result of the Contribution. +In connection with the Contribution, the Company and Diamondback entered into an investor rights agreement under which the Company has the right, for so long as it beneficially owns more than 10% of Diamondback’s outstanding common stock, to designate one individual as a nominee to serve on Diamondback’s board of directors. Such nominee, if elected to Diamondback’s board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as the Company has the right to designate a nominee to Diamondback’s board and there is no Gulfport nominee actually serving as a Diamondback director, the Company has the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. The Company is also entitled to certain information rights and Diamondback granted the Company certain demand and “piggyback” registration rights obligating Diamondback to register with the SEC any shares of Diamondback common stock that the Company owns. Immediately upon completion of the Contribution, the Company owned a 35% equity interest in Diamondback, rather than leasehold interests in the Company’s Permian Basin acreage. Upon completion of the Diamondback IPO in October 2012, Gulfport owned approximately 21.4% of Diamondback's outstanding common stock. As of December 31, 2013, Gulfport owned approximately 7.2% of Diamondback's outstanding common stock. Following the Contribution, the Company has accounted for its interest in Diamondback as an equity investment. See Note 5, "Equity Investments - Diamondback Energy, Inc ." +F-14 +Table of Contents +Index to Financial Statements +5. +EQUITY INVESTMENTS +Investments accounted for by the equity method consist of the following as of December 31, 2013 and 2012 : +Carrying Value +(Income) loss from equity method investments +Approximate Ownership % +December 31, +For the Year Ended December 31, +2013 +2012 +2013 +2012 +2011 +(In thousands) +Investment in Tatex Thailand II, LLC +23.5 +% +$ +— +$ +203 +$ +(343 +) +$ +7 +$ +7 +Investment in Tatex Thailand III, LLC +17.9 +% +10,774 +8,657 +254 +251 +172 +Investment in Grizzly Oil Sands ULC +24.9999 +% +191,473 +172,766 +2,999 +1,512 +1,592 +Investment in Bison Drilling and Field Services LLC +40.0 +% +12,318 +13,518 +3,533 +373 +(357 +) +Investment in Muskie Proppant LLC +25.0 +% +7,544 +7,320 +1,975 +1,031 +4 +Investment in Timber Wolf Terminals LLC +50.0 +% +1,001 +878 +(6 +) +122 +— +Investment in Windsor Midstream LLC +22.5 +% +10,632 +9,503 +(1,125 +) +(663 +) +— +Investment in Stingray Pressure Pumping LLC +50.0 +% +19,624 +13,265 +(818 +) +1,235 +— +Investment in Stingray Cementing LLC +50.0 +% +3,291 +3,110 +93 +159 +— +Investment in Blackhawk Midstream LLC +50.0 +% +— +— +673 +436 +— +Investment in Stingray Logistics LLC +50.0 +% +903 +947 +51 +36 +— +Investment in Diamondback Energy, Inc. +7.2 +% +178,708 +151,317 +(220,129 +) +(12,821 +) +— +Investment in Stingray Energy Services LLC +50.0 +% +3,800 +— +(215 +) +— +— +$ +440,068 +$ +381,484 +$ +(213,058 +) +$ +(8,322 +) +$ +1,418 +The tables below summarize financial information for the Company's equity investments, excluding Diamondback, as of December 31, 2013 and 2012 . +Summarized balance sheet information: +December 31, +2013 +2012 +(In thousands) +Current assets +$ +84,107 +$ +68,459 +Noncurrent assets +$ +1,107,579 +$ +887,884 +Current liabilities +$ +112,406 +$ +74,308 +Noncurrent liabilities +$ +110,095 +$ +23,521 +Summarized results of operations: +December 31, +2013 +2012 +2011 +(In thousands) +Gross revenue +$ +162,401 +$ +39,918 +$ +16,955 +Net loss +$ +17,350 +$ +1,943 +$ +6,375 +Tatex Thailand II, LLC +The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”). Tatex holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a +F-15 +Table of Contents +Index to Financial Statements +reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. +Tatex Thailand III, LLC +The Company has an ownership interest in Tatex Thailand III, LLC ("Tatex III"). Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. During the year ended December 31, 2013 and 2012 , the Company paid cash calls of $2.4 million and $0.6 million , respectively. +Grizzly Oil Sands ULC +The Company, through its wholly owned subsidiary Grizzly Holdings Inc. ("Grizzly Holdings"), owns an interest in Grizzly Oil Sands ULC ("Grizzly"), a Canadian unlimited liability company. The remaining interest in Grizzly are owned by Grizzly Oil Sands Inc. ("Oil Sands"), an entity owned by certain investment funds managed by Wexford Capital LP ("Wexford"). As of December 31, 2013 , Grizzly had approximately 830,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. During the years ended December 31, 2013 and 2012 , Gulfport paid $ 33.9 million and $103.9 million , respectively, in cash calls. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was decreased by $12.2 million and $0.9 million as a result of a foreign currency translation loss for the years ended December 31, 2013 and 2011 , respectively, and increased by $1.4 million as a result of a foreign currency translation gain for the year ended December 31, 2012 . +The Company, through Grizzly Holdings, entered into a loan agreement with Grizzly effective January 1, 2008 , under which Grizzly borrowed funds from the Company. Borrowed funds initially bore interest at LIBOR plus 400 basis points and had an original maturity date of December 31, 2012 . Effective April 1, 2010 , the loan agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011 . Effective October 15, 2010 , the loan agreement was further amended to change the maturity date to December 31, 2012 . Interest was paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The Company loaned Grizzly approximately $3.2 million during the year ended December 31, 2011 . The Company recognized interest income of approximately $0.1 million for the year ended December 31, 2011 , which is included in interest income in the consolidated statements of operations. Effective December 7, 2011 , Grizzly Holdings Inc., entered into a debt settlement agreement with Grizzly under which Grizzly agreed to satisfy the entire outstanding debt by issuing additional common shares of Grizzly with no effect to the composition of ownership structure of Grizzly. At such date, the Company’s investment in Grizzly increased by the total $22.3 million outstanding advances and accrued interest due from Grizzly, the cumulative $0.1 million currency translation loss for the note receivable was adjusted through accumulated other comprehensive income and the note receivable was considered paid in full. +Bison Drilling and Field Services LLC +During 2011 , the Company invested in Bison Drilling and Field Services LLC (“Bison”). Bison owns and operates drilling rigs. During the years ended December 31, 2013 and 2012 , Gulfport paid $ 2.3 million and $7.5 million , respectively, in cash calls. +The Company entered into a loan agreement with Bison effective May 15, 2012, under which Bison may borrow funds from the Company. Interest accrues at LIBOR plus 0.28% or 8% , whichever is lower, and shall be paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan has a maturity date of January 31, 2015. The Company loaned Bison $1.6 million during the first nine months of 2012, all of which was repaid by Bison during the third quarter of 2012. The Company has made no loans to Bison since that time. +Muskie Proppant LLC +During 2011 , the Company invested in Muskie Proppant LLC (“Muskie”), formerly known as Muskie Holdings LLC. Muskie processes and sells sand for use in hydraulic fracturing by the oil and natural gas industry and holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. During the years ended December 31, 2013 and 2012 , Gulfport paid $ 2.2 million and $6.2 million , respectively, in cash calls. +The Company entered into a loan agreement with Muskie effective July 1, 2013, under which it loaned Muskie $0.9 million . Interest accrues at the prime rate plus 2.5% . The loan has a maturity date of July 31, 2014. At December 31, 2013 , the outstanding balance on the loan is included in notes receivable-related party on the accompanying consolidated balance sheets. +Timber Wolf Terminals LLC +F-16 +Table of Contents +Index to Financial Statements +During 2012, the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). The Company's initial investment during 2012 was $ 1.0 million . Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. During the year ended December 31, 2013 , Gulfport paid $0.1 million in cash calls. +Windsor Midstream LLC +During 2012, the Company purchased an ownership interest in Windsor Midstream LLC (“Midstream”) at a cost of $7.0 million . Midstream owns a 28.4% interest in MidMar Gas LLC, a gas processing plant in West Texas. During the year ended December 31, 2013 , Gulfport paid an immaterial amount in net cash calls to Midstream. During the year ended December 31, 2012 , Gulfport paid $1.8 million in cash calls. +Stingray Pressure Pumping LLC +During 2012, the Company invested in Stingray Pressure Pumping LLC ("Stingray Pressure"). Stingray Pressure provides well completion services. During the years ended December 31, 2013 and 2012 , the Company paid $ 1.8 million and $14.5 million , respectively, in cash calls. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. +Stingray Cementing LLC +During 2012, the Company invested in Stingray Cementing LLC ("Stingray Cementing"). Stingray Cementing provides well cementing services. During the year ended December 31, 2013 , the Company did not pay any cash calls related to Stingray Cementing. During the year ended December 31, 2012 , the Company paid $3.3 million in cash calls. The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. +Blackhawk Midstream LLC +During 2012, the Company invested in Blackhawk Midstream LLC ("Blackhawk"). Blackhawk coordinates gathering, compression, processing and marketing activities for the Company in connection with the development of its Utica Shale acreage. During the years ended December 31, 2013 and 2012 , the Company paid $0.7 million and $0.4 million , respectively, in cash calls related to Blackhawk. On January 28, 2014, Blackhawk closed on the sale of its equity interest in Ohio Gathering Company, LLC and Ohio Condensate Company, LLC for a purchase price of $190.0 million , of which $14.3 million was placed in escrow. Gulfport received $84.8 million in net proceeds from this transaction. +Stingray Logistics LLC +During 2012, the Company invested in Stingray Logistics LLC ("Stingray Logistics"). Stingray Logistics provides well services. During the year ended December 31, 2012 , the Company paid $1.0 million in cash calls. +Diamondback Energy, Inc. +As noted above in Note 4, on May 7, 2012, the Company entered into a contribution agreement with Diamondback. Following the closing of the Diamondback IPO, the Company owned approximately 21.4% of Diamondback's outstanding common stock for an initial investment in Diamondback of $ 138.5 million . On June 24, 2013, the Company sold 1,951,781 shares of its Diamondback common stock for net proceeds of $65.1 million in an underwritten public offering in which certain entities controlled by Wexford also participated as selling stockholders. On July 5, 2013, the underwriters purchased an additional 282,755 shares of Diamondback common stock from Gulfport pursuant to an option to purchase additional shares from the selling stockholders granted to the underwriters resulting in net proceeds to the Company of $9.4 million . The shares were sold to the public at $34.75 per share. On November 11, 2013, the Company sold 2,000,000 shares of its Diamondback common stock for net proceeds of $102.8 million in an underwritten public offering. On November 18, 2013, the underwriters purchased an additional 300,000 shares of Diamondback common stock from Gulfport pursuant to an option to purchase additional shares from the selling stockholder granted to the underwriters resulting in net proceeds to the Company of $15.4 million . The shares were sold to the public at $51.39 per share. As of December 31, 2013 , the Company owned approximately 7.2% of Diamondback's outstanding common stock. +The Company accounts for its interest in Diamondback as an equity method investment and has elected the fair value option of accounting for this investment. While the investment in Diamondback is below 20% ownership at December 31, 2013 , the Company has appointed a member of Diamondback's Board as discussed in Note 4; as the Company continues to +F-17 +Table of Contents +Index to Financial Statements +have influence through this board seat, the investment in Diamondback will continue to be accounted for as an equity method investment. The Company valued its investment in Diamondback using the quoted closing market price of Diamondback's stock on December 31, 2013 of $52.88 per share multiplied by the number of outstanding shares of Diamondback's stock held by the Company. The Company recognized an aggregate gain of approximately $220.1 million and $12.8 million on its investment in Diamondback for years ended December 31, 2013 and 2012 , respectively, which is included in (income) loss from equity method investments in the consolidated statements of operations. +The Company has determined that for the periods presented in its consolidated financial statements, Diamondback has met the conditions of a significant subsidiary under Rule 1-02(w) of Regulation S-X, for which the Company is required, pursuant to Rule 3-09 of Regulation S-X, to attach separate financial statements as exhibits to its Annual Report on Form 10-K. +Stingray Energy Services LLC +During 2013, the Company invested in Stingray Energy Services LLC ("Stingray Energy") at a cost of $2.9 million . Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites.The (income) loss from equity method investments presented in the table above reflects any intercompany profit eliminations. +6. +OTHER ASSETS +Other assets consist of the following as of December 31, 2013 and 2012 : +December 31, +2013 +2012 +(In thousands) +Plugging and abandonment escrow account on the WCBB properties (Note 16) +$ +3,105 +$ +3,113 +Certificates of Deposit securing letter of credit +275 +275 +Prepaid drilling costs +526 +515 +Loan commitment fees +9,341 +9,388 +Derivative receivable +4,493 +— +Deposits +34 +4 +Other +77 +— +$ +17,851 +$ +13,295 +7. +LONG-TERM DEBT +Long-term debt consisted of the following items as of December 31, 2013 and 2012 : +December 31, +2013 +2012 +(In thousands) +Revolving credit agreement (1) +$ +— +$ +— +Building loans (2) +1,995 +2,143 +7.75% senior unsecured notes due 2020 (3) +300,000 +300,000 +Unamortized original issue (discount) premium, net (4) +(2,808 +) +(3,105 +) +Less: current maturities of long term debt +(159 +) +(150 +) +Debt reflected as long term +$ +299,028 +$ +298,888 +Maturities of long-term debt (excluding premiums and discounts) as of December 31, 2013 are as follows: +F-18 +Table of Contents +Index to Financial Statements +(In thousands) +2014 +$ +159 +2015 +168 +2016 +1,668 +2017 +— +2018 +300,000 +Thereafter +— +Total +$ +301,995 +The Company capitalized approximately $7.1 million in interest expense to undeveloped oil and natural gas properties during the year ended December 31, 2013 . There was no interest expense capitalized during the year ended December 31, 2012 . +(1) On September 30, 2010, the Company entered into a $100.0 million senior secured revolving credit agreement with The Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association ("Amegy Bank"). The revolving credit facility initially matured on September 30, 2013 and had an initial borrowing base availability of $50.0 million , which was increased to $65.0 million effective December 24, 2010. The credit agreement is secured by substantially all of the Company’s assets. The Company’s wholly-owned subsidiaries guaranteed the obligations of the Company under the credit agreement. +On May 3, 2011, the Company entered into a first amendment to the revolving credit agreement with The Bank of Nova Scotia, Amegy Bank, KeyBank National Association (“KeyBank”) and Société Générale. Pursuant to the terms of the first amendment, KeyBank and Société Générale were added as additional lenders, the maximum amount of the facility was increased to $350.0 million , the borrowing base was increased to $90.0 million , certain fees and rates payable by the Company under the credit agreement were decreased, and the maturity date was extended until May 3, 2015. On October 31, 2011, the Company entered into additional amendments to its revolving credit facility pursuant to which, among other things, the borrowing base under this facility was increased to $125.0 million . +Effective May 2, 2012, the Company entered into a fourth amendment to its revolving credit facility under which, among other things, the borrowing base was increased to $155.0 million and Credit Suisse, Deutsche Bank Trust Company Americas and Iberiabank were added as additional lenders and Société Générale left the bank group. +On October 9, 2012 and October 17, 2012, the Company entered into a fifth amendment and a sixth amendment, respectively, to the revolving credit agreement. The fifth amendment modified certain covenants in the credit agreement to permit the Company to issue senior unsecured notes in an aggregate principal amount of up to $300.0 million and provided for a reduction in the borrowing base to an amount to be determined upon the completion of any senior unsecured notes issuance. The sixth amendment lowered the applicable rate set forth in the credit agreement (i) from a range of 1.00% to 1.75% to a range of 0.75% to 1.50% for the base rate loans and (ii) from a range of 2.00% to 2.75% to a range of 1.75% to 2.50% for the eurodollar rate loans and letters of credit. The sixth amendment lowered the commitment fees for Level 1 and Level 2 usage levels, in each case, from 0.50% per annum to 0.375% per annum. Also, effective as of October 17, 2012, in connection with the Company's completion of the offering of $250.0 million 7.75% senior unsecured notes due 2020, (the "October Notes"), the repayment of all outstanding amounts under the revolving credit agreement with the proceeds of the October Notes, and the contribution of Gulfport’s oil and natural gas interests in the Permian Basin to Diamondback discussed in Notes 4 and 5 above, Gulfport’s borrowing base under the credit agreement was reduced to $45.0 million until the next borrowing base redetermination. In conjunction with the lowering of the borrowing base in October 2012, the company expensed a proportional amount of the unamortized loan fees associated with the revolving credit facility totaling approximately $1.1 million , which is included in interest expense on the accompanying consolidated statements of operations. +On December 18, 2012, the Company entered into a seventh amendment to the revolving credit agreement under which the Company was permitted to issue $50.0 million 7.75% senior unsecured notes due 2020 (the "December Notes") under the same indenture as the October Notes (collectively, the "Notes"), and upon the issuance of the December Notes, the borrowing base under the revolving credit agreement was reduced from $45.0 million to $40.0 million until the next borrowing base redetermination. In conjunction with the lowering of the borrowing base in December 2012, the Company expensed a proportional amount of unamortized loan fees associated with the revolving credit facility totaling approximately $0.1 million , which is included in interest expense on the accompanying consolidated statements of operations. +F-19 +Table of Contents +Index to Financial Statements +On June 6, 2013, the Company entered into an eighth amendment to the revolving credit agreement. The eighth amendment lowered the applicable rate set forth in the revolving credit agreement (i) from a range of 1.75% to 2.50% to a range of 1.50% to 2.50% for eurodollar rate loans and (ii) from a range of 0.75% to 1.50% to a range of 0.50% to 1.50% for base rate loans. Additionally, the eighth amendment extended the maturity date from May 3, 2015 to June 6, 2018, provided for an increase in the borrowing base from $40.0 million to $50.0 million , and amended certain other provisions. +On December 27, 2013, the Company entered into an Amended and Restated Credit Agreement with The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and other lenders, which amends and restates in its entirety the Company's existing credit agreement, dated as of September 30, 2010, as amended. The Amended and Restated Credit Agreement provides for an increase in the maximum facility amount from $350.0 million to $1.5 billion , with an increase in borrowing base availability as of December 27, 2013 from $50.0 million to $150.0 million . The Amended and Restated Credit Agreement matures on June 6, 2018. As of December 31, 2013 , the Company had no borrowings outstanding under the revolving credit agreement. At December 31, 2013 , the total available funds under our revolving credit agreement, including a reduction for a $6.4 million letter of credit in effect, was $143.6 million . +Advances under the credit agreement, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50% , plus (2) the highest of: (a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from 1.50% to 2.50% , plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. +The credit agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability to: +• incur indebtedness; +• grant liens; +• pay dividends and make other restricted payments; +• make investments; +• make fundamental changes; +• enter into swap contracts and forward sales contracts; +• dispose of assets; +• change the nature of their business; and +• enter into transactions with affiliates. +The negative covenants are subject to certain exceptions as specified in the credit agreement. The credit agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: +(i) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offerings, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00 ; and +F-20 +Table of Contents +Index to Financial Statements +(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00 . +The Company was in compliance with all covenants at December 31, 2013 . +(2) In March 2011, the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matures in February 2016 and bears interest at the rate of 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. +(3) On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of October Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, (the "October Notes Offering") under an indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of December Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act ("the December Notes Offering"). The December Notes were issued as additional securities under the senior note indenture. The October Notes Offering and the December Notes Offering are collectively referred to as the "Notes Offerings". The Company used a portion of the net proceeds from the October Notes Offering to repay all amounts outstanding at such time under its revolving credit facility. The Company used the remaining net proceeds of October Notes Offering and the net proceeds of the December Notes Offering for general corporate purposes, which included funding a portion of its 2013 capital development plan. +Under the senior note indenture, interest on the Notes accrues at a rate of 7.75% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are the Company's senior unsecured obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt guarantee the Notes; provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior to November 1, 2016, the Company may redeem the Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Notes initially issued remains outstanding immediately after such redemption. +(4) The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an effective rate of 8.000% . The December Notes were issued at a price of 101.000% resulting in a gross premium of $0.5 million and an effective rate of 7.531% . The premium and discount are being amortized using the effective interest method. +Interest Expense +The following schedule shows the components of interest expense at December 31, 2013 and 2012 : +December 31, +2013 +2012 +2011 +(In thousands) +Cash paid for interest +$ +24,270 +$ +1,404 +$ +963 +Change in accrued interest +(969 +) +4,155 +(132 +) +Write-off of deferred loan costs +— +1,143 +— +Capitalized interest +(7,132 +) +— +— +Amortization of loan costs +1,012 +640 +540 +Amortization of note discount and premium +298 +59 +— +Other +11 +57 +29 +Total interest expense +$ +17,490 +$ +7,458 +$ +1,400 +F-21 +Table of Contents +Index to Financial Statements +8. +COMMON STOCK OPTIONS, WARRANTS AND CHANGES IN CAPITALIZATION +Options +The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is administered by the Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable period of such options. Eligible participants are defined as all directors of the Company, all officers of the Company and all key employees of the Company with a customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be granted under the Plan, as adjusted for changes in capitalization which have taken place since the Plan’s adoption, was 883,000 . The Company has granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, 2013 . No additional securities will be issued under the Plan other than upon exercise of options that are outstanding. +The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible participants options shall be granted, the number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. +On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) incentive stock options, (b) nonstatutory stock options, (c) restricted awards (restricted stock and restricted stock units), (d) performance awards and (e) stock appreciation rights and (ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 2013 , the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. No additional securities will be issued under the Plan other than upon exercise of options that are outstanding. +On April 19, 2013, the Company amended and restated the 2005 Plan with the 2013 Restated Stock Incentive Plan ("2013 Plan"). The 2013 Plan increased the numbers of shares that may be awarded from 3,000,000 to 7,500,000 shares, including the 627,337 shares underlaying options granted to employees under the Plan. The shares of stock issued once the options are exercised will be from authorized but unissued common stock. +Sale of Common Stock +On March 30, 2011, the Company completed the sale of an aggregate of 2,760,000 shares of its common stock in an underwritten public offering at a public offering price of $32.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $84.3 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. +On July 15, 2011, the Company completed the sale of an aggregate of 3,450,000 shares of its common stock in an underwritten public offering at a public offering price of $28.75 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $94.7 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. +On December 5, 2011, the Company completed the sale of an aggregate of 4,600,000 shares of its common stock in an underwritten public offering at a public offering price of $29.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $128.0 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the proceeds to fund capital expenditures associated with drilling, development and infrastructure, principally in the Utica Shale in Ohio and for general corporate purposes. +F-22 +Table of Contents +Index to Financial Statements +On December 24, 2012, the Company completed the sale of an aggregate of 11,750,000 shares of its common stock in an underwritten public offering (including the partial exercise of a 1,650,000 share over-allotment option granted to the underwriters, which option was initially exercised to the extent of 750,000 shares) at a public offering price of $38.00 per share less the underwriting discount. The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of common stock subject to the over-allotment option in a second closing, which occurred on January 7, 2013. The Company received aggregate net proceeds from both closings of approximately $460.7 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, as described above in Note 2, and for general corporate purposes, including the funding of a portion of its 2013 capital development plan. +On February 15, 2013, the Company completed the sale of an aggregate of 8,912,500 shares of its common stock in an underwritten public offering at a public offering price of $38.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $325.8 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of the net proceeds from this equity offering to fund its acquisition of additional Utica Shale acreage as described in Note 2, and the balance for general corporate purposes, including the funding of a portion of its 2013 capital development plan. +On November 13, 2013, the Company completed the sale of an aggregate of 7,475,000 shares of its common stock in an underwritten public offering at a public offering price of $56.75 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $408.0 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company has used and intends to continue to use the net proceeds from this equity offering for general corporate purposes, which may include expenditures associated with its 2014 drilling program and additional acreage acquisitions in the Utica Shale. +Private Placement Offering +In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred Stock, Series A, of the Company (the “Preferred”) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per share, of the Company (the “Warrants”). Holders of the Preferred were entitled to receive dividends at the rate of 12% of the liquidation preference per annum payable quarterly in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of Preferred at the rate of 15% of the liquidation preference per annum. All Preferred shares were redeemed in 2005. +The 2,322,962 Warrants issued had a term of 10 years and a current exercise price of $1.19 per share of common stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the Warrants. The 8,875 unexercised warrants expired on March 31, 2012. +9. +STOCK-BASED COMPENSATION +During the years ended December 31, 2013 , 2012 and 2011 the Company’s stock-based compensation cost was $ 10.5 million , $4.7 million and $1.3 million , respectively, of which the Company capitalized $ 4.2 million , $1.9 million and $0.5 million , respectively, relating to its exploration and development efforts. +The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon the historical experience of the Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant. +No stock options were issued during the years ended December 31, 2013 , 2012 and 2011 . +The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. +A summary of the status of stock options and related activity for the years ended December 31, 2013 , 2012 and 2011 is presented below: +F-23 +Table of Contents +Index to Financial Statements +Shares +Weighted +Average +Exercise Price +per Share +Weighted +Average +Remaining +Contractual Term +Aggregate +Intrinsic +Value (In thousands) +Options outstanding at December 31, 2010 +458,241 +$ +7.23 +4.48 +$ +6,621 +Granted +— +— +Exercised +(102,000 +) +9.74 +2,308 +Forfeited/expired +— +— +Options outstanding at December 31, 2011 +356,241 +6.51 +3.41 +$ +8,172 +Granted +— +— +Exercised +(21,000 +) +8.80 +628 +Forfeited/expired +— +— +Options outstanding at December 31, 2012 +335,241 +6.37 +2.39 +$ +10,678 +Granted +— +— +Exercised +(125,000 +) +11.20 +4,797 +Forfeited/expired +— +— +Options outstanding at December 31, 2013 +210,241 +$ +3.50 +1.07 +$ +12,538 +Options exercisable at December 31, 2013 +210,241 +$ +3.50 +1.07 +$ +12,538 +The following table summarizes information about the stock options outstanding at December 31, 2013 : +Exercise +Price +Number +Outstanding +Weighted Average +Remaining Life +(in years) +Number +Exercisable +$ +3.36 +205,241 +1.06 +205,241 +$ +9.07 +5,000 +1.69 +5,000 +210,241 +210,241 +The following table summarizes restricted stock activity for the twelve months ended December 31, 2013 , 2012 and 2011 : +Number of +Unvested +Restricted Shares +Weighted +Average +Grant Date +Fair Value +Unvested shares as of December 31, 2010 +113,386 +$ +11.72 +Granted +153,332 +31.15 +Vested +(63,370 +) +12.87 +Forfeited +— +— +Unvested shares as of December 31, 2011 +203,348 +$ +26.02 +Granted +196,832 +$ +35.87 +Vested +(135,015 +) +29.59 +Forfeited +(19,334 +) +26.81 +Unvested shares as of December 31, 2012 +245,831 +$ +31.88 +Granted +463,952 +$ +50.00 +Vested +(237,646 +) +41.79 +Forfeited +(8,500 +) +38.54 +Unvested shares as of December 31, 2013 +463,637 +$ +44.80 +Unrecognized compensation expense as of December 31, 2013 related to outstanding stock options and restricted shares was $ 19.2 million . The expense is expected to be recognized over a weighted average period of 1.65 years. +F-24 +Table of Contents +Index to Financial Statements +10. +FAIR VALUE OF FINANCIAL INSTRUMENTS +The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which approximates market value due to their short-term nature. Long-term debt related to the building loan is carried at cost, which approximates market value based on the borrowing rates currently available to the Company with similar terms and maturities. +At December 31, 2013 , the carrying value of the outstanding debt represented by the Notes was $ 297.2 million , including the remaining unamortized discount of approximately $3.2 million related to the October Notes and the remaining unamortized premium of approximately $ 0.4 million related to the December Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $ 320.8 million at December 31, 2013 . +The fair value of the derivative instruments is computed based on the difference between the prices provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis differentials, and for the Company's swaptions, market implied volatilities of the underlying commodity are also evaluated. Forward market prices for oil and natural gas are dependent upon supply and demand factors in such forward market and are subject to significant volatility. +11. +INCOME TAXES +The income tax provision for continuing operations consists of the following: +2013 +2012 +2011 +(In thousands) +Current: +State +$ +6,860 +$ +84 +$ +— +Federal +6,325 +646 +282 +Deferred: +State +7,385 +2,214 +— +Federal +77,566 +23,419 +(372 +) +Total income tax expense (benefit) provision from continuing operations +$ +98,136 +$ +26,363 +$ +(90 +) +A reconciliation of the statutory federal income tax amount to the recorded expense follows: +2013 +2012 +2011 +(In thousands) +Income from continuing operations before federal income taxes +$ +251,328 +$ +98,199 +$ +108,332 +Expected income tax at statutory rate +87,965 +34,370 +37,916 +State income taxes +9,297 +1,493 +4,227 +Other differences +874 +292 +(146 +) +Changes in valuation allowance +— +(9,792 +) +(42,087 +) +Income tax expense (benefit) recorded for continuing operations +$ +98,136 +$ +26,363 +$ +(90 +) +The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 2013 , 2012 and 2011 are estimated as follows: +F-25 +Table of Contents +Index to Financial Statements +2013 +2012 +2011 +(In thousands) +Deferred tax assets: +Net operating loss carryforward +$ +1,462 +$ +1,513 +$ +40,880 +FASB ASC 718 compensation expense +634 +762 +520 +Investment in pass through entities +— +— +78 +AMT credit +7,968 +1,643 +1,000 +Non-oil and gas property basis difference +— +— +103 +Charitable contributions carryover +25 +5 +3 +Unrealized loss on hedging activities +8,540 +3,836 +— +Foreign tax credit carryforwards +2,074 +2,074 +— +State net operating loss carryover +4,408 +4,315 +6,410 +Total deferred tax assets +25,111 +14,148 +48,994 +Valuation allowance for deferred tax assets +(4,743 +) +(4,629 +) +(12,347 +) +Deferred tax assets, net of valuation allowance +20,368 +9,519 +36,647 +Deferred tax liabilities: +Oil and gas property basis difference +72,173 +15,049 +35,637 +Investment in pass through entities +8,799 +3,618 +— +Non-oil and gas property basis difference +249 +227 +— +Investment in nonconsolidated affiliates +46,495 +9,232 +— +Unrealized gain on hedging activities +— +— +10 +Total deferred tax liabilities +127,716 +28,126 +35,647 +Net deferred tax asset (liability) +$ +(107,348 +) +$ +(18,607 +) +$ +1,000 +The Company has an available federal tax net operating loss carryforward estimated at approximately $4.2 million as of December 31, 2013 . This carryforward will begin to expire in the year 2023. Based upon the December 31, 2013 and 2012 net deferred tax liability position of the Company's oil and gas assets, management believes that this is a positive source of evidence to utilize the carryforward before it expires. Therefore, a valuation allowance has not been provided at December 31, 2013 and 2012 . A valuation allowance has been provided at December 31, 2011 because it was management’s belief at that time, based upon the Company’s past history of no taxable income and future projections of no taxable income during the carryforward period, it was more likely than not that the net deferred tax assets would not be realized. The Company also has state net operating loss carryovers of $84.8 million from Louisiana that will begin to expire in 2014, alternative minimum tax credits of $8.0 million with no expiration date and federal foreign tax credit carryovers of $2.1 million which begin to expire in 2017. The Company has recorded a valuation allowance of $4.7 million related to state net operating loss carryovers and foreign tax credit carryovers as the carryovers may not be utilized based upon a more likely than not basis. +In 2012, the Diamondback Contribution generated an estimated $61.9 million taxable gain. As a result, the Company recognized $9.8 million of its deferred tax assets which had previously been subject to a valuation allowance. The Company also recognized $25.6 million of deferred tax expense in 2012 primarily due to the utilization of prior net operating losses from the Diamondback Contribution gain. In 2013, the sale of Diamondback common shares generated $120.0 million taxable gain resulting in deferred tax expense of $35.7 million and current tax expense of $13.2 million . The Company's current federal tax expense in 2013 and 2012 is primarily attributable to alternative minimum tax. +F-26 +Table of Contents +Index to Financial Statements +12. +EARNINGS PER SHARE +Reconciliations of the components of basic and diluted net income per common share are presented in the tables below: +For the Year Ended December 31, +2013 +2012 +2011 +Income +Shares +Per +Share +Income +Shares +Per +Share +Income +Shares +Per Share +(In thousands, except share data) +Basic: +Net income +$ +153,192 +77,375,683 +$ +1.98 +$ +68,371 +55,933,354 +$ +1.22 +$ +108,422 +48,754,840 +$ +2.22 +Effect of dilutive securities: +Stock options and awards +— +485,963 +— +484,134 +— +452,123 +Diluted: +Net income +$ +153,192 +77,861,646 +$ +1.97 +$ +68,371 +56,417,488 +$ +1.21 +$ +108,422 +49,206,963 +$ +2.20 +There were no potential shares of common stock that were considered anti-dilutive for the years ended December 31, 2013 , 2012 and 2011 . +F-27 +Table of Contents +Index to Financial Statements +13. +HEDGING ACTIVITIES +Oil Price Hedging Activities +The Company seeks to reduce its exposure to unfavorable changes in oil and natural gas prices, which are subject to significant and often volatile fluctuation, by entering into fixed price swaps. These contracts allow the Company to predict with greater certainty the effective oil and natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. +The Company accounts for its oil and natural gas derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related pronouncements. All derivative contracts are marked to market each quarter end and are included in the accompanying consolidated balance sheets as derivative assets and liabilities. +During 2012 and 2013, the Company entered into fixed price swap and swaption contracts for 2013 through 2016 with four financial institutions. The Company’s fixed price swap contracts are tied to the commodity prices on the International Petroleum Exchange (“IPE”) and NYMEX. The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price as listed on the IPE for Brent Crude and the NYMEX WTI for oil and on the NYMEX Henry Hub for natural gas. At December 31, 2013 , the Company had the following fixed price swaps in place: +Daily Volume +(Bbls/day) +Weighted +Average Price +January - March 2014 +4,000 +$ +104.75 +April - December 2014 +2,000 +$ +101.50 +Daily Volume (MMBtu/day) +Weighted +Average Price +January 2014 +65,000 +$ +4.04 +February - December 2014 +105,000 +$ +4.01 +January - December 2015 +125,000 +$ +4.03 +January - March 2016 +105,000 +$ +4.04 +April 2016 +95,000 +$ +4.04 +At December 31, 2013 the fair value of derivative assets and liabilities related to the fixed price swaps and swaptions was as follows: +(In thousands) +Short-term derivative instruments - asset +$ +324 +Long-term derivative instruments - asset +$ +521 +Short-term derivative instruments - liability +$ +12,280 +Long-term derivative instruments - liability +$ +11,366 +At December 31, 2012 the fair value of derivative assets and liabilities related to the fixed price swaps and swaptions was as follows: +(In thousands) +Short-term derivative instruments - asset +$ +664 +Short-term derivative instruments - liability +$ +10,442 +All fixed price swaps and swaptions have been executed in connection with the Company’s oil and natural gas price hedging program. For fixed price swaps qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract price is included in oil and gas sales in the period for which the underlying production was hedged. +F-28 +Table of Contents +Index to Financial Statements +For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income (loss) until the hedged item is recognized in earnings. Amounts reclassified out of accumulated other comprehensive income (loss) into earnings as a component of oil and condensate sales for the years ended December 31, 2013 and 2012 are presented below. +Year Ended December 31, +2013 +2012 +2011 +(In thousands) +Reduction to oil and condensate sales +$ +(9,779 +) +$ +(1,517 +) +$ +(4,720 +) +At December 31, 2013 , no amounts related to fixed price swaps remain in accumulated other comprehensive income (loss). +The following table presents the balances of the Company’s cumulative hedging activities included in other comprehensive income. +(In thousands) +December 31, 2010 +$ +(4,720 +) +December 31, 2011 +$ +1,576 +December 31, 2012 +$ +(9,660 +) +December 31, 2013 +$ +— +Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company recognized a loss of $18.2 million related to hedge ineffectiveness for the year ended December 31, 2013 , which is included in oil and condensate and gas sales in the consolidated statements of operations. This loss was comprised of a loss of $9.1 million related to hedge ineffectiveness and a loss of $9.1 million related to the amortization of other comprehensive income for the year ended December 31, 2013 . The Company recognized a loss of $0.1 million related to hedge ineffectiveness for the year ended December 31, 2012 , which is included in oil and condensate sales in the consolidated statements of operations. The Company recognized an immaterial gain related to hedge ineffectiveness for the year ended December 31, 2011 , which is included in oil and condensate sales in the consolidated statements of operations. +The Company delivered approximately 48% of its 2013 production under fixed price swaps. +14. +FAIR VALUE MEASUREMENTS +The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with FASB ASC 820. FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and disclosed in one of the following categories: +Level 1 – Quoted prices in active markets for identical assets and liabilities. +Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. +Level 3 – Significant inputs to the valuation model are unobservable. +Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. +The following tables summarize the Company’s financial and non-financial liabilities by FASB ASC 820 valuation level as of December 31, 2013 and 2012 : +F-29 +Table of Contents +Index to Financial Statements +December 31, 2013 +Level 1 +Level 2 +Level 3 +(In thousands) +Assets: +Fixed price swaps +$ +— +$ +845 +$ +— +Equity investment in Diamondback +178,708 +— +— +Liabilities: +Fixed price swaps and swaptions +$ +— +$ +23,646 +$ +— +December 31, 2012 +Level 1 +Level 2 +Level 3 +(In thousands) +Assets: +Fixed price swaps +$ +— +$ +664 +$ +— +Equity investment in Diamondback +151,317 +— +— +Liabilities: +Fixed price swaps +$ +— +$ +10,442 +$ +— +The estimated fair value of the Company’s fixed price swap contracts and swaptions were based upon forward commodity prices based on quoted market prices, adjusted for differentials, and for the Company's swaptions, market implied volatilities of the underlying commodity were also evaluated. See Note 13 for further discussion of the Company's hedging activities. The estimated fair value of the Company's equity investment in Diamondback was based upon the public closing share price of Diamondback's common stock as of December 31, 2013 . +The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations ” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the year ended December 31, 2013 were approximately $ 3.6 million . +15. +RELATED PARTY TRANSACTIONS +In the ordinary course of business, the Company conducts business activities with certain related parties. +Diamondback operates the Permian Basin wells included in the Contribution as discussed above in Note 4. At December 31, 2012 , the Company owed Diamondback approximately $0.3 million related to reimbursement for services provided prior to the contribution. Approximately $7.1 million of services provided by Diamondback are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2012 . Approximately $40.4 million related to services performed by Diamondback are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 . +As discussed in Note 3, Gulfport is the operator of its Niobrara Formation acreage under a development agreement with Windsor Niobrara. As operator, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the years ended December 31, 2013 and 2012 , the Company billed Windsor Niobrara approximately $0.9 million and $7.5 million , respectively, for these services. At December 31, 2013 , Windsor Niobrara owed the Company an immaterial amount for these services. At December 31, 2012 , Windsor Niobrara owed the Company approximately $0.2 million for these services. +Windsor Ohio LLC ("Windsor Ohio") participated with the Company in the acquisition of certain leasehold interests in acreage located in the Utica Shale in Ohio. As operator of this acreage, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the years ended December 31, 2013 and 2012 , the Company billed Windsor Ohio approximately $73.4 million and $163.7 million , respectively, for these services. +F-30 +Table of Contents +Index to Financial Statements +At December 31, 2013 and 2012 , Windsor Ohio owed the Company approximately $1.6 million and $6.5 million , respectively, for these services. During the years ended December 31, 2013 and 2012 , the Company purchased certain oil and natural gas properties in the Utica Shale from Windsor Ohio. For information regarding these transactions, see Note 2. +Rhino Exploration LLC ("Rhino") participated with the Company in the acquisition of certain leasehold interest in acreage located in the Utica Shale in Ohio. As operator of this acreage, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2012 , the Company billed Rhino approximately $4.4 million for these services. At December 31, 2012 , Rhino owed the Company approximately $4.3 million for these services. +Stingray Pressure, which is 50% owned by the Company, provides well completion services as discussed above in Note 5. At December 31, 2013 and 2012 , the Company owed Stingray Pressure approximately $8.3 million and $5.3 million , respectively, related to these services. Approximately $58.3 million and $4.3 million of services provided by Stingray Pressure are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2013 and 2012 , respectively. +Stingray Cementing, which is 50% owned by the Company, provides well cementing services as discussed above in Note 5. At December 31, 2013 , the Company owed Stingray Cementing approximately $1.5 million related to these services. No amounts were owed to Stingray Cementing at December 31, 2012 . Approximately $4.0 million of services provided by Stingray Cementing are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2013 . +Stingray Energy, which is 50% owned by the Company, provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites as discussed above in Note 5. At December 31, 2013 , the Company owed Stingray Energy approximately $4.1 million related to these services. Approximately $5.1 million of services provided by Stingray Energy are included in oil and natural gas properties before elimination of intercompany profits on the accompanying consolidated balance sheets at December 31, 2013 . +Athena Construction LLC (“Athena”) performs services for the Company at its WCBB and Hackberry fields. At December 31, 2013 and 2012 , the Company owed Athena approximately $1.0 million and $1.5 million , respectively, related to these services. Approximately $0.6 million and $0.4 million of services provided by Athena are included in lease operating expenses in the consolidated statements of operations for the year ended December 31, 2013 and 2012 , respectively. Approximately $4.1 million and $5.0 million related to services performed by Athena are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2013 and 2012 , respectively. +Black Fin P&A, LLC (“Black Fin”) performs plugging and abandonment services for the Company at its WCBB field. No amounts were owed to Black Fin at December 31, 2013 and 2012 . An immaterial amount of services performed by Black Fin are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2013 . Approximately $0.7 million of services performed by Black Fin are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 . +Panther Drilling Systems, LLC ("Panther") performs directional drilling services for the Company. At December 31, 2013 and 2012 , the Company owed Panther approximately $1.8 million and an immaterial amount, respectively, related to these services. Approximately $12.6 million and an immaterial amount of services provided by Panther are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2013 and 2012 , respectively. +Redback Directional Services, LLC ("Redback") provides coil tubing and flow back services for the Company. No amounts were owed to Redback at December 31, 2013 . At 2012 the Company owed Redback $1.1 million related to these services. Approximately $0.1 million and $1.8 million related to services performed by Redback are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2013 and 2012 , respectively. +Caliber Development Company, LLC ("Caliber") provides building maintenance services for the Company's headquarters in Oklahoma City, Oklahoma. Caliber also leases office space to the Company. At December 31, 2013 and 2012 , the Company owed Caliber an immaterial amount related to these services. Approximately $0.2 million and $0.1 million of services performed by Caliber and rent paid to Caliber are included in general and administrative expenses on the accompanying consolidated statements of operations for the year ended December 31, 2013 and 2012 , respectively. +F-31 +Table of Contents +Index to Financial Statements +Each of Diamondback, Windsor Niobrara, Windsor Ohio, Rhino, Stingray Pressure, Stingray Cementing, Stingray Energy, Stingray Logistics, Athena, Black Fin, Panther, Redback and Caliber is affiliated with or controlled by Wexford. Prior to September 21, 2012, Wexford and/or its affiliates beneficially owned more than 10% of the Company's common stock and was deemed to be a related party. On or about September 28, 2012, Wexford’s and/or its affiliates’ ownership of Gulfport’s common stock dropped to below 1% and, as a result, was no longer deemed to be a related party. Subsequent to September 28, 2012, the Company continued to treat Windsor Niobrara, Windsor Ohio, Athena, Black Fin, Panther, Redback and Caliber as related parties because Mr. Mike Liddell, the Company's former Chairman of the Board and a named executive officer during 2013, is the operating member of each such entity and also holds a 10% participation interest in Windsor Ohio and a 10% contingent participation interest in Windsor Niobrara, Athena, Black Fin, Panther, Redback and Caliber. During December 2012, Mr. Liddell had transferred his participation in Windsor Ohio to an entity he controlled. For the year ended December 31, 2012 , the Company billed this entity directly in respect of his 10% interest in the amount of approximately $2.0 million . For the year ended December 31, 2012 , the Company paid this entity approximately $0.1 million in respect of its interest in Windsor Ohio. +16. +COMMITMENTS +Plugging and Abandonment Funds +In connection with the Company's acquisition in 1997 of the remaining 50% interest in its WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of December 31, 2013 , the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2013 , the Company had plugged 354 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its current minimum plugging obligation. +Contributions to 401(k) Plan +Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 100% of their total compensation up to the maximum pre-tax threshold through salary deferrals. Also under the plan, the Company will make a contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals and may also make additional discretionary contributions. During the years ended December 31, 2013 , 2012 and 2011 , Gulfport incurred $0.6 million , $0.4 million , and $0.3 million , respectively, in contributions expense related to this plan. +Employment Agreements +Effective November 1, 2012, the Company entered into employment agreements with its executive officers, each with an initial three -year term that expires on November 1, 2015 subject to automatic one -year extensions unless terminated by either party to the agreement at least 90 days prior to the end of the then current term. These agreements provide for minimum salary and bonus levels which are subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's Amended and Restated 2005 Stock Incentive Plan (or other equity incentive plans that may be put in place for the benefit of employees) and other employee benefits. The aggregate minimum commitment for future salaries and bonuses at December 31, 2013 was approximately $ 3.5 million . +Gulfport's former Chairman, Mr. Liddell, resigned effective June 2013 at which date his employment agreement with Gulfport terminated. At that same date, the Company entered into a consulting agreement with Mr. Liddell. The minimum commitment under the consulting agreement at December 31, 2013 was approximately $1.1 million . +Firm Transportation Commitments +As of December 31, 2013 , the Compay had approximately 183,000 MMBtu per day of firm sales contracted with third parties. Of these sales, 33,000 MMBtu per day, 100,000 MMBtu per day and 50,000 MMBtu per day expire in 2015, 2016 and 2017, respectively. +F-32 +Table of Contents +Index to Financial Statements +Operating Leases +The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these leases at December 31, 2013 are as follows: +(In thousands) +2014 +$ +536 +2015 +494 +2016 +426 +2017 +398 +Total +$ +1,854 +The following table presents rent expense for the years ended December 31, 2013 , 2012 and 2011 , respectively. +For the years ended December 31, +2013 +2012 +2011 +(In thousands) +Minimum rentals +$ +258 +$ +139 +$ +52 +Less: Sublease rentals +45 +7 +— +$ +213 +$ +132 +$ +52 +17. CONTINGENCIES +The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale of oil under fixed price contracts during the years 2005 through 2007. The LDR maintains that Gulfport paid approximately $1.8 million less in severance taxes under fixed price terms than the severance taxes Gulfport would have had to pay had it paid severance taxes on the oil at the contracted market rates only. Gulfport has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. Gulfport has maintained its right to contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette Parish, in Louisiana against Gulfport seeking $2.3 million in severance taxes, plus interest and court costs. Gulfport filed a response denying any liability to the LDR for underpayment of severance taxes. The LDR had taken no further action on this lawsuit since filing its petition other than propounding discovery requests to which Gulfport has responded. Since serving discovery requests on the LDR and receiving the LDR's responses in 2012, there has been no further activity on the case and no trial date has been set. +In December 2010, the LDR filed two identical lawsuits against Gulfport in different venues (the 15th Judicial District Court and the 19th Judicial Court) to recover allegedly underpaid severance taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any specific claim for damages or unpaid taxes. As with the lawsuit filed by the LDR in 2009 discussed in the paragraph above, Gulfport denies all liability and will vigorously defend the lawsuit. The LDR filed motions to stay the lawsuits before Gulfport filed any responsive pleadings. After years of no activity on either of these lawsuits, the LDR recently moved to dismiss one of the identical lawsuits it filed in the 19th Judicial District Court in 2010, amended the petition it filed in the 15th Judicial District Court in 2010 and served discovery requests on Gulfport. The LDR asserts that Gulfport underpaid severance taxes by nearly $12 million from 2007 to 2010. The LDR also asserts that Gulfport owes an additional $4.4 million and may be subject to additional penalties. In 2013, the LDR asserted that Gulfport owes additional severance taxes in connection with the cash settlements it received to terminate forward sales contracts. The LDR's claims are still in their infancy and there has been no formal discovery. Gulfport maintains that the LDR's claims are not well-grounded in fact or law and intends to aggressively defend the lawsuits. +On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for surface contamination in areas where the defendants operated in an action entitled Reeds et al. v. BP American +F-33 +Table of Contents +Index to Financial Statements +Production Company et al.,38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name Gulfport as a defendant, alleges that the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. The plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and response costs and stigma damages. On December 7, 2010, Gulfport was served with a copy of the plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including Gulfport, bringing the total number of defendants to 21 . It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income; attorney fees and expenses and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to Gulfport, current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, Gulfport filed a pleading challenging the legal sufficiency of the petitions on several grounds and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by Gulfport and similar pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue. In response, Gulfport and numerous defendants re-urged their pleadings challenging the legal sufficiency of the petitions. Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the court on May 25, 2011 and were denied. The court signed the written judgment on December 9, 2011. Gulfport noticed its intent to seek supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application. Gulfport filed its supervisory writ, which was denied by the Louisiana Third Circuit Court of Appeal and the Louisiana Supreme Court. The parties engaged in a non-binding mediation in July 2013 and discussion are on-going. At this time, the parties are continuing to conduct discovery. The trial date has been continued to July 2014. +Due to the early stages of the LDR and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that may result. In each case, management has determined the possibility of loss is remote. However, litigation is inherently uncertain. Adverse decisions in one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations and management cannot determine the amount of loss, if any, that may result. +The Company has been named as a defendant in various other lawsuits related to its business. In each such case, management has determined that the possibility of loss is remote. The resolution of these matters is not expected to have a material adverse effect on the Company's financial condition or results of operations in future periods. +Concentration of Credit Risk +Gulfport operates in the oil and gas industry principally in the state of Louisiana with sales to refineries, re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue to be immaterial to the Company’s results of operations in the long term. +The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000 . At December 31, 2013 , Gulfport held cash in excess of insured limits in these banks totaling $457.7 million . +During the year ended December 31, 2013 , Gulfport sold approximately 99% of its oil production to Shell Trading Company (“Shell”), 100% of its natural gas liquids production to Markwest Utica and 32% , 31% and 17% of its natural gas production to Sequent Energy Management, L.P., Hess and Interstate Gas Supply, Inc., respectively. During the year ended December 31, 2012 , Gulfport sold approximately 92% and 8% of its oil production to Shell and Diamondback O&G, respectively, 91% of its natural gas liquids production to Diamondback O&G, and 41% , 18% and 16% of its natural gas +F-34 +Table of Contents +Index to Financial Statements +production to Noble Americas Gas, Hess and Chevron, respectively. During the year ended December 31, 2011 , Gulfport sold approximately 93% and 7% of its oil production to Shell and Diamondback O&G, respectively, 100% of its natural gas liquids production to Diamondback O&G and 50% , 27% , and 22% of its natural gas production to Hilcorp Energy Company, Chevron, and Diamondback O&G, respectively. +18. +CONDENSED CONSOLIDATING FINANCIAL INFORMATION +On October 17, 2012 and December 21, 2012, the Company issued an aggregate of $300.0 million of its 7.75% Senior Notes (the "Notes"). The Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company's secured revolving credit facility or certain other debt (the "Guarantors"). The Notes are not guaranteed by Grizzly Holdings, Inc., (the "Non-Guarantor"). The Guarantors are 100% owned by Gulfport (the "Parent"), and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan. +The following condensed consolidating balance sheets, statements of operations, statements of comprehensive income (loss) and statements of cash flows are provided for the Parent, the Guarantors and the Non-Guarantor and include the consolidating adjustments and eliminations necessary to arrive at the information for the Company on a condensed consolidated basis. The information has been presented using the equity method of accounting for the Parent's ownership of the Guarantors and the Non-Guarantor. +F-35 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING BALANCE SHEETS +(Amounts in thousands) +December 31, 2013 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Assets +Current assets: +Cash and cash equivalents +$ +451,431 +$ +7,525 +$ +— +$ +— +$ +458,956 +Accounts receivable - oil and gas +58,662 +162 +— +— +58,824 +Accounts receivable - related parties +2,617 +— +— +— +2,617 +Accounts receivable - intercompany +21,379 +27 +— +(21,406 +) +— +Prepaid expenses and other current assets +2,581 +— +— +— +2,581 +Deferred tax asset +6,927 +— +— +— +6,927 +Short-term derivative instruments +324 +— +— +— +324 +Note receivable - related party +875 +— +— +— +875 +Total current assets +544,796 +7,714 +— +(21,406 +) +531,104 +Property and equipment: +Oil and natural gas properties, full-cost accounting +2,470,411 +7,340 +— +(573 +) +2,477,178 +Other property and equipment +11,102 +29 +— +— +11,131 +Accumulated depletion, depreciation, amortization and impairment +(784,695 +) +(22 +) +— +— +(784,717 +) +Property and equipment, net +1,696,818 +7,347 +— +(573 +) +1,703,592 +Other assets: +Equity investments and investments in subsidiaries +432,727 +— +191,473 +(184,132 +) +440,068 +Derivative instruments +521 +— +— +— +521 +Other assets +17,851 +— +— +— +17,851 +Total other assets +451,099 +— +191,473 +(184,132 +) +458,440 +Total assets +$ +2,692,713 +$ +15,061 +$ +191,473 +$ +(206,111 +) +$ +2,693,136 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +190,284 +$ +423 +$ +— +$ +— +$ +190,707 +Accounts payable - intercompany +— +21,296 +110 +(21,406 +) +— +Asset retirement obligation - current +795 +— +— +— +795 +Short-term derivative instruments +12,280 +— +— +— +12,280 +Current maturities of long-term debt +159 +— +— +— +159 +Total current liabilities +203,518 +21,719 +110 +(21,406 +) +203,941 +Long-term derivative instrument +11,366 +— +— +— +11,366 +Asset retirement obligation - long-term +14,288 +— +— +— +14,288 +Deferred tax liability +114,275 +— +— +— +114,275 +Long-term debt, net of current maturities +299,028 +— +— +— +299,028 +Total liabilities +642,475 +21,719 +110 +(21,406 +) +642,898 +Stockholders' equity: +Common stock +851 +— +— +— +851 +Paid-in capital +1,813,058 +322 +208,277 +(208,599 +) +1,813,058 +Accumulated other comprehensive income (loss) +(9,781 +) +— +(9,781 +) +9,781 +(9,781 +) +Retained earnings (accumulated deficit) +246,110 +(6,980 +) +(7,133 +) +14,113 +246,110 +Total stockholders' equity +2,050,238 +(6,658 +) +191,363 +(184,705 +) +2,050,238 +Total liabilities and stockholders' equity +$ +2,692,713 +$ +15,061 +$ +191,473 +$ +(206,111 +) +$ +2,693,136 +F-36 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING BALANCE SHEETS +(Amounts in thousands) +December 31, 2012 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Assets +Current assets: +Cash and cash equivalents +$ +165,293 +$ +1,795 +$ +— +$ +— +$ +167,088 +Accounts receivable - oil and gas +25,070 +545 +— +— +25,615 +Accounts receivable - related parties +33,806 +1,042 +— +— +34,848 +Accounts receivable - intercompany +15,368 +(15,368 +) +— +Prepaid expenses and other current assets +1,506 +— +— +— +1,506 +Short-term derivative instruments +664 +— +— +— +664 +Total current assets +241,707 +3,382 +— +(15,368 +) +229,721 +Property and equipment: +Oil and natural gas properties, full-cost accounting, +1,606,172 +4,918 +— +— +1,611,090 +Other property and equipment +8,642 +20 +— +— +8,662 +Accumulated depletion, depreciation, amortization and impairment +(665,864 +) +(20 +) +— +— +(665,884 +) +Property and equipment, net +948,950 +4,918 +— +— +953,868 +Other assets: +Equity investments and investments in subsidiaries +374,209 +— +172,766 +(165,491 +) +381,484 +Other assets +13,295 +— +— +— +13,295 +Total other assets +387,504 +— +172,766 +(165,491 +) +394,779 +Total assets +$ +1,578,161 +$ +8,300 +$ +172,766 +$ +(180,859 +) +$ +1,578,368 +Liabilities and Stockholders' Equity +Current liabilities: +Accounts payable and accrued liabilities +$ +110,037 +$ +207 +$ +— +$ +— +$ +110,244 +Accounts payable - intercompany +— +15,259 +109 +(15,368 +) +— +Asset retirement obligation - current +60 +— +— +— +60 +Short-term derivative instruments +10,442 +— +— +— +10,442 +Current maturities of long-term debt +150 +— +— +— +150 +Total current liabilities +120,689 +15,466 +109 +(15,368 +) +120,896 +Asset retirement obligation - long-term +13,215 +— +— +— +13,215 +Deferred tax liability +18,607 +— +— +— +18,607 +Long-term debt, net of current maturities +298,888 +— +— +— +298,888 +Other non-current liabilities +354 +— +— +— +354 +Total liabilities +451,753 +15,466 +109 +(15,368 +) +451,960 +Stockholders' equity: +Common stock +674 +— +— +— +674 +Paid-in capital +1,036,245 +322 +174,348 +(174,670 +) +1,036,245 +Accumulated other comprehensive income (loss) +(3,429 +) +— +2,442 +(2,442 +) +(3,429 +) +Retained earnings (accumulated deficit) +92,918 +(7,488 +) +(4,133 +) +11,621 +92,918 +Total stockholders' equity +1,126,408 +(7,166 +) +172,657 +(165,491 +) +1,126,408 +Total liabilities and stockholders' equity +$ +1,578,161 +$ +8,300 +$ +172,766 +$ +(180,859 +) +$ +1,578,368 +F-37 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS +(Amounts in thousands) +Year Ended December 31, 2013 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Total revenues +$ +261,809 +$ +1,517 +$ +— +$ +(573 +) +$ +262,753 +Costs and expenses: +Lease operating expenses +25,971 +732 +— +— +26,703 +Production taxes +26,848 +85 +— +— +26,933 +Midstream transportation, processing and marketing +10,999 +31 +— +— +11,030 +Depreciation, depletion, and amortization +118,878 +2 +— +— +118,880 +General and administrative +22,359 +159 +1 +— +22,519 +Accretion expense +717 +— +— +— +717 +Loss on sale of assets +508 +— +— +— +508 +206,280 +1,009 +1 +— +207,290 +INCOME (LOSS) FROM OPERATIONS +55,529 +508 +(1 +) +(573 +) +55,463 +OTHER (INCOME) EXPENSE: +Interest expense +17,490 +— +— +— +17,490 +Interest income +(297 +) +— +— +— +(297 +) +(Income) loss from equity method investments and investments in subsidiaries +(212,992 +) +— +2,999 +(3,065 +) +(213,058 +) +(195,799 +) +— +2,999 +(3,065 +) +(195,865 +) +INCOME (LOSS) BEFORE INCOME TAXES +251,328 +508 +(3,000 +) +2,492 +251,328 +INCOME TAX EXPENSE +98,136 +— +— +— +98,136 +NET INCOME (LOSS) +$ +153,192 +$ +508 +$ +(3,000 +) +$ +2,492 +$ +153,192 +F-38 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS +(Amounts in thousands) +Year Ended December 31, 2012 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Total revenues +$ +247,637 +$ +1,289 +$ +— +$ +— +$ +248,926 +Costs and expenses: +Lease operating expenses +23,644 +664 +— +— +24,308 +Production taxes +28,874 +83 +— +— +28,957 +Midstream transportation, processing and marketing +432 +11 +443 +Depreciation, depletion, and amortization +90,749 +— +— +— +90,749 +General and administrative +13,602 +132 +74 +— +13,808 +Accretion expense +698 +— +— +— +698 +Gain on sale of assets +(7,300 +) +— +— +— +(7,300 +) +150,699 +890 +74 +— +151,663 +INCOME (LOSS) FROM OPERATIONS +96,938 +399 +(74 +) +— +97,263 +OTHER (INCOME) EXPENSE: +Interest expense +7,458 +— +— +— +7,458 +Interest income +(72 +) +— +— +— +(72 +) +(Income) loss from equity method investments and investments in subsidiaries +(5,182 +) +— +1,512 +(4,652 +) +(8,322 +) +2,204 +— +1,512 +(4,652 +) +(936 +) +INCOME (LOSS) FROM COTINUING OPERATIONS BEFORE INCOME TAXES +94,734 +399 +(1,586 +) +4,652 +98,199 +INCOME TAX EXPENSE +26,363 +— +— +— +26,363 +INCOME (LOSS) FROM CONTINUING OPERATIONS +68,371 +399 +(1,586 +) +4,652 +71,836 +DISCONTINUED OPERATIONS +Loss on disposal of Belize properties, net of tax +— +3,465 +— +— +3,465 +NET INCOME (LOSS) +$ +68,371 +$ +(3,066 +) +$ +(1,586 +) +$ +4,652 +$ +68,371 +F-39 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS +(Amounts in thousands) +Year Ended December 31, 2011 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Total revenues +$ +228,281 +$ +973 +$ +— +$ +— +$ +229,254 +Costs and expenses: +Lease operating expenses +20,168 +729 +— +— +20,897 +Production taxes +25,991 +63 +— +— +26,054 +Midstream transportation, processing and marketing +275 +4 +— +— +279 +Depreciation, depletion, and amortization +62,320 +— +— +— +62,320 +General and administrative +8,038 +11 +25 +— +8,074 +Accretion expense +666 +— +— +— +666 +117,458 +807 +25 +— +118,290 +INCOME (LOSS) FROM OPERATIONS +110,823 +166 +(25 +) +— +110,964 +OTHER (INCOME) EXPENSE: +Interest expense +1,400 +— +— +— +1,400 +Interest income +(39 +) +— +(147 +) +— +(186 +) +(Income) loss from equity method investments and investments in subsidiaries +1,130 +— +1,592 +(1,304 +) +1,418 +2,491 +— +1,445 +(1,304 +) +2,632 +INCOME (LOSS) BEFORE INCOME TAXES +108,332 +166 +(1,470 +) +1,304 +108,332 +INCOME TAX BENEFIT +(90 +) +— +— +— +(90 +) +NET INCOME (LOSS) +$ +108,422 +$ +166 +$ +(1,470 +) +$ +1,304 +$ +108,422 +F-40 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(Amounts in thousands) +Year Ended December 31, 2013 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Net income (loss) +$ +153,192 +$ +508 +$ +(3,000 +) +$ +2,492 +$ +153,192 +Foreign currency translation adjustment +(12,223 +) +— +(12,223 +) +12,223 +(12,223 +) +Change in fair value of derivative instruments, net of taxes +(4,419 +) +— +— +— +(4,419 +) +Reclassification of settled contracts, net of taxes +10,290 +— +— +— +10,290 +Other comprehensive income (loss) +(6,352 +) +— +(12,223 +) +12,223 +(6,352 +) +Comprehensive income +$ +146,840 +$ +508 +$ +(15,223 +) +$ +14,715 +$ +146,840 +Year Ended December 31, 2012 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Net income (loss) +$ +68,371 +$ +(3,066 +) +$ +(1,586 +) +$ +4,652 +$ +68,371 +Foreign currency translation adjustment +1,355 +— +1,355 +(1,355 +) +1,355 +Change in fair value of derivative instruments, net of taxes +(8,452 +) +— +— +— +(8,452 +) +Reclassification of settled contracts, net of taxes +1,005 +— +— +— +1,005 +Other comprehensive income (loss) +(6,092 +) +— +1,355 +(1,355 +) +(6,092 +) +Comprehensive income +$ +62,279 +$ +(3,066 +) +$ +(231 +) +$ +3,297 +$ +62,279 +Year Ended December 31, 2011 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Net income (loss) +$ +108,422 +$ +166 +$ +(1,470 +) +$ +1,304 +$ +108,422 +Foreign currency translation adjustment +(1,865 +) +— +(1,865 +) +1,865 +(1,865 +) +Change in fair value of derivative instruments, net of taxes +1,576 +— +— +— +1,576 +Reclassification of settled contracts, net of taxes +4,720 +— +— +— +4,720 +Other comprehensive income (loss) +4,431 +— +(1,865 +) +1,865 +4,431 +Comprehensive income +$ +112,853 +$ +166 +$ +(3,335 +) +$ +3,169 +$ +112,853 +F-41 +Table of Contents +Index to Financial Statements +CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS +(Amounts in thousands) +Year Ended December 31, 2013 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Net cash provided by operating activities +$ +182,961 +$ +8,104 +$ +— +$ +— +$ +191,065 +Net cash provided by (used in) investing activities +(661,886 +) +(2,374 +) +(33,929 +) +33,929 +(664,260 +) +Net cash provided by (used in) financing activities +765,063 +— +33,929 +(33,929 +) +765,063 +Net increase in cash and cash equivalents +286,138 +5,730 +— +— +291,868 +Cash and cash equivalents at beginning of period +165,293 +1,795 +— +— +167,088 +Cash and cash equivalents at end of period +$ +451,431 +$ +7,525 +$ +— +$ +— +$ +458,956 +Year Ended December 31, 2012 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Net cash provided by (used in) operating activities +$ +195,734 +$ +3,425 +$ +(1 +) +$ +— +$ +199,158 +Net cash provided by (used in) investing activities +(838,177 +) +(2,402 +) +(103,915 +) +103,915 +(840,579 +) +Net cash provided by (used in) financing activities +714,612 +— +103,915 +(103,915 +) +714,612 +Net increase (decrease) in cash and cash equivalents +72,169 +1,023 +(1 +) +— +73,191 +Cash and cash equivalents at beginning of period +93,124 +772 +1 +— +93,897 +Cash and cash equivalents at end of period +$ +165,293 +$ +1,795 +$ +— +$ +— +$ +167,088 +Year Ended December 31, 2011 +Parent +Guarantors +Non-Guarantor +Eliminations +Consolidated +Net cash provided by operating activities +$ +154,329 +$ +3,808 +$ +1 +$ +— +$ +158,138 +Net cash provided by (used in) investing activities +(320,203 +) +(3,045 +) +(25,858 +) +25,858 +(323,248 +) +Net cash provided by (used in) financing activities +256,539 +— +25,858 +(25,858 +) +256,539 +Net increase in cash and cash equivalents +90,665 +763 +1 +— +91,429 +Cash and cash equivalents at beginning of period +2,459 +9 +— +— +2,468 +Cash and cash equivalents at end of period +$ +93,124 +$ +772 +$ +1 +$ +— +$ +93,897 +F-42 +Table of Contents +Index to Financial Statements +19. +SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) +As discussed above in Notes 4 and 5, the Company owned a 7.2% equity interest in Diamondback at December 31, 2013 which interest is shown below. At December 31, 2012 , the Company owned a 21.4% equity interest in Diamondback. The Company did not own an equity interest in Diamondback at December 31, 2011 . +The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States: +Capitalized Costs Related to Oil and Gas Producing Activities +2013 +2012 +(In thousands) +Proven properties +$ +1,526,588 +$ +984,795 +Unproven properties +950,590 +626,295 +2,477,178 +1,611,090 +Accumulated depreciation, depletion, amortization and impairment reserve +(779,561 +) +(661,442 +) +Net capitalized costs +$ +1,697,617 +$ +949,648 +Equity investment in Diamondback Energy, Inc. +Proven properties +$ +92,074 +$ +123,370 +Unproven properties +26,608 +25,947 +118,682 +149,317 +Accumulated depreciation, depletion, amortization and impairment reserve +$ +(15,180 +) +$ +(31,052 +) +Net capitalized costs +$ +103,502 +$ +118,265 +Costs Incurred in Oil and Gas Property Acquisition and Development Activities +2013 +2012 +2011 +(In thousands) +Acquisition +$ +338,153 +$ +513,904 +$ +119,522 +Development of proved undeveloped properties +408,121 +121,787 +123,489 +Exploratory +26,174 +93,397 +3,994 +Recompletions +44,633 +24,643 +17,259 +Capitalized asset retirement obligation +3,556 +2,195 +1,390 +Total +$ +820,637 +$ +755,926 +$ +265,654 +Equity investment in Diamondback Energy, Inc. +Acquisition +$ +44,534 +$ +49,895 +$ +— +Development of proved undeveloped properties +6,369 +22,740 +— +Exploratory +17,491 +3,755 +— +Capitalized asset retirement obligation +50 +203 +— +Total +$ +68,444 +$ +76,593 +$ +— +Results of Operations for Producing Activities +The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include +F-43 +Table of Contents +Index to Financial Statements +depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production. +2013 +2012 +2011 +(In thousands) +Revenues +$ +262,225 +$ +248,601 +$ +228,953 +Production costs +(64,666 +) +(53,708 +) +(47,230 +) +Depletion +(118,118 +) +(90,230 +) +(61,965 +) +79,441 +104,663 +119,758 +Income tax expense (benefit) +Current +— +730 +282 +Deferred +49,447 +25,633 +(372 +) +49,447 +26,363 +(90 +) +Results of operations from producing activities +$ +29,994 +$ +78,300 +$ +119,848 +Depletion per barrel of oil equivalent (BOE) +$ +28.68 +$ +35.07 +$ +26.56 +Results of Operations from equity method investment in Diamondback Energy, Inc. +Revenues +$ +14,976 +$ +16,042 +$ +— +Production costs +(2,518 +) +(4,474 +) +— +Depletion +(4,754 +) +(5,515 +) +— +7,704 +6,053 +— +Income tax expense (benefit) +2,286 +2,158 +— +Results of operations from producing activities +$ +5,418 +$ +3,895 +$ +— +Oil and Gas Reserves +The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2013 , 2012 and 2011 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2013 , 2012 and 2011 , in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The prices used for the 2013 reserve report are $96.78 per barrel of oil, $3.67 per MMbtu and $41.23 per barrel for NGLs, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2012 and 2011 for reserve report purposes are $91.32 per barrel and $2.76 per MMbtu and $96.19 per barrel and $4.12 per MMbtu, respectively. +Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. +F-44 +Table of Contents +Index to Financial Statements +2013 +2012 +2011 +Oil +Gas +NGL +Oil +Gas +NGL +Oil +Gas +NGL +(MBbls) +(MMcf) +(MBbls) +(MBbls) +(MMcf) +(MBbls) +(MBbls) +(MMcf) +(MBbls) +Proved Reserves +Beginning of the period +8,106 +33,771 +145 +13,954 +15,728 +2,791 +16,597 +16,158 +3,107 +Purchases in oil and gas reserves in place +— +— +— +— +— +— +2 +19 +— +Extensions and discoveries +2,765 +123,597 +5,850 +4,732 +31,265 +148 +3,723 +2,091 +217 +Sales of oil and gas reserves in place +— +— +— +(7,875 +) +(11,757 +) +(2,729 +) +— +— +— +Revisions of prior reserve estimates +(208 +) +(2,031 +) +— +(382 +) +(357 +) +— +(4,240 +) +(1,662 +) +(474 +) +Current production +(2,317 +) +(8,891 +) +(320 +) +(2,323 +) +(1,108 +) +(65 +) +(2,128 +) +(878 +) +(59 +) +End of period +8,346 +146,446 +5,675 +8,106 +33,771 +145 +13,954 +15,728 +2,791 +Proved developed reserves +5,609 +94,552 +3,527 +5,175 +18,482 +44 +6,780 +6,152 +705 +Proved undeveloped reserves +2,737 +51,894 +2,148 +2,931 +15,289 +101 +7,174 +9,576 +2,086 +Equity investment in Diamondback Energy, Inc. +Proved Reserves +Beginning of the period +5,606 +7,398 +1,766 +3,874 +4,398 +1,080 +— +— +— +Change in ownership interest in Diamondback +(3,720 +) +(4,909 +) +(1,171 +) +— +— +— +— +— +— +Purchases in oil and gas reserves in place +528 +752 +120 +1,543 +2,292 +540 +— +— +— +Extensions and discoveries +1,227 +1,741 +331 +665 +804 +186 +— +— +— +Revisions of prior reserve estimates +(428 +) +(417 +) +(249 +) +(314 +) +82 +(1 +) +— +— +— +Current production +(146 +) +(124 +) +(26 +) +(162 +) +(178 +) +(39 +) +— +— +— +End of period +3,067 +4,441 +771 +5,606 +7,398 +1,766 +— +— +— +Proved developed reserves +1,425 +2,263 +358 +1,539 +2,753 +641 +— +— +— +Proved undeveloped reserves +1,642 +2,178 +413 +4,068 +4,645 +1,124 +— +— +— +In 2013, the Company experienced extensions and discoveries of 27,805 thousand barrels of oil equivalent (MBOE) of proved reserves attributable to the development of the Company's Utica Shale acreage. The Company contributed its Permian Basin assets to Diamondback in 2012, as discussed in Note 4, resulting in a decrease of 12,564 MBOE in estimated proved reserves in 2012. The Company experienced extensions and discoveries of proved reserves of 6,675 MBOE in 2012 attributable to the discovery and development of the Company's Utica Shale acreage. In addition, the Company experienced downward reserve revisions of 442 MBOE in estimated proved reserves in 2012 primarily due to a change in the drilling schedule of its Niobrara acreage. The Company also experienced downward reserve revisions in 2011. These downward revisions were primarily the result of the drilling of PUDs during the Company’s 2011 drilling program and ethane takeaway issues in the Permian Basin. +Discounted Future Net Cash Flows +The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2013 , 2012 and 2011 using an unweighted average first-of-the-month price for the period January through December 31, 2013 , 2012 and 2011 . +F-45 +Table of Contents +Index to Financial Statements +Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves +Year ended December 31, +2013 +2012 +2011 +(In thousands) +Future cash flows +$ +1,657,708 +$ +954,833 +$ +1,594,050 +Future development and abandonment costs +(272,500 +) +(159,113 +) +(306,810 +) +Future production costs +(274,428 +) +(147,024 +) +(295,383 +) +Future production taxes +(78,647 +) +(89,175 +) +(124,739 +) +Future income taxes +(172,691 +) +(114,867 +) +(229,649 +) +Future net cash flows +859,442 +444,654 +637,469 +10% discount to reflect timing of cash flows +(280,976 +) +(96,013 +) +(260,788 +) +Standardized measure of discounted future net cash flows +$ +578,466 +$ +348,641 +$ +376,681 +Equity investment in Diamondback Energy, Inc. Standardized measure of discounted cash flows +Future cash flows +$ +331,505 +$ +592,669 +$ +— +Future development and abandonment costs +(37,229 +) +(115,869 +) +— +Future production costs +(58,096 +) +(165,553 +) +— +Future production taxes +(22,925 +) +(30,122 +) +— +Future income taxes +(48,547 +) +(71,669 +) +— +Future net cash flows +164,708 +209,456 +— +10% discount to reflect timing of cash flows +(94,462 +) +(130,871 +) +— +Standardized measure of discounted future net cash flows +$ +70,246 +$ +78,585 +$ +— +In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers in Gulfport’s reserve report, the Company will need to spend $135.4 million , $68.7 million and $8.5 million during years 2014 , 2015 and 2016 , respectively. +Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves +F-46 +Table of Contents +Index to Financial Statements +Year ended December 31, +2013 +2012 +2011 +(In thousands) +Sales and transfers of oil and gas produced, net of production costs +$ +(197,559 +) +$ +(194,893 +) +$ +(181,723 +) +Net changes in prices, production costs, and development costs +65,573 +108,941 +136,071 +Acquisition of oil and gas reserves in place +— +— +72 +Extensions and discoveries +130,826 +151,654 +107,110 +Previously estimated development costs incurred during the period +43,478 +10,211 +41,193 +Revisions of previous quantity estimates, less related production costs +(3,591 +) +(10,504 +) +(112,553 +) +Sales of reserves in place +— +(214,867 +) +— +Accretion of discount +34,864 +37,668 +31,549 +Net changes in income taxes +(30,239 +) +25,585 +(36,674 +) +Change in production rates and other +186,473 +58,165 +76,149 +Total change in standardized measure of discounted future net cash flows +$ +229,825 +$ +(28,040 +) +$ +61,194 +Equity investment in Diamondback Energy, Inc. Changes in standardized measure of discounted cash flows +Change in ownership interest in Diamondback +$ +(52,145 +) +$ +— +$ +— +Sales and transfers of oil and gas produced, net of production costs +(12,524 +) +(11,601 +) +— +Net changes in prices, production costs, and development costs +3,312 +(14,596 +) +— +Acquisition of oil and gas reserves in place +21,968 +23,090 +— +Extensions and discoveries +39,776 +16,969 +— +Previously estimated development costs incurred during the period +5,517 +19,014 +— +Revisions of previous quantity estimates, less related production costs +(9,143 +) +(4,897 +) +— +Accretion of discount +4,175 +7,803 +— +Net changes in income taxes +(12,137 +) +(26,866 +) +— +Change in production rates and other +2,862 +(8,358 +) +— +Total change in standardized measure of discounted future net cash flows +$ +(8,339 +) +$ +558 +$ +— +20. +SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) +The following table summarizes quarterly financial data for the years ended December 31, 2013 and 2012 : +F-47 +Table of Contents +Index to Financial Statements +2013 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(In thousands) +Revenues +$ +55,000 +$ +70,434 +$ +69,252 +$ +68,067 +Income from operations +14,944 +22,456 +15,137 +2,926 +Income tax expense +28,195 +25,514 +23,400 +21,027 +Net income +44,559 +43,828 +40,527 +24,278 +Income per share: +Basic +$ +0.61 +$ +0.57 +$ +0.52 +$ +0.30 +Diluted +$ +0.61 +$ +0.56 +$ +0.52 +$ +0.30 +2012 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(In thousands) +Revenues +$ +65,461 +$ +66,325 +$ +60,537 +$ +56,603 +Income from operations +27,263 +25,947 +18,178 +25,875 +Income tax expense (benefit) +— +— +15,514 +10,849 +Net income +26,869 +25,117 +502 +15,883 +Income per share: +Basic +$ +0.48 +$ +0.45 +$ +0.01 +$ +0.28 +Diluted +$ +0.48 +$ +0.45 +$ +0.01 +$ +0.28 +21. SUBSEQUENT EVENTS +In January 2014, the Company entered into fixed price swaps for 25,000 MMBtu of natural gas per day at a weighted average price of $4.20 per MMBtu for the period from May 2014 through December 2015. For the period from June 2014 through December 2015, the Company entered into fixed price swaps for 25,000 MMBtu of natural gas per day at a weighted average price of $4.21 per MMBtu. The Company's fixed price swap contracts are tied to the commodity prices on NYMEX. The Company will receive the fixed price amount stated in the contract and pay to its counterparty the current market price as listed on NYMEX for natural gas. +On February 26, 2014, the Company entered into a binding letter of intent with Rhino Resources Partners LP ("Rhino") to acquire approximately 8,200 additional net acres in the Utica Shale of Eastern Ohio and approximately 1,000 BOEPD of production during January 2014 for a total purchase price of $185.0 million , subject to closing adjustments. These assets constitute all the rights, title and interest in leasehold and mineral interests covered by all oil and gas leases owned by Rhino in the Utica Shale in Eastern Ohio, together with all wells, production, data, equipment, contracts permits and privileges relating to the ownership of such properties. Gulfport is the operator of substantially all of this acreage. The Company plans to fund this acreage acquisition from existing cash on hand. The acquisition is expected to close by the end of March 2014, however the transaction remains subject to completion of due diligence and other closing conditions, and there can be no assurance that the transaction will be completed. +F-48 +Table of Contents +Index to Financial Statements +ITEM 6. +EXHIBITS +Exhibit +Number +Description +2.1 +Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012). +2.2 +Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 18, 2012). +2.3 +Amendment, dated December 19, 2012, to the Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 20, 2012). +2.4 +Purchase and Sale Agreement, dated February 11, 2013, by and between Windsor Ohio, LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 15, 2013). +3.1 +Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +3.2 +Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 6, 2009). +3.3 +Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013). +3.4 +Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 12, 2006). +3.5 +First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013). +4.1 +Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). +4.2 +Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005). +4.3 +Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on November 11, 2005). +4.4 +Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2006). +4.5 +Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.6 +Registration Rights Agreement, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). +4.7 +First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +E-1 +Table of Contents +Index to Financial Statements +4.8 +Registration Rights Agreement, dated as of December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). +10.1+ +2013 Restated Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form S-4, File No. 333-189992, filed by the Company with the SEC on July 17, 2013). +10.2+ +Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006). +10.3+* +Form of Restricted Stock Award Agreement. +10.4+ +Consulting Agreement, effective as of June 14, 2013, by and between the Company and Mike Liddell (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on June 19, 2013). +10.5+ +Separation and Release Agreement, dated as of January 31, 2014, by and between the Company and James D. Palm (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 4, 2014). +10.6+ +Employment Agreement, dated November 7, 2012, between the Company and Michael G. Moore (incorporated by reference to Exhibit 10.6 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). +10.7 +Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National Association, as documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 3, 2014). +10.8 +Investor Rights Agreement, dated as of October 11, 2012, between Gulfport Energy Corporation and Diamondback Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 17, 2012). +14 +Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 14, 2006). +21* +Subsidiaries of the Registrant. +23.1* +Consent of Grant Thornton LLP. +23.2* +Consent of Netherland, Sewell & Associates, Inc. +23.3* +Consent of Ryder Scott Company. +23.4* +Consent of Grant Thornton LLP with respect to financial statements of Diamondback Energy, Inc. +31.1* +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +31.2* +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. +32.1** +Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +32.2** +Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. +99.1* +Report of Netherland, Sewell & Associates, Inc. +99.2* +Report of Ryder Scott Company. +101.INS* +XBRL Instance Document. +101.SCH* +XBRL Taxonomy Extension Schema Document. +E-2 +Table of Contents +Index to Financial Statements +101.CAL* +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF* +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB* +XBRL Taxonomy Extension Labels Linkbase Document. +101.PRE* +XBRL Taxonomy Extension Presentation Linkbase Document. +* +Filed herewith. +** +Furnished herewith, not filed. ++ +Management contract, compensatory plan or arrangement. +E-3 \ No newline at end of file diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/filing_metadata.csv b/raw/filings/0000874499/2013/0001445305-14-000751/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..2c819ebcb3430ce83d5c3089708f7fde39106da3 --- /dev/null +++ b/raw/filings/0000874499/2013/0001445305-14-000751/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2014-02-28,2013-12-31,2014-02-28T21:19:04.000Z,0001445305-14-000751,gpor-12312013x10k.htm,10-K,26206817,1,0,https://www.sec.gov/Archives/edgar/data/874499/000144530514000751/gpor-12312013x10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000144530514000751/,2013,2013,1 diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/item1.txt b/raw/filings/0000874499/2013/0001445305-14-000751/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..2af38ab02cacd02c852c5361d595f9eb220da8e8 --- /dev/null +++ b/raw/filings/0000874499/2013/0001445305-14-000751/item1.txt @@ -0,0 +1,456 @@ +ITEM 1. +BUSINESS +General +We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of crude oil, natural gas liquids and natural gas in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal properties are located in the Utica Shale in Eastern Ohio and along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. In addition, we have producing properties in the Niobrara Formation of Northwestern Colorado and the Bakken Formation. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, an equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and natural gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO, and interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. +On February 26, 2014, we entered into an agreement to acquire approximately 8,200 additional net acres in the Utica Shale. See "- Recent Developments" below. As of February 27, 2014, after giving pro forma effect to the acquisition, we would have owned leasehold interests in approximately 167,700 gross (165,400 net) acres in the Utica Shale in Eastern Ohio. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2013, had spud 66 wells, 38 of which were completed and are producing. In 2013, we spud 52 gross (39 net) wells, of which 24 were completed as producing wells, 11 were waiting on completion, one was non-productive, nine were waiting on horizontal rigs and seven were still being drilled as of December 31, 2013. As of February 14, 2014, we had spud six gross (five net) wells all of which were still drilling. In addition, 61 gross (3.5 net) wells were drilled by other operators on our Utica Shale acreage during 2012 and 2013. +We have seven rigs under contract on our Utica Shale acreage. We currently intend to drill 85 to 95 gross (64 to 71 net) wells on our Utica Shale acreage in 2014 for an estimated aggregate cost of $594.0 million to $634.0 million. +Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2013 was approximately 984,528 net barrels of oil equivalent, or BOE, or 10,701 BOE per day, 68% of which was from natural gas and 32% of which was from oil and natural gas liquids, or NGLs. During January 2014, our average daily net production from the Utica Shale was approximately 15,897 BOE, 27% of which was from oil and NGLs and 73% of which was from natural gas. +In 2013, at our WCBB field, we recompleted 87 wells and drilled 22 wells. Of the 22 new wells drilled at WCBB in 2013, 21 were completed as producing wells and one was being drilled at year end. In the fourth quarter of 2013, production at WCBB was approximately 346,736 BOE, or an average of 3,769 BOE per day, 97% of which was from oil and 3% of which was from natural gas. During January 2014, our average net daily production at WCBB was approximately 3,158 BOE, 100% of which was from oil. During 2014, we currently anticipate drilling 22 to 24 wells at our WCBB field for an estimated aggregate cost of $42.0 million to $45.0 million. +In 2013, at our East Hackberry field, we recompleted 61 wells and drilled 16 wells. Of the 16 new wells drilled at East Hackberry during 2013, 13 were completed as producing wells, one was non-productive, one was waiting on completion and one was being drilled at year end. In the fourth quarter of 2013, net production at East Hackberry was approximately 188,536 BOE, or an average of 2,049 BOE per day, 90% of which was from oil and 10% of which was from natural gas. During January 2014, our average net daily production at East Hackberry was approximately 2,431 BOE, 93% of which was from oil and 7% of which was from natural gas. During 2014, we currently anticipate drilling ten to twelve wells for an estimated aggregate cost of $24.0 million to $26.0 million. +In 2013, at our West Hackberry field, we recompleted two wells and drilled two wells as of December 31, 2013. Of the two new wells drilled at West Hackberry during 2013, both were productive. In the fourth quarter of 2013, net production at West Hackberry was approximately 6,466 BOE, or an average of 70 BOE per day, 100% of which was from oil. During January 2014, our average net daily production at West Hackberry was approximately 110 BOE, 100% of which was from oil. +2 +Table of Contents +Index to Financial Statements +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2013, we held leases for approximately 7,481 net acres. During the year ended December 31, 2013, there were no wells spud on our Niobrara Formation acreage. In the fourth quarter of 2013, net production from our Niobrara Formation acreage was approximately 4,552 BOE, or an average of 49 BOE per day, 100% of which was from oil. During January 2014, our average net daily production from our Niobrara Formation acreage was approximately 55 BOE, 100% of which was from oil. During 2014, we currently do not anticipate drilling any wells in the Niobrara Formation. +As of December 31, 2013, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with interests in 13 wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2013, our net production from this acreage was approximately 2,412 BOE, or an average of 26 BOE per day, of which 90% was from oil and 10% was from NGLs. During January 2014, our average daily net production from our Bakken Formation acreage was approximately 93 BOE, of which 88% was from oil and 12% was from natural gas. +As of December 31, 2013, we owned approximately 7.2% of the outstanding common stock of Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to the Diamondback IPO. See Notes 4 and 5 to our consolidated financial statements included elsewhere in this report for additional information regarding our investment in Diamondback. +We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2013 , Grizzly had approximately 830,000 net acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada and had drilled an aggregate of 255 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. Grizzly has three oil sands projects in various stages of development. At Grizzly's 11,300 barrel per day steam-assisted gravity drainage, or SAGD, oil sand project at Algar Lake, steam generation commenced and was circulating through the plant and well pad facilities by year-end 2013 and reservoir steam injection commenced in January 2014, with first production expected by the end of the first quarter of 2014. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. At May River, an initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. A 29 well delineation drilling program was completed in the first quarter of 2013 over the development application area and a 2D seismic program covering approximately 80 kilometers is currently underway to more fully define the development area. At the Thickwood thermal project, activities have included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is developing a rail loadout facility in Conklin, Alberta, which we refer to as the Windell Terminal, and a rail to barge off-load facility on the lower Mississippi River, which we refer to as the Paulina Terminal. Construction of the 15,000 barrel per day truck to rail transloading Windell Terminal proximate to its May River lease, is expected to be completed and ready for operation by the end of the first quarter of 2014. In the U.S. Gulf Coast, Grizzly has begun engineering design work of the 40,000 barrel per day rail/barge Paulina terminal project located on the lower Mississippi River and has filed development permits. +We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. +We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. In March 2011, the second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. However, despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. In October 2013, Tatex III spud the TEW-K well, located to the south of the TEW-E well. The well tested gas at non-commercial rates. During drilling, the well flowed gas with rates as high as 20 MMcf per day of gas; however, no acceptable sustainable rate was established. +3 +Table of Contents +Index to Financial Statements +In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the first quarter of 2013, we participated in the formation of Stingray Energy Services LLC, or Stingray Energy, with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure Pumping LLC, or Stingray Pressure, Stingray Cementing LLC, or Stingray Cementing, and Stingray Logistics LLC, or Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk Midstream LLC, or Blackhawk, and Timber Wolf Terminals, LLC, or Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie (formerly known as Muskie Holdings LLC), which is engaged in the processing and sale of hydraulic fracturing grade sand. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. +As of December 31, 2013, we had 38.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $696.9 million and associated standardized measure of discounted future net cash flows of approximately $578.5 million , excluding reserves attributable to our interests in Diamondback, Grizzly, Tatex II and Tatex III. See "Item 2. Properties-Proved Oil and Natural Gas Reserves ” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. +Recent Developments +On February 26, 2014, we entered into a binding letter of intent with Rhino Resources Partners LP, or Rhino, to acquire approximately 8,200 net acres in the Utica Shale of Eastern Ohio and approximately 1,000 BOEPD of production during January 2014 for a total purchase price of $185.0 million, subject to closing adjustments. These assets constitute all the rights, title and interest in leasehold and mineral interests covered by all oil and gas leases owned by Rhino in the Utica Shale in Eastern Ohio, together with all wells, production, data, equipment, contracts permits and privileges relating to the ownership of such properties. We are the operator of substantially all of this acreage. We plan to fund this acquisition from existing cash on hand. The acquisition is expected to close by the end of March 2014, however the transaction remains subject to completion of due diligence and other closing conditions, and there can be no assurance that the transaction will be completed. +Principal Oil and Natural Gas Properties +The following table presents certain information as of December 31, 2013 reflecting our net interest in our principal producing oil and natural gas properties in the Utica Shale in Eastern Ohio, along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana. +Proved Reserves +Field +NRI/WI (1) +Productive +Wells (2) +Non-Productive +Wells +Developed +Acreage (3) +Gas +Oil +NGLs +Total +Percentages +Gross +Net +Gross +Net +Gross +Net +MBOE +MBOE +MBOE +MBOE +Utica Shale (4) +51.61/63.9 +38 +24 +1 +1 +10,627 +8,694 +23,983 +2,696 +5,674 +32,353 +West Cote Blanche Bay Field (5) +80.108/100 +110 +110 +201 +201 +5,668 +5,668 +241 +3,737 +— +3,978 +E. Hackberry Field (6) +80.309/100 +47 +47 +86 +86 +3,931 +3,931 +142 +1,170 +— +1,312 +W. Hackberry Field +83.333/100 +4 +4 +19 +19 +1,192 +1,192 +— +470 +— +470 +Niobrara Formation +36.77/47.85 +6 +3 +1 +1 +3,448 +1,724 +25 +186 +— +211 +Bakken Formation (4) +2.16/1.795 +13 +0.3 +— +— +1,862 +163 +13 +86 +— +99 +Overrides/Royalty Non-operated +Various +266 +0.45 +2 +0.06 +— +— +4 +1 +1 +6 +Total +484 +188.75 +310 +308.06 +26,728 +21,372 +24,408 +8,346 +5,675 +38,429 +(1) +Net Revenue Interest (NRI)/Working Interest (WI) for producing wells. +(2) +Includes three gross and net wells at WCBB that are producing intermittently. +4 +Table of Contents +Index to Financial Statements +(3) +Developed acres are acres spaced or assigned to productive wells. Approximately 13% of our acreage is developed acreage and has been held by production. +(4) Includes NRI/WI from wells that have been drilled or in which we have elected to participate. +(5) +We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). +(6) +NRI shown is for producing wells. +Utica Shale (Eastern Ohio) +Location and Land +As of December 31, 2013, we had acquired leasehold interests in approximately 152,000 gross (143,000 net) acres in the Utica Shale in Eastern Ohio, +Area History +Based on the estimates published by the Ohio Department of Natural Resources, or ODNR, which were last updated in 2012, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas in Ohio alone. During 2012 and 2013, a number of oil and gas companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio. As of February 9, 2013, the ODNR reported that in the Utica Shale in Ohio there were 65 producing horizontal wells, 236 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 15 horizontal wells that were being drilled and an additional 272 horizontal wells that had been permitted. +Geology +The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. +Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. +The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west. +The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. +The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale. +5 +Table of Contents +Index to Financial Statements +Facilities +There are standard land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well site pads inclusive of storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression and applicable metering. +Recent and Future Activities +We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2013, had spud 66 wells, 38 of which were completed and are producing. In 2013, we spud 52 gross (39 net) wells, of which 24 were completed and are productive, 11 were waiting on completion, one was non-productive, nine were waiting on horizontal rigs and seven were still being drilled as of December 31, 2013. As of February 14, 2014, we had spud six gross (five net) wells during 2014 all of which were still drilling. In addition, 49 gross (2.6 net) wells were drilled by other operators on our Utica Shale acreage during 2013. +We have seven rigs under contract on our Utica Shale acreage. We currently intend to drill 85 to 95 gross (64 to 71 net) wells on our Utica Shale acreage in 2014. +Production Status +Aggregate net production from the Utica Shale during the three months ended December 31, 2013 was approximately 984,528 BOE, or 10,701 BOE per day, 68% of which was from natural gas and 32% of which was from oil and NGLs. From January 1, 2014 through January 31, 2014, our average daily net production from the Utica Shale was approximately 15,897 BOE, 27% of which was from oil and NGLs and 73% of which was from natural gas. The increase in January 2014 production is a result of our 2013 drilling activities. +West Cote Blanche Bay Field +Location and Land +The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres. +Area History and Production +Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,047 wells drilled as of December 31, 2013, 949 were completed as producing wells. As a result, the field has a historic success rate of 91% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2013, we drilled 236 new wells, 215 of which were productive, for a 91% success rate. As of December 31, 2013, estimated field cumulative gross production was 195.3 MMBOE and 237.0 Bcf of gas. Of the 1,047 wells drilled in WCBB as of December 31, 2013, 107 were producing, 201 were shut-in, three were producing intermittently and five were being used as salt water disposal wells. The other 731 wells have been plugged and abandoned. +In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. +Geology +WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition +6 +Table of Contents +Index to Financial Statements +and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. +There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,047 wells that had been drilled in the field as of December 31, 2013, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. +WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. +Facilities +We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. +Recent and Future Activity +In 2013, we recompleted 87 gross and net wells and drilled 22 gross and net wells at WCBB. Of the 22 new wells drilled at WCBB in 2013, 21 were completed as producers and one was being drilled at year end. As of February 14, 2014, we had recompleted nine wells during 2014, drilled one well and were in the process of drilling one additional well in our WCBB field. Of the 22 wells drilled in 2013, 22 were considered deep wells. The 21 productive wells, with total depths ranging from 8,100 to 10,104 feet, have approximately 2,225 feet of aggregate apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells at WCBB during 2014. +Production Status +In the fourth quarter of 2013, our production at WCBB was approximately 346,736 net BOE, or an average of 3,769 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2014 through January 31, 2014, our average net daily production at WCBB was approximately 3,158 BOE, 100% of which was from oil. The decrease in average net daily production in January 2014 was due to normal production declines and the impact of extreme winter conditions. +East Hackberry Field +Location and Land +The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.309% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2013, we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic data. +Area History and Production +The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production +7 +Table of Contents +Index to Financial Statements +through 2013 was over 3,426 MBOE and 330.4 Bcf of casinghead gas production. A total of 254 wells have been drilled on our portion of the field. As of December 31, 2013, 47 wells had daily production, 86 were shut-in and three had been converted to salt water disposal wells. The remaining 118 wells had been plugged and abandoned. +Geology +The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. +Facilities +We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, five natural gas compressors, dehydration units and salt water disposal systems. +Recent and Future Activity +During 2013 at East Hackberry, we recompleted 61 gross and net wells and drilled 14 gross and net land wells and two gross and net wells on water. Of the 16 wells drilled during 2013, 13 were completed as producing wells, one was non-productive, one was waiting on completion and one was being drilled at year end. As of February14, 2014, we had recompleted seven wells during 2014, drilled one well and were in the process of drilling one additional well in our East Hackberry field. We currently intend to drill ten to twelve gross and net wells in our East Hackberry field during 2014. +Production Status +In the fourth quarter of 2013, our net production at East Hackberry was approximately 188,536 BOE, or an average of 2,049 BOE per day, 90% of which was from oil and 10% of which was from natural gas. From January 1, 2014 through January 31, 2014, our average net daily production at East Hackberry was approximately 2,431 BOE, 93% of which was from oil and 7% of which was from natural gas. The increase in production in 2014 is a result of our 2013 drilling and recompletion activities. +West Hackberry Field +Location and Land +The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 83.333% NRI) in 1,192 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum Reserves. +Area History +The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2013 was 344 MBOE and 140 Bcf of natural gas. There have been 40 wells drilled to date on our portion of West Hackberry. Currently, four of such wells are producing, 19 are shut-in and one has been converted to a saltwater disposal well. The remaining 16 wells have been plugged and abandoned. +Geology +Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. +8 +Table of Contents +Index to Financial Statements +Recent and Future Activity +During 2013 at West Hackberry, we recompleted two gross and net wells and drilled two gross and net wells both of which were productive as of year end. As of February14, 2014, no new wells had been drilled in our West Hackberry field. +Production Status +In the fourth quarter of 2013, our net production at West Hackberry was approximately 6,466 BOE, or an average of 70 BOE per day, 100% of which was from oil. From January 1, 2014 through January 31, 2014, our average net daily production at West Hackberry was approximately 110 BOE and was 100% from oil. +Facilities +We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. +Niobrara Formation (Northwestern Colorado) +Location and Land +Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and, as of December 31, 2013, we held leases for approximately 7,481 net acres. In 2013, no wells were spud on our Niobrara Formation acreage. +Area History +The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara Formation has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and limited in area extent. We believe the Niobrara Formation can be produced on a more widespread basis using today's horizontal multi-stage fracture stimulation technology where the Niobrara Formation is thermally mature. +Geology +The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect to oil generation. The producing intervals are geologically equivalent to the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major crude resource play. +Production Status +In the fourth quarter of 2013, our net production from our Niobrara Formation acreage was approximately 4,552 BOE, or an average of 49 BOE per day, 100% of which was from oil. From January 1, 2014 through January 31, 2014, our average daily net production from our Niobrara Formation acreage was approximately 55 BOE, 100% of which was from oil. +Facilities +There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +9 +Table of Contents +Index to Financial Statements +Recent and Future Activity +We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We do not anticipate drilling any wells in the Niobrara Formation during 2014. +Bakken Formation +Location and Land +The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern Montana. As of December 31, 2013, we held approximately 864 net acres, interests in 13 wells and an overriding royalty interests in certain existing and future wells. +Production Status +In the fourth quarter of 2013, our net production from our Bakken Formation acreage was approximately 2,412 BOE, or an average of 26 BOE per day, of which 90% was from oil and 10% was from NGLs. From January 1, 2014 through January 31, 2014, our average net daily production from this acreage was approximately 93 BOE, of which 88% was from oil and 12% was from natural gas. +Facilities +There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. +Recent and Future Activities +Six gross (1.3 net) wells were drilled on our Bakken Formation acreage in 2013. As of February 14, 2014, no new wells had been drilled on our Bakken Formation acreage in 2014. +Additional Properties +Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of December 31, 2013: +Field +State +Parish/County +Acreage Working +Interest +Overriding Royalty +Interests +Producing +Wells +Non-Producing +Wells +Deer Island +Louisiana +Terrebonne +3.125 +% +— +% +1 +— +Napoleonville +Louisiana +Assumption +— +% +2.5 +% +3 +— +Crest +Texas +Ochiltree +2 +% +— +% +1 +— +Eagle City South +Oklahoma +Dewey +1.04 +% +— +% +1 +— +Fay South +Oklahoma +Blaine +0.301 +% +— +% +1 +— +Squaw Cheek +Oklahoma +Blaine +0.694 +% +— +% +1 +— +Our Equity Investments +Permian Basin . On October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of December 31, 2013, we owned approximately 7.2% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. +10 +Table of Contents +Index to Financial Statements +Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by Grizzly Oil Sands Inc., an entity owned by certain investment funds managed by Wexford Capital LP, or Wexford. As of December 31, 2013 , Grizzly had approximately 830,000 net acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada and had three oil sands projects in various stages of development and had drilled an aggregate of 255 core holes and six water supply test wells on ten separate lease blocks and conducted a number of seismic programs. Regulatory approval of Grizzly's 11,300 barrel per day steam-assisted gravity drainage, or SAGD, oil sand project at Algar Lake was received in the fourth quarter of 2011. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were installed. Steam generation commenced and was circulating through the plant and well pad facilities by year-end 2013. Reservoir steam injection commenced in January 2014 with first production expected by the end of the first quarter of 2014. In the first quarter of 2012, Grizzly acquired the May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development application was filed with the regulatory authorities in the fourth quarter of 2013, covering the eastern portion of the May River lease. A 29 well delineation drilling program was completed in the first quarter of 2013 over the development application area and a 2D seismic program covering approximately 80 kilometers is currently underway to more fully define the development area. At the Thickwood thermal project, Grizzly's activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is developing the Windell Terminal, a rail loadout facility in Conklin, Alberta, and the Paulina Terminal, a rail to barge off-load facility on the lower Mississippi River. Construction of the 15,000 barrel per day Windell Terminal, proximate to its May River lease, is expected to be completed and ready for operation by the end of the first quarter of 2014. In the U.S. Gulf Coast, Grizzly has begun engineering design work of the 40,000 barrel per day Paulina Terminal project located on the lower Mississippi River and has filed development permits. +Thailand . We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes the Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm's initial gross production was approximately 60 million cubic feet per day. For 2013, net gas production was approximately 88 MMcf per day and condensate production was 382 barrels per day. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. +We own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Tatex III owns a concession covering approximately 245,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. In March 2011, the second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. However, despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. In October 2013, Tatex III spud the TEW-K well, located to the south of the TEW-E well. The well tested gas at non-commercial rates. During drilling, the well flowed gas with rates as high as 20 MMcf per day of gas; however, no acceptable sustainable rate was established. +Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the first quarter of 2013, we participated in the formation of Stingray Energy with an initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we participated in the formation of Stingray Pressure, Stingray Cementing and Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well completion and other well services. In 2012, we also participated in the formation of Blackhawk and Timber Wolf, with an initial ownership interest of 50% in each entity. Blackhawk coordinates gathering, compression, processing and marketing activities in connection with the development of our +11 +Table of Contents +Index to Financial Statements +Utica Shale acreage and Timber Wolf will operate a crude/condensate terminal and a sand transloading facility in Ohio. Also in 2012, we acquired a 22.5% equity interest in Midstream which owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison, which owns and operates drilling rigs and related equipment. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the processing and sale of hydraulic fracturing grade sand. See Note 5 to our consolidated financial statements included elsewhere in this report for additional information regarding these other investments. +Competition +The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. +Marketing and Customers +The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our Southern Louisiana oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI trade month average differential less $2.00 per barrel for transportation. Shell is the purchaser of our Utica Shale oil and pays us NYMEX less $10.00 per barrel. Markwest Utica purchases our Utica Shale NGLs. We have agreements in place with various purchasers for our Utica Shale natural gas production. In 2013, our Utica Shale natural gas was sold under monthly, seasonal and long term contracts and, as needed, through trades. Pricing was based on Dominion South Point (Dominion Eastern and Dominion Transmission) or Texas Eastern M2 Zone, plus or minus the market differential. As discussed below under "- Transportation and Takeaway Capacity," we have entered into agreements to transport our natural gas production out of the Utica Basin in 2014 and beyond. +During the year ended December 31, 2013, we sold approximately 99% of our oil production to Shell Trading Company, or Shell, 100% of our natural gas liquids production to Markwest Utica and 32%, 31% and 17% of our natural gas production to Sequent Energy Management, L.P., or Sequent, Hess and Interstate Gas Supply, Inc., or Interstate Gas, respectively. During the year ended December 31, 2012, we sold approximately 92% and 8% of our oil production to Shell and Diamondback O&G LLC (a wholly-owned subsidiary of Diamondback formerly known as Windsor Permian LLC), or Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G and 41%, 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G, and 50%, 27% and 22% of our natural gas production to Hilcorp Energy Company, Chevron and Diamondback O&G, respectively. +As of December 31, 2013, we had approximately 183,00 MMBtu per day of firm sales contracted with third parties. Of these sales, 33,000 MMBtu per day, 100,000 MMBtu per day and 50,000 MMBtu per day expire in 2015, 2016 and 2017, respectively. +Transportation and Takeaway Capacity +In Ohio, as of December 31, 2013, we had entered into firm transportation contracts for 2014, 2015 and 2016 for an aggregate of approximately 427,000 MMBtu per day, 677,000 MMBtu per day and 650,000 MMBtu per day, respectively. We are actively seeking to secure additional firm transportation contracts for incremental volumes from our Utica Shale acreage +12 +Table of Contents +Index to Financial Statements +and expect to finalize additional contracts in the first half of 2014. Our primary long-haul firm transportation commitments include the following: +• +194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities that will allow us to reach the Michigan, Chicago and Wisconsin natural gas markets in 2014. +• +200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities beginning in mid-2014 and, by the end of 2014, we expect to be able to reach Gulf Coast delivery points with the full contracted volumes; and +• +50,000 MMBtu per day of firm capacity to the Gulf Coast through Texas Gas Transmission facilities beginning in 2016. +Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Utica Basin position. +Regulation +Regulation of Gas and Oil Production +Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. +We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, and in the Utica Shale in Eastern Ohio, the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. +Environmental Regulation +Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. +Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in +13 +Table of Contents +Index to Financial Statements +conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. +Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. +Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. +Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. In November 2012, we and other entities involved in our WCBB field operations received a government subpoena, to which we have responded, for the production of documents and other information related primarily to a discharge of produced water that was allegedly identified by the U.S. Coast Guard in March 2012. We have had continuing communications with the government concerning these events and have been informed that the government may pursue claims against us and certain of our field personnel. We are continuing to cooperate with the investigation. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in April 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. +The Oil Pollution Act, or OPA, is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential +14 +Table of Contents +Index to Financial Statements +environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. +Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. +Air Emissions . The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail under the caption “ -Regulation of Hydraulic Fracturing .” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. +Climate Change . Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutants” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the “tailoring rule”) in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court granted review of certain issues related to EPA’s authority to regulate such emissions from stationary sources. Oral argument on the issues before the Supreme Court was heard on February 24, 2014, and a decision is expected by July 2014. +Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as a September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. +In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. +Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our +15 +Table of Contents +Index to Financial Statements +operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. +In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations. +Endangered Species Act +Environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities on federal lands may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. +Occupational Safety and Health Act +We are also subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements. +Regulation of Hydraulic Fracturing +Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. On February 12, 2014, the EPA published revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. The EPA is encouraging state programs to review and consider use of the draft guidance. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. +Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. +16 +Table of Contents +Index to Financial Statements +In August 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that may be responsive to some of these requests. +In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. +Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 16, 2013, the U.S. Department of Interior, or DOI, issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. DOI is expected to issue a final rule in 2014. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations. +There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any +17 +Table of Contents +Index to Financial Statements +failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. +Other Regulation of the Oil and Natural Gas Industry +The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. +The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. +Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices. +Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following: +• +the location of wells; +• +the method of drilling and casing wells; +• +the timing of construction or drilling activities, including seasonal wildlife closures; +• +the rates of production or “allowables”; +• +the surface use and restoration of properties upon which wells are drilled; +• +the plugging and abandoning of wells; and +• +notice to, and consultation with, surface owners and other third parties. +State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill. +Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements. +18 +Table of Contents +Index to Financial Statements +Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. +Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. +Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. +Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors. +Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. +State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. +The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. +19 +Table of Contents +Index to Financial Statements +Operational Hazards and Insurance +The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. +In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers' liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows. +Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million which includes sudden and accidental pollution for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore WCBB properties, we also have a $38.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $12.5 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $12.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $250,000 per occurrence ($1.25 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. +We carry control of well insurance for all of our Utica Shale wells and several Southern Louisiana wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. +We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean up services during 2013 and 2012 were approximately $0.7 million and $0.1 million, respectively. While these companies have been able to meet our service needs when required from time to time in the past, it is possible that the ability of one or more of them to provide services to us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and the nature of our production, we believe other companies would be available to us in the event our primary remediation companies are unable to perform. To supplement our planning and operation activities in Ohio, we also actively manage an incident response planning program and coordinate with applicable state agency personnel on spills and releases. We also participate in Ohio's Emergency Planning and Community Right to Know Act (EPCRA) program, which includes reporting of various materials used or stored on-site as well as notification to state and local emergency response centers, such as local fire departments, for emergency planning purposes. +20 +Table of Contents +Index to Financial Statements +Headquarters and Other Facilities +We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. Additionally, we lease approximately 20,800 square feet of office space in other buildings in Oklahoma City. We also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We recently completed construction of an approximately 5,700 square foot office building in St. Clairsville, Ohio that will serve as our Ohio headquarters. In addition, we lease 1,400 square feet of office space in St. Clairsville, Ohio. Each of these properties is suitable and adequate for its use. +Employees +At December 31, 2013 , we had 118 employees. An unrelated Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. During 2013, certain of our employees performed management and administrative services for affiliated companies for which we were reimbursed approximately $1.4 million. +Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. \ No newline at end of file diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/item13.txt b/raw/filings/0000874499/2013/0001445305-14-000751/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..4a2f04df11e3a34b80e43e7cb8a0c34418a99503 --- /dev/null +++ b/raw/filings/0000874499/2013/0001445305-14-000751/item13.txt @@ -0,0 +1,3 @@ +ITEM 13. +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference). \ No newline at end of file diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/item9a.txt b/raw/filings/0000874499/2013/0001445305-14-000751/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c99f0447269ff38657951102df22d2cab7a9b81e --- /dev/null +++ b/raw/filings/0000874499/2013/0001445305-14-000751/item9a.txt @@ -0,0 +1,32 @@ +ITEM 9A. +CONTROLS AND PROCEDURES +Evaluation of Disclosure Control and Procedures . Under the direction of our Interim Chief Executive Officer, President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Interim Chief Executive Officer, President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. +As of December 31, 2013 , an evaluation was performed under the supervision and with the participation of management, including our Interim Chief Executive Officer, President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Interim Chief Executive Officer, President and Chief Financial Officer has concluded that, as of December 31, 2013 , our disclosure controls and procedures are effective. +Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. +Management's Report on Internal Control Over Financial Reporting +Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. +Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 1992 Internal Control-Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2013 . +Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2013 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2013 , as stated in their accompanying report. +/s/ Michael G. Moore +Name: +Michael G. Moore +Title: +Interim Chief Executive Officer, President and Chief Financial Officer +68 +Table of Contents +Index to Financial Statements +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Gulfport Energy Corporation: +We have audited the internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2013 , based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013 , based on criteria established in the 1992 Internal Control-Integrated Framework issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2013 and our report dated February 28, 2014 expressed an unqualified opinion on those financial statements. +/s/ GRANT THORNTON LLP +Oklahoma City, Oklahoma +February 28, 2014 +69 +Table of Contents +Index to Financial Statements \ No newline at end of file diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/rp_note.txt b/raw/filings/0000874499/2013/0001445305-14-000751/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000874499/2013/0001445305-14-000751/rpt_disclosure.txt b/raw/filings/0000874499/2013/0001445305-14-000751/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..dfb5389ea775bbc89825c0647850bd6236b17c9d --- /dev/null +++ b/raw/filings/0000874499/2013/0001445305-14-000751/rpt_disclosure.txt @@ -0,0 +1,72 @@ +Certain Relationships and Related Transactions +Review and Approval of Related Party Transactions +The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be +substantively applied to each transaction reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the +Company. Further, the Company’s Code of Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party +transactions. +The Company’s policy is that all of its employees and directors, as well as their family members, must avoid any activity that is or +has the appearance of conflicting with the Company’s business interest. This policy is included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform +the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the +Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give +rise to a conflict of interest. +Further, under the Audit Committee Charter, the Audit Committee is responsible for reviewing and monitoring compliance +with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the Audit Committee, reviews and approves all relationships and +transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members, have a direct or +indirect material interest. The board of directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as they determine in +the good faith exercise of their discretion. +Related Party Transactions and Relationships +We contract with Athena Construction, L.L.C., or Athena, to provide barge services in our West Cote Blanche Bay and Hackberry fields located along the +Louisiana Gulf Coast. During 2013, we paid Athena $5.2 million and owed an additional $1.0 million for such services at December 31, 2013. +Caliber +Development Company, LLC, or Caliber, provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. We also lease office space from Caliber. During 2013, we paid Caliber $175,000 and owed $43,000 as of December 31, +2013. +We own a 24.9999% interest in Grizzly Oil Sands ULC, or Grizzly, a Canadian unlimited liability company, through our wholly owned subsidiary +Grizzly Holdings, Inc. The remaining interests in Grizzly are owned by Grizzly Oils Sands Inc. As of December 31, 2013, Grizzly had approximately 830,000 acres under lease in the Athabasca and Peace River oil sands regions located in the +Alberta Province near Fort McMurray. On October 5, 2012, we entered into an agreement with Grizzly in which we committed to make monthly payments from October 2012 to May 2013 in the aggregate amount of approximately $8.5 million to fund our +proportionate share of the construction and development costs of the Algar Lake facility. We also agreed to fund our proportionate share of any unfunded cost overruns in excess of $2.0 million. During 2013, we paid an aggregate of $33.9 million +under this agreement and in cash calls. +We have a 25% ownership interest in Muskie Proppant LLC, or Muskie (formerly known as Muskie Holdings LLC). +Muskie processes and sells sand for use in hydraulic fracturing by the oil and natural gas industry and holds certain assets, real estate and rights in a lease covering land in Wisconsin that is prospective for mining oil and natural gas fracture +grade sand. During the year ended December 31, 2013, we paid $2.2 million in cash calls, increasing our total net investment in Muskie to $7.5 million. We also entered into a loan agreement with Muskie effective July 1, 2013, under which +we have loaned Muskie $0.9 million. Interest accrues at the prime rate plus 2.5%. The loan has a maturity date of July 31, 2014. At December 31, 2013, the outstanding balance of the loan was $0.9 million. +During 2011, we invested in Bison Drilling and Field Services LLC, or Bison. Bison owns and operates drilling rigs. During the year ended December 31, +2013, we paid $2.3 million in cash calls. We entered into a loan agreement with Bison effective May 15, 2012, under which Bison may borrow funds from us. Interest accrues at LIBOR plus 0.28% or 8%, whichever is lower, and is to be paid on a +paid-in-kind basis by increasing the outstanding balance of the loan. The loan has a maturity date of January 31, 2015. We loaned Bison $1.6 million during the first nine months of 2012, all of which was repaid by Bison during the third quarter +of 2012. We have made no loans to Bison since that time. +37 +Table of Contents +During the first quarter of 2012, we, Windsor Ohio LLC, or Windsor Ohio, and Rhino Energy LLC formed Timber Wolf +Terminals LLC, or Timber Wolf. We currently have a 50% interest in Timber Wolf and paid $0.1 million in cash calls during 2013. Timber Wolf was formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. +During the first quarter of 2012, we purchased a 22.5% ownership interest in Windsor Midstream LLC, or Midstream, at a cost of $7.0 million. Midstream owns a +28.4% interest in Coronado Midstream LLC (formerly known as MidMar Gas LLC), a gas processing plant in West Texas. During the year ended December 31, 2013, we paid an immaterial amount in net cash calls. +During the second quarter of 2012, we and Windsor Ohio formed Blackhawk Midstream LLC, or Blackhawk. We are the manager of Blackhawk and have a 50% ownership +interest. Blackhawk coordinates gathering, compression, processing and marketing activities for us in connection with the development of our Utica Shale acreage. During the year ended December 31, 2013, we paid $0.7 million in cash calls to +Blackhawk. On January 28, 2014, Blackhawk closed on the sale of its equity interest in Ohio Gathering Company, LLC and Ohio Condensate Company, LLC for a purchase price of $190.0 million, of which $14.3 million was placed in escrow. We received +$84.8 million in net proceeds from this transaction. +Panther Drilling Systems, LLC, or Panther, performs directional drilling services for the Company. +During the year ended December 31, 2013, we were billed $12.6 million for these services and, at December 31, 2013, we owed Panther approximately $1.8 million. +Redback Directional Services, LLC, or Redback, provides coil tubing and flow back services for the Company. Redback billed us $0.1 million for these services +during the year ended December 31, 2013, and no amounts were owed to Redback at December 31, 2013. +Effective April 1, 2010, we entered +into an area of mutual interest agreement with Windsor Niobrara LLC, or Windsor Niobrara, to jointly acquire oil and gas leases in Northwest Colorado for the purpose of exploring, exploiting and producing oil and gas from the Niobrara Formation. The +agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50/50 basis. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their +respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we and Windsor Niobrara also entered into a development agreement, effective as of April 1, 2010, pursuant to which +we and Windsor Niobrara agreed to jointly develop the contract area, and we agreed to act as the operator under the terms of a joint operating agreement. As operator, we are responsible for daily operations, monthly operation billings and monthly +revenue disbursements for these properties. For the year ended December 31, 2013, we billed Windsor Niobrara $0.9 million and, at December 31, 2013, Windsor Niobrara owed us an immaterial amount for these services. +Windsor Ohio participated with us in the acquisition of certain leasehold interests in acreage located in the Utica Shale in Ohio. We are the operator of this +acreage in the Utica Shale. As operator, we are responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2013, we billed Windsor Ohio approximately +$73.4 million for these services. At December 31, 2013, Windsor Ohio owed us approximately $1.6 million for these services. +In February 2013, we +entered into a purchase and sale agreement with Windsor Ohio pursuant to which Windsor Ohio agreed to sell to us approximately 22,000 net acres representing 100% of its right, title and interest in and to certain leasehold interests in the Utica +Shale in Eastern Ohio for approximately $220.4 million, subject to certain adjustments. This transaction, which closed on February 15, 2013, excluded Windsor Ohio’s interest in 14 existing wells and 16 proposed future wells together with +certain acreage surrounding those wells. Through this transaction, we acquired an additional approximately 16.2% interest in our Utica Shale leases, increasing our working interest in the acreage to 93.8%. All of the acreage included in this +transaction was nonproducing at the time of the acquisition and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the completion of title review after the closing, +approximately $33.6 million of the purchase price was placed in an escrow account. In May 2013, the escrow accounts for both this acquisition and a prior acquisition with Windsor Ohio that was completed in December 2012 were terminated, and an +aggregate of $10.0 million was returned to us. The $77.5 million balance of the escrow accounts was disbursed to Windsor Ohio based on the results of title review. The transaction was approved by a special committee of our board of directors, which +engaged independent counsel and financial advisors to assist with its review. +Mr. Mike Liddell, our former Chairman of the Board and one of our +named executive officers during 2013, is the operating member and/or an officer of each of Windsor Niobrara, Windsor Ohio, Windsor Midstream, Athena, Panther, Redback, Timber Wolf, Bison and Caliber and holds a 10% participation interest in Windsor +Ohio and a direct or indirect contingent participation or profits interest ranging from 2.5% to 10.0% in Windsor Niobrara, Athena, Redback, Caliber, Windsor Midsteam, Muskie, Bison, Panther and Grizzly Oil Sands Inc., none of which interests are +dilutive to the interests, if any, that we hold in such entities. +38 +Table of Contents \ No newline at end of file