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+10-K
+1
+y46850e10-k.txt
+FORM 10-K
+1
+SECURITIES AND EXCHANGE COMMISSION
+Washington, DC. 20549
+FORM 10-K
+(Mark One)
+(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
+THE SECURITIES EXCHANGE ACT OF 1934
+For the fiscal year ended December 31, 2000
+-------------------------------------------------------
+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: 0-21121
+----------
+TRANSACT TECHNOLOGIES INCORPORATED
+--------------------------------------------------------------------------------
+(Exact name of registrant as specified in its charter)
+DELAWARE 06-1456680
+--------------------------------- -------------------------------------
+(State or other jurisdiction of (I.R.S. Employer Identification No.)
+incorporation or organization)
+7 LASER LANE, WALLINGFORD, CT 06492
+--------------------------------- -------------------------------------
+(Address of principal executive (Zip Code)
+offices)
+Registrant's telephone number, including area code 203-269-1198
+----------------------------
+Securities registered pursuant to Section 12 (b) of the Act:
+NONE
+--------------------------------------------------------------------------------
+Securities registered pursuant to Section 12 (g) of the Act:
+COMMON STOCK, $0.01 PAR VALUE
+--------------------------------------------------------------------------------
+(Title of class)
+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 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 other amendment
+to this Form 10-K. [ ]
+As of MARCH 16, 2001 the aggregate market value of the registrant's issued and
+outstanding voting stock held by non-affiliates of the registrant was
+$22,100,000.
+As of MARCH 16, 2001 the registrant had outstanding 5,620,327 shares of common
+stock, $0.01 par value.
+DOCUMENTS INCORPORATED BY REFERENCE
+Proxy Statement for the Annual Meeting of Shareholders to be held on May 23,
+2001 - Part III.
+2
+PART I
+GENERAL
+TransAct Technologies Incorporated ("TransAct" or the "Company")
+designs, develops, manufactures and markets transaction-based printers and
+related products under the Ithaca(R), Magnetec(R) and TransAct.com brand names.
+The Company's printers are used worldwide to provide transaction records such as
+receipts, tickets, coupons, register journals and other documents. The Company
+focuses on five vertical markets: point-of-sale ("POS"), gaming and lottery,
+kiosk, financial services and Internet. The Company sells its products directly
+to end users, original equipment manufacturers ("OEMs"), value-added resellers
+("VARs") and selected distributors, primarily in the United States, Canada,
+Europe and Latin America. TransAct has two operating facilities located in
+Wallingford, Connecticut and Ithaca, New York, five sales offices located in the
+United States, and one sales office and service depot in the United Kingdom.
+ITEM 1. BUSINESS.
+(A) GENERAL DEVELOPMENT OF BUSINESS
+TransAct began operating as a stand-alone business in August 1996 to
+operate the printer business that was formerly conducted by certain subsidiaries
+of Tridex Corporation. TransAct completed an initial public offering on August
+22, 1996. In April 1999, the Company formed and incorporated a new wholly-owned
+subsidiary, TransAct.Com. Through TransAct.com, the Company plans to explore
+leveraging its inkjet printing technology into the expanding online, e-commerce
+market.
+On February 15, 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company will consolidate all manufacturing and
+engineering into its existing Ithaca, NY facility and close its Wallingford, CT
+facility by the end of 2001. Production is planned to continue at the
+Wallingford facility until the end of 2001, with individual product lines
+scheduled to move over the course of 2001. The closing of the Wallingford
+facility is expected to result in the termination of employment of approximately
+70 employees.
+(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
+TransAct has assessed its operating and reportable segments and
+determined that it operates in one reportable segment, the design, development,
+manufacture and marketing of transaction-based printers and
+printer-related products.
+(C) NARRATIVE DESCRIPTION OF BUSINESS
+(i) PRINCIPAL PRODUCTS AND SERVICES
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing dot matrix, thermal and inkjet printing
+technology for applications requiring up to 60 character columns in each of its
+five vertical markets: POS, gaming and lottery, kiosk, financial services and
+Internet. The Company's printers are configurable, which offer customers the
+ability to choose from a variety of features and functions. Options typically
+include PC board configuration, paper cutting devices, paper handling capacities
+and number of print stations. In addition to its configurable printers, TransAct
+manufactures custom printers for certain OEM customers. In collaboration with
+these customers, the Company provides engineering and manufacturing expertise
+for the design and development of specialized printers.
+2
+3
+The Company also manufactures and sells document transport mechanisms
+which deliver the finished printed output to the consumer in unattended
+applications, such as ATMs and kiosks. In addition, the Company offers inkjet
+cartridges, printer ribbons, paper and replacement parts for all of its
+products.
+The Company provides customers with telephone sales and technical
+support, a personal account representative for orders, shipping and general
+information and expedited shipping for orders of its configurable and custom
+products. Technical and sales support personnel receive training in all of the
+Company's products and services manufactured at their facility. The Company's
+printers generally carry a one- or two-year limited warranty; extended
+warranties are available for purchase on selected printers to supplement the
+original warranty.
+(ii) STATUS OF PRODUCT REQUIRING MATERIAL INVESTMENT
+None.
+(iii) SOURCES AND AVAILABILITY OF RAW MATERIALS
+The principal materials used in manufacturing are copper wire, magnetic
+metals, injection molded plastic parts, formed metal parts and electronic
+components. Although the Company could experience temporary disruption if
+certain suppliers ceased doing business with the Company, the Company's
+requirements generally are available from a number of sources, except as
+described below.
+Okidata, Division of Oki America, Inc. ("Okidata") is the sole supplier
+for a printer component kit consisting of a printhead, control board and
+carriage (the "Oki Kit"), which is used in all of the Company's Ithaca(R) brand
+impact printers. The loss of the supply of Oki Kits would have a material
+adverse effect on the Company. TransAct has a supply agreement with Okidata to
+provide Oki Kits until May 2001 at a fixed price through May 2001. The Company
+and Okidata are currently negotiating for future supplies and pricing.
+Hewlett-Packard Company ("HP") is the sole supplier of inkjet cartridges which
+are used in all of the Company's inkjet printers. The loss of the supply of HP
+inkjet cartridges would have a material adverse effect on the sale of the
+Company's inkjet printers. TransAct has a supply agreement with HP to purchase
+inkjet cartridges until June 1, 2001 at a fixed price. The Company and HP are
+currently negotiating for future supplies and pricing. TransAct believes its
+relations with Okidata and HP are good and has received no indication that
+either of the supply agreements will not be renewed beyond the respective
+expiration dates of the current contracts. TransAct cannot be certain, however,
+that either of the supply agreements will be renewed, or if renewed, that the
+terms will be as favorable as those under the current contracts.
+(iv) PATENTS AND PROPRIETARY INFORMATION
+The Company owns several patents, one of which it considers material.
+That patent covers an automated paper cut-off device, which is a feature offered
+on certain of the Company's POS printers. The Company also has sought patent and
+other protection for certain design features of its new family of printers
+utilizing inkjet printing technology. The Company regards certain manufacturing
+processes and designs to be proprietary and attempts to protect them through
+employee and third-party nondisclosure agreements and similar means. It may be
+possible for unauthorized third parties to copy certain portions of the
+Company's products or to reverse engineer or otherwise obtain and use, to the
+Company's detriment, information that the Company regards as proprietary.
+Moreover, the laws of some foreign countries do not afford the same protection
+to the Company's proprietary rights as do United States laws. There can be no
+assurance that legal protections relied upon by the Company to protect its
+proprietary position will be adequate or that the Company's competitors will not
+independently develop technologies that are substantially equivalent or superior
+to the Company's technologies.
+3
+4
+(v), (vi) SEASONALITY AND PRACTICES RELATING TO WORKING CAPITAL ITEMS
+Retailers typically reduce purchases of new POS equipment in the fourth quarter,
+due to the increased volume of consumer transactions in that period, and the
+Company's sales of printers in the POS market historically have increased in the
+third quarter and decreased in the fourth quarter. However, the Company has not
+experienced material seasonality in its total net sales, due to offsetting sales
+in other markets.
+(vii) CERTAIN CUSTOMERS
+The Company has an OEM purchase agreement with GTECH Corporation
+("GTECH") to provide on-line lottery printers and spare parts, at prices to be
+negotiated, through July 2004. Firm purchase orders for printers may be placed
+annually by GTECH. For 2001, the Company has received an order for approximately
+$14,000,000 for delivery between May and December 2001. The Company also sells
+printers to GTECH for use in lottery terminals at grocery check-out lanes
+("in-lane lottery printers"). Sales to GTECH accounted for approximately 22.1%
+and 31.8% of net sales in 2000 and 1998, respectively. The Company made no
+on-line lottery printer shipments to GTECH during 1999. The Company also
+provides printers to ICL Pathway for use in the British Post Office. During
+2000, sales to ICL Pathway accounted for approximately 20.2% of net sales. The
+Company completed shipping printers to ICL Pathway for use in the British Post
+Office in February 2001 and no further shipments are expected. The Company had
+no sales to any one customer greater than 10% of net sales in 1999.
+(viii) BACKLOG
+The Company's backlog of firm orders was approximately $18,100,000 as
+of March 16, 2001 and $19,900,000 as of March 17, 2000. Based on customers'
+current delivery requirements, TransAct expects to fill its current backlog of
+approximately $18,100,000 during 2001.
+(ix) MATERIAL PORTION OF BUSINESS SUBJECT TO RENEGOTIATION OF PROFITS
+None.
+(x) COMPETITION
+The market for transaction-based printers is extremely competitive, and
+the Company expects such competition to intensify in the future. The Company
+competes with a number of companies, many of which have greater financial,
+technical and marketing resources than the Company. TransAct believes its
+ability to compete successfully depends on a number of factors both within and
+outside its control, including durability, reliability, quality, design
+capability, product customization, price, customer support, success in
+developing new products, manufacturing expertise and capacity, supply of
+component parts and materials, strategic relationships with suppliers, the
+timing of new product introductions by the Company and its competitors, general
+market and economic conditions and, in some cases, the uniqueness of its
+products.
+4
+5
+Three of the Company's competitors, Epson America, Inc., Axiohm
+Transaction Solutions and Star Micronics America, Inc. together control
+approximately 70% of the United States market for POS printers, a market in
+which the Company's strategy calls for increased market share. Another principal
+competitor in the POS market is Citizen -- CBM America Corporation. Certain
+competitors of the Company have greater financial resources, lower costs
+attributable to higher volume production and off-shore manufacturing locations,
+and offer lower prices than the Company from time to time.
+In the gaming and lottery, financial services and kiosk markets, no
+single supplier holds a dominant position. Certain of the Company's products
+sold for gaming and lottery, kiosk and financial service applications compete
+based upon the Company's ability to provide highly specialized products, custom
+engineering and ongoing technical support.
+The Company's strategy for competing in its markets is to continue to
+develop new products and product line extensions, to increase its geographic
+market penetration, and to take advantage of strategic relationships. The
+Company expects to particularly focus on gaining market acceptance for its new
+family of printers utilizing Hewlett Packard's inkjet printing technology.
+Although the Company believes that its products, operations and relationships
+provide a competitive foundation, there can be no assurance that the Company
+will compete successfully in the future.
+(xi) RESEARCH AND DEVELOPMENT ACTIVITIES
+The Company spent approximately $3,481,000, $3,235,000 and $3,642,000
+in 2000, 1999 and 1998, respectively, on engineering, design and product
+development efforts in connection with specialized engineering and design to
+introduce new products and to customize existing products. During 2001, the
+Company expects to focus the majority of its research and development activities
+on the development of (1) a family of printers for the POS market utilizing
+Hewlett Packard's inkjet printing technology and (2) new voucher-issuing
+printers for use in the casino market.
+(xii) ENVIRONMENT
+The Company is not aware of any material noncompliance with federal,
+state and local provisions which have been enacted or adopted regulating the
+discharge of materials into the environment, or otherwise relating to the
+protection of the environment.
+(xiii) EMPLOYEES
+As of March 16, 2001, TransAct Technologies and its subsidiaries
+employed 205 persons, of whom 190 were full-time and 15 were temporary
+employees. None of the Company's employees is unionized and the Company
+considers its relationships with its employees to be good.
+(D) FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS AND
+EXPORT SALES
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary located in the United Kingdom, which had sales
+to its customers of $11,164,000, $700,000 and $4,990,000 in 2000, 1999 and 1998,
+respectively. The Company had export sales to its customers from its domestic
+operations of approximately $5,156,000, $7,807,000, and $3,396,000 in 2000, 1999
+and 1998, respectively.
+5
+6
+(E) EXECUTIVE OFFICERS OF THE REGISTRANT AS OF DECEMBER 31, 2000
+Name Age Position
+---- --- --------
+Thomas R. Schwarz 64 Chairman of the Board
+Bart C. Shuldman 43 President, Chief Executive Officer and Director
+Richard L. Cote 59 Executive Vice President, Chief Financial Officer, Treasurer,
+Secretary and Director
+Mark B. Goebel 46 Senior Vice President - General Manger (Wallingford, CT facility)
+Michael S. Kumpf 51 Senior Vice President - Engineering
+Lucy H. Staley 50 Senior Vice President - General Manager (Ithaca, NY facility)
+James B. Stetson 43 Senior Vice President - Sales
+Catherine J. Dawson 33 Vice President - Marketing
+Steven A. DeMartino 31 Vice President and Corporate Controller
+THOMAS R. SCHWARZ, Chairman of the Board, has been a Director of the
+Company since its formation in June 1996. Mr. Schwarz was Chairman and Chief
+Executive Officer of Grossman's Inc., a retailer of building materials, from
+1990 until his retirement in 1994. Mr. Schwarz is a Director of Tridex,
+Foilmark, Inc., Tanaka Growth Fund, Lebhar-Friedman Publishing Company and
+Yorkshire Global Restaurants. In February 2001, Mr. Schwarz resigned from his
+position as Chairman of the Board, but remains a director of the Company.
+BART C. SHULDMAN has been Chief Executive Officer, President and a
+Director of the Company since its formation in June 1996. Previously, Mr.
+Shuldman served as President of Magnetec and later the combined operations of
+Magnetec and Ithaca from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+RICHARD L. COTE has been Executive Vice President, Chief Financial
+Officer, Treasurer, Secretary and a Director of the Company since its formation
+in June 1996. Prior thereto, he served as Senior Vice President and Chief
+Financial Officer of Tridex from September 1993 to June 1996.
+MARK B. GOEBEL, Senior Vice President - General Manager (Wallingford,
+CT facility), joined TransAct in November 1993 as Engineering Manager. From
+April 1994, Mr. Goebel served as Vice President-Engineering until he was
+appointed Senior Vice President of Engineering of Wallingford, and an officer of
+the Company, in January 2000. In November 2000, Mr. Goebel was named Senior Vice
+President - General Manager of the Wallingford, CT facility.
+MICHAEL S. KUMPF, Senior Vice President-Engineering since June 1996,
+served as Vice President of Engineering of Ithaca from 1991 until June 1996.
+LUCY H. STALEY, Senior Vice President-General Manager (Ithaca, NY
+facility) since June 1996, served as a Vice President of Ithaca from 1984 until
+June 1996.
+JAMES B. STETSON was appointed Senior Vice President of Worldwide Sales
+of the Company in February 2000, and served as Vice President of Sales, Latin
+America from October 1997 to February 2000. Prior to joining TransAct, Mr.
+Stetson served as Vice President and Sales Manager at Gekay Sales and Service
+Company from 1995 until October 1997.
+6
+7
+CATHERINE J. DAWSON joined TransAct in June 1998 as Vice President of
+Marketing, and was appointed an officer of the Company on January 1, 2000. Prior
+to joining TransAct, Ms. Dawson served as Product Marketing Manager for the
+visual systems division of 3M Corporation from March 1996 to March 1998, and as
+a Senior Marketing Analyst from June 1994 to March 1996.
+STEVEN A. DEMARTINO joined TransAct as Corporate Controller in August
+1996 and was appointed an officer of the Company in January 1998 and Vice
+President in December 1999. Prior to joining TransAct, Mr. DeMartino was a
+self-employed financial consultant from May 1996 to August 1996. Prior thereto,
+Mr. DeMartino, served as Controller of NER/Copart, Inc. from September 1994 to
+May 1996.
+ITEM 2. PROPERTIES.
+The Company's operations are currently conducted at the facilities
+described below. In February 2001, the Company announced plans to establish a
+global engineering and manufacturing center at its Ithaca, NY facility. As part
+of this strategic decision, the Company will consolidate all manufacturing and
+engineering into its existing Ithaca, NY facility and close its Wallingford, CT
+facility by the end of 2001. The Company expects to be able to sublease the
+Wallingford facility for the remaining term of the lease, however there can be
+no assurance that the Company will be successful in doing so.
+Size Owned or Lease Expiration
+Location Operations Conducted (Approx. Sq. Ft.) Leased Date
+-------- -------------------- ----------------- ------ ----
+Wallingford, Connecticut Manufacturing facility and 49,000 Leased March 31, 2008
+executive offices
+Ithaca, New York Manufacturing facility 59,000 Leased June 30, 2007
+Doncaster, United Kingdom Sales office and service 2,800 Leased August 1, 2009
+depot
+Georgia, Florida, Illinois, New York Five (5) regional sales 600 Leased Various
+and Texas offices
+The Company believes that its facilities generally are in good
+condition, adequately maintained and suitable for their present and currently
+contemplated uses.
+ITEM 3. LEGAL PROCEEDINGS.
+None.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
+No matters were submitted to a vote of security holders during the last
+quarter of the year covered by this report.
+7
+8
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
+The Company's common stock is traded on the Nasdaq National Market
+under the symbol TACT. As of March 16, 2001, there were 896 holders of record of
+the common stock. The high and low sales prices of the common stock reported
+during each quarter of the years ended December 31, 2000 and 1999 were as
+follows:
+Year Ended Year Ended
+December 31, 2000 December 31, 1999
+----------------- -----------------
+High Low High Low
+---- --- ---- ---
+First Quarter $10.25 $6.03 $3.63 $2.56
+Second Quarter 11.38 8.00 6.81 2.75
+Third Quarter 11.50 5.75 8.00 5.50
+Fourth Quarter 8.25 3.88 9.06 5.25
+No dividends on common stock have been declared and the Company does
+not anticipate declaring dividends in the foreseeable future. The Company's
+credit agreement with Webster Bank restricts the payment of cash dividends on
+its common stock for the term of the agreement.
+ITEM 6. SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+Because the Company was wholly-owned by Tridex until August 22, 1996,
+the Selected Financial Data which appear below with respect to the year ended
+December 31, 1996 may not necessarily reflect the results of operations or
+financial position of the Company or what the results of operations would have
+been if the Company had been a stand alone entity during 1996.
+Year Ended December 31,
+2000 1999 1998 1997 1996
+---- ---- ---- ---- ----
+Statement of Operations Data:
+Net sales $53,720 $44,889 $52,239 $58,400 $42,134
+Gross profit 14,142 11,754 13,826 18,173 13,933
+Operating income (loss) (154) 35 2,148 7,831 5,233
+Net income (loss) (344) 324 1,206 4,893 3,340
+Net income (loss) available
+to common shareholders (664) 324 1,206 4,893 3,340
+Net income (loss) per share
+(pro forma for 1996):
+Basic (0.12) 0.06 0.20 0.72 0.57
+Diluted (0.12) 0.06 0.20 0.71 0.57
+December 31,
+2000 1999 1998 1997 1996
+---- ---- ---- ---- ----
+Balance Sheet Data:
+Total assets $27,619 $25,684 $23,788 $24,699 $20,784
+Long-term debt 5,944 7,100 5,075 - -
+Shareholders' equity:
+Preferred 3,668 - - - -
+Common 12,191 12,207 12,177 17,903 14,407
+8
+9
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS.
+This discussion should be read in conjunction with the Consolidated
+Financial Statements and notes thereto.
+Certain statements included in this report, including without
+limitation statements in this Management's Discussion and Analysis of Financial
+Condition and Results of Operations, which are not historical facts are
+"forward-looking statements" within the meaning of Section 27A of the Securities
+Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
+as amended. All forward-looking statements involve risks and uncertainties,
+including, but not limited to, customer acceptance and market share gains, both
+domestically and internationally, in the face of substantial competition from
+competitors that have broader lines of products and greater financial resources;
+introduction of new products into the marketplace by competitors; successful
+product development; dependence on significant customers; dependence on third
+parties for sales in Europe and Latin America; economic conditions in the United
+States, Europe and Latin America; marketplace acceptance of new products; risks
+associated with foreign operations; the Company's ability to successfully
+consolidate its operations into its Ithaca, NY facility; availability of
+third-party components at reasonable prices; and the absence of price wars or
+other significant pricing pressures affecting the Company's products in the
+United States or abroad. Actual results may differ materially from those
+discussed in, or implied by, the forward-looking statements.
+PLANT CONSOLIDATION DURING 2001
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company will consolidate all manufacturing and
+engineering into its existing Ithaca, NY facility and close its Wallingford, CT
+facility by the end of 2001 (the "Consolidation"). The Company's technology
+shift to inkjet and thermal printing from dot matrix impact printing has
+dramatically reduced the labor content in printers, and therefore, lowers the
+required production capacity. Production is planned to continue at the
+Wallingford facility until the end of 2001, with individual product lines
+scheduled to move over the course of 2001. The Company estimates that the
+non-recurring costs associated with the Consolidation, including severance pay,
+employee benefits, moving expenses, non-cancelable lease payments and other
+costs, will be in the $3.0 to $3.5 million range and will be recognized during
+2001. The Company expects the Consolidation will provide approximately $4.0
+million in annual cost savings, compared to 2000, beginning in 2002. See the
+"Liquidity and Capital Resources" section for a discussion of the expected
+impact of the Consolidation on the Company's future cash flows.
+(A) RESULTS OF OPERATIONS
+(i) YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31,
+1999
+NET SALES. Net sales by market for the years ended December 31, 2000
+and 1999 were as follows:
+Year ended Year ended
+(In thousands) December 31, 2000 December 31, 1999
+----------------- -----------------
+Point of sale $29,396 54.7% $26,653 59.4%
+Gaming and lottery 19,298 35.9 8,782 19.5
+Other 5,026 9.4 9,454 21.1
+------- ----- ------- -----
+$53,720 100.0% $44,889 100.0%
+======= ===== ======= =====
+9
+10
+Net sales for the year ended December 31, 2000 increased $8,831,000, or
+20%, to $53,720,000 from $44,889,000 in 1999 due to increased shipments into the
+POS and gaming and lottery markets, partially offset by a decrease in sales in
+the Company's other markets. International sales increased to $16,320,000, or
+30.4% of net sales in 2000, from $8,507,000, or 19.0% of net sales in 1999.
+Point of sale: Sales of the Company's POS printers increased
+$2,743,000, or 10%. International POS printer shipments increased approximately
+$9,387,000 due to the resumption of printer shipments to ICL Pathway for the
+British Post Office project. Shipments of printers for this project totaled
+approximately $10,700,000 in 2000. The Company did not make any printer
+shipments related to this project in 1999. The Company completed shipping
+printers for the British Post Office project in February 2001 and no further
+shipments are expected. While the Company expects to replace sales for the
+British Post Office project with sales of other POS and gaming and lottery
+printers in 2001, if the Company is unable to do so, the absence of such sales
+would have a material adverse impact on the Company's operations and financial
+results during 2001. The increase in international shipments for the British
+Post Office project was offset by a net decrease of approximately $1,300,000 of
+printer shipments to other customers primarily in Europe and Latin America.
+Domestic POS printer shipments decreased by approximately $6,644,000,
+due primarily to continued softness in demand from the Company's domestic
+distributors.
+Gaming and lottery: Sales of the Company's gaming and lottery printers
+increased $10,516,000, or 120%, from 1999. This net increase resulted from a
+number of factors. The primary effect on the revenue in this market during 2000
+was the resumption of shipments to GTECH of the Company's on-line lottery
+printers, that totaled $11,400,000 compared to no on-line lottery printer
+shipments during 1999. In addition, the Company's new slot machine printer added
+approximately $2,800,000 to revenue in 2000. The new slot machine printer is
+primarily for use in Indian casinos in California and casinos in Nevada. The
+Company expects sales of its slot machine printers to grow significantly in
+2001.
+Offsetting the sales increases noted above was a decrease of
+approximately $2,400,000 in shipments of printers for use in video lottery
+terminals (VLTs), primarily due to the absence in 2000 of sales into the South
+Carolina market, which banned VLTs in October 1999. The absence of VLT printer
+sales for the South Carolina market was partially offset by increased sales of
+these printers into other jurisdictions. Also, sales of in-lane lottery printers
+to GTECH did not recur in 2000, resulting in a decrease in sales of $1,100,000.
+Sales of in-lane lottery printers are project-oriented and the Company cannot
+predict if and when future sales may occur.
+The Company received an order from GTECH in January 2001 approximating
+$14,000,000 for additional on-line lottery printers which will be delivered from
+May to December 2001.
+Other: Sales of the Company's printers into other markets decreased
+$4,428,000, or 47% from 1999 due to decreased shipments of printers used in
+automated teller machines, decreased shipments of printers for use in bank
+teller applications, and the absence of shipments of the Company's thermal kiosk
+printers for use in a Canadian government application.
+10
+11
+GROSS PROFIT. Gross profit increased $2,388,000, or 20%, to $14,142,000
+from $11,754,000 in 1999 due primarily to higher sales volume in 2000. The gross
+margin remained essentially the same at 26.3% in 2000 compared to 26.2% in 1999.
+The Company expects its gross margin in 2001, before the impact of the
+Consolidation, to remain relatively consistent with 2000.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses increased $246,000, or 8%, to $3,481,000 from $3,235,000 in
+1999. The increase in spending was primarily due to increased development and
+design expenses related to inkjet printers, including additional engineering
+staff. These expenses decreased as a percentage of net sales to 6.5% from 7.2%,
+due to higher sales in 2000 compared to 1999. The Company expects its
+engineering, design and product development expenses to decrease slightly during
+2001, as the Company reduces engineering activity at the Wallingford, CT
+facility in preparation for its closing on December 31, 2001.
+SELLING AND MARKETING. Selling and marketing expenses increased
+$1,199,000, or 31%, to $5,086,000 from $3,887,000 in 1999, and increased as a
+percentage of net sales to 9.5% from 8.7% in 1999. Such expenses increased by
+approximately $1,400,000 due primarily to marketing and promotional activities
+related to the launch of the Company's new family of printers utilizing inkjet
+printing technology in April 2000, including additional marketing staff. This
+increase was somewhat offset by lower sales commissions resulting from a
+decrease in sales eligible for commissions in 2000 compared to 1999. The Company
+expects that selling and marketing expenses for 2001 will be relatively
+consistent with those of 2000, as the Company plans to continue a similar level
+of marketing and promotional activities to support the existing inkjet product,
+as well as a new inkjet printer expected to be introduced during 2001.
+GENERAL AND ADMINISTRATIVE. General and administrative expenses
+increased by $943,000, or 21% to $5,540,000 in 2000 from $4,597,000 in 1999, and
+increased slightly as a percentage of net sales to 10.3% from 10.2%. The
+increase primarily resulted from (1) higher expenses resulting from the
+Company's upgrade of its telecommunications system, (2) an increase in
+administrative compensation-related expenses and (3) higher professional
+expenses.
+PROVISION FOR RESTRUCTURING. During the year ended December 31, 2000,
+the Company recorded a provision for restructuring of $189,000 to cover
+severance costs related to the downsizing at the Company's manufacturing
+facility in Wallingford, Connecticut. At December 31, 2000, approximately
+$105,000 of restructuring expenses remained accrued.
+OPERATING INCOME (LOSS). The Company incurred an operating loss of
+$154,000 in 2000 compared to operating income of $35,000 in 1999. The operating
+loss was primarily the result of higher operating expenses, including planned
+marketing and product development expenses related to the launch of the
+Company's new inkjet printer, higher general and administrative expenses, and
+the restructuring provision recorded in 2000.
+OTHER INCOME. In 1999, the Company recorded a one-time pre-tax gain of
+$770,000 related to the favorable settlement of a lawsuit with GTECH.
+11
+12
+INTEREST. Net interest expense increased to $649,000 from $399,000 in
+1999 due to increased average outstanding borrowings on the Company's line of
+credit and a higher average borrowing rate in 2000 compared to 1999. See
+"Liquidity and Capital Resources" below.
+INCOME TAXES. As a result of the Company's loss before income taxes in
+2000, the Company recorded an income tax benefit of $448,000, or an effective
+rate of 56.6%, compared to an income tax provision of $102,000 in 1999, or an
+effective rate of 24%. The abnormally high effective tax benefit rate in 2000
+and the low effective tax rate in 1999 are primarily due to the recognition of
+certain tax credits and the benefit from the Company's foreign sales corporation
+on relatively low pre-tax amounts.
+NET INCOME (LOSS). The Company incurred a net loss of $344,000 for
+2000, or $0.12 per share (basic and diluted), after giving effect to $264,000 of
+dividends and accretion charges and a one-time beneficial conversion charge of
+approximately $56,000 on preferred stock issued in April of 2000. This compares
+to net income of $324,000, or $0.06 per share (basic and diluted) in 1999. In
+2001, dividends and accretion charges on preferred stock will be $360,000,
+before the effect of any conversion or redemption of the preferred stock.
+(ii) YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31,
+1998
+NET SALES. Net sales by market for the years ended December 31, 1999
+and 1998 were as follows:
+Year ended Year ended
+(In thousands) December 31, 1999 December 31, 1998
+----------------- -----------------
+Point of sale $26,653 59.4% $27,778 53.2%
+Gaming and lottery 8,782 19.5 20,113 38.5
+Other 9,454 21.1 4,348 8.3
+------- ----- ------- -----
+$44,889 100.0% $52,239 100.0%
+======= ===== ======= =====
+Net sales for the year ended December 31, 1999 decreased $7,350,000, or
+14%, to $44,889,000 from $52,239,000 in 1998 due to decreased shipments into the
+POS and gaming and lottery markets, partially offset by an increase in the
+Company's other markets.
+Point of sale: Sales of the Company's POS printers decreased
+approximately $1,125,000, or 4%. International POS printer shipments decreased
+approximately $1,660,000 due largely to the absence of printer shipments for the
+British Post Office project. Shipments for this project totaled approximately
+$4,600,000 in 1998. The absence of printer shipments for the British Post Office
+project was largely offset by increased printer shipments to Europe and Latin
+America through the Company's distribution partner, Okidata. Domestic POS
+printer shipments increased by approximately $535,000 due largely to increased
+domestic demand for the Company's POS printers in the third quarter of 1999,
+particularly its thermal receipt printer.
+12
+13
+Gaming and lottery: Sales of the Company's gaming and lottery printers
+decreased approximately $11,331,000, or 56%, from 1998. The overall decrease
+primarily reflects a decrease of approximately $15,800,000 in shipments of the
+Company's on-line lottery printers and spare parts to GTECH. The Company did not
+make any shipments of on-line lottery printers, other than spares, to GTECH in
+1999. The decrease in sales of printers for use in on-line lottery terminals was
+largely offset by (1) an increase of approximately $300,000 of sales of in-lane
+and other lottery printers to GTECH and (2) an increase of approximately
+$3,900,000 in shipments of printers for use in VLTs, primarily for use in South
+Carolina's video poker industry. During 1998, shipments of VLT printers were
+significantly lower due to uncertainty in South Carolina's video poker industry
+concerning the industry's continued future in the state. In October 1999, the
+Supreme Court of South Carolina upheld legislation to prohibit the use of video
+poker machines beginning July 1, 2000.
+Other: Sales of the Company's printers into other markets increased
+$5,106,000, or 117% from 1998 due largely to increased shipments of printers
+(approximately $2,400,000) used in automated teller machines. Additionally,
+sales into the Company's other markets increased due to shipments of printers to
+a new customer for use in a bank teller application and resumed shipments of
+approximately $1,400,000 of the Company's thermal kiosk printers for use in a
+Canadian government application. No shipments of these kiosk printers were made
+in 1998.
+GROSS PROFIT. Gross profit decreased $2,072,000, or 15%, to $11,754,000
+from $13,826,000 in 1998 due primarily to lower sales volume in 1999 compared to
+1998. The gross margin slightly declined to 26.2% from 26.5%.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses decreased $407,000, or 11%, to $3,235,000 from $3,642,000
+in 1998. This decrease is primarily due to (1) a reduction in engineering staff
+resulting from the downsizing and reorganization of the Company's manufacturing
+facility in Wallingford, Connecticut in December 1998 and (2) unusually high
+expenses related to development of certain of the Company's thermal printers in
+1998. These reductions were somewhat offset by increased product development and
+design expenses, primarily for new products in the POS market, including
+expenses related to the development of printers utilizing inkjet printing
+technology. Engineering and product development expenses increased as a
+percentage of net sales to 7.2% from 7.0%, due largely to lower sales in 1999
+compared to 1998.
+SELLING AND MARKETING. Selling and marketing expenses increased
+$607,000, or 19%, to $3,887,000 from $3,280,000 in 1998, and increased as a
+percentage of net sales to 8.7% from 6.3%. Such expenses increased due primarily
+to (1) higher sales commissions resulting from an increase in sales eligible for
+commissions in 1999 compared to 1998 and (2) additional marketing staff related
+to the establishment of a corporate marketing department in the second half of
+1998.
+13
+14
+GENERAL AND ADMINISTRATIVE. General and administrative expenses
+increased $141,000, or 3% to $4,597,000 in 1999 from $4,456,000 in 1998. The
+increase primarily resulted from higher depreciation expense largely from the
+purchase of new computer and telecommunications hardware and software, partially
+offset by a reduction in staff resulting from the downsizing and reorganization
+of the Company's manufacturing facility in Wallingford, CT in December 1998.
+General and administrative expenses increased as a percentage of net sales to
+10.2% from 8.5%, primarily due to lower sales in 1999 compared to 1998.
+PROVISION FOR RESTRUCTURING. During the year ended December 31, 1998,
+the Company recorded a provision for restructuring of $300,000 to cover
+severance costs related to the downsizing and reorganization of the Company's
+manufacturing facility in Wallingford, Connecticut.
+OPERATING INCOME. Operating income decreased $2,113,000 to $35,000 from
+$2,148,000 in 1998. Operating income as a percentage of net sales declined to
+0.1% from 4.1%, due primarily to (1) less gross profit on lower sales volume,
+(2) increased selling and marketing expenses and (3) $350,000 of nonrecurring
+costs related to the GTECH product line.
+OTHER INCOME. Other income for the year ended December 31, 1999
+includes a one-time gain of $770,000 related to the favorable settlement of a
+lawsuit with GTECH.
+INTEREST. Net interest expense increased to $399,000 from $353,000 in
+1998 due to increased average outstanding borrowings on the Company's line of
+credit and a higher average borrowing rate in 1999 compared to 1998.
+INCOME TAXES. The provision for income taxes for the year ended
+December 31, 1999 reflects an effective tax rate of 24% compared to 34% in the
+prior year. The significant decline in the Company's effective tax rate largely
+resulted from the amplified impact of the recognition of certain tax credits
+compared to a relatively low income before taxes in 1999.
+NET INCOME. Net income for 1999 was $324,000, or $0.06 per share (basic
+and diluted), as compared to $1,206,000, or $0.20 per share (basic and diluted)
+in 1998.
+(B) LIQUIDITY AND CAPITAL RESOURCES
+The Company generated cash from operations of $333,000, $2,033,000 and
+$4,047,000 in 2000, 1999 and 1998, respectively. The decrease in cash generated
+from operations in 2000 compared to 1999 resulted largely from (1) higher
+receivables at December 31, 2000 and (2) funding of the Company's net loss in
+2000. The Company's working capital increased to $13,631,000 at December 31,
+2000 from $11,094,000 at December 31, 1999. The current ratio also increased to
+3.54 to 1 at December 31, 2000 from 2.90 to 1 at December 31, 1999. Both the
+increase in working capital and the current ratio were largely due to (1) higher
+receivables at December 31, 2000 resulting from higher sales volume in the
+fourth quarter of 2000 compared to the fourth quarter of 1999 and (2) a higher
+cash balance at December 31, 2000.
+14
+15
+On September 21, 2000, the Company entered into a two-year revolving
+credit facility (the "Webster Credit Facility") with Webster Bank ("Webster")
+expiring on September 21, 2002. The Webster Credit Facility replaced a previous
+credit facility with Fleet National Bank. Under the Webster Credit Facility, the
+Company may borrow up to $12 million, based on certain financial criteria of the
+Company at the time of any borrowing, to fund working capital. Borrowings under
+the Webster Credit Facility bear a floating rate of interest at the higher of
+the "Prime Rate" as published in The Wall Street Journal or one-half of one
+percent (1/2%) over the federal funds rate (as defined in the Webster Credit
+Facility). Under certain circumstances, the Company may select a fixed interest
+rate for a specified period of up to 90 days on borrowings based on the current
+LIBOR rate (as adjusted as specified in the Webster Credit Facility) plus 2.5%,
+which may be reduced to 2.25% on July 1, 2001 if there is no Event of Default
+(as defined in the Webster Credit Facility). The Company will also pay a fee of
+three-eighths of one percent (3/8%) on unused borrowing capacity under the
+Webster Credit Facility. Borrowings under the Webster Credit Facility are
+secured by a lien on substantially all the assets of the Company. The Webster
+Credit facility also imposes certain financial covenants on the Company and
+restricts the payment of dividends on its common stock and the creation of other
+liens. The Company had $5,944,000 of outstanding borrowings under this facility
+at December 31, 2000.
+On February 27, 2001, the Company amended the Webster Credit Facility
+to (1) provide the Company with the ability to borrow up to $1,500,000 in excess
+of the amount permitted under the Webster Credit Facility's borrowing base
+formula ("Permitted Over-Formula Borrowing") and (2) revise certain financial
+covenants. The Permitted Over-Formula Borrowing is effective from March 1, 2001
+through August 31, 2001.
+On April 7, 2000 the Company sold 4,000 shares of 7% Series B
+Cumulative Convertible Redeemable Preferred Stock (the "Preferred Stock") to
+Advance Capital Advisors, L.P. and its affiliate in consideration of $1,000 per
+share (the "Stated Value"), for a total of $4,000,000, less issuance costs of
+approximately $200,000. The Preferred Stock is convertible at any time by the
+holders at a conversion price of $9.00 per common share. In addition, the
+Company issued warrants pro-rata to the Preferred Stock holders to purchase an
+aggregate of 44,444 shares of the Company's common stock at an exercise price of
+$9.00 per common share. The warrants, valued at $175,000, are exercisable at any
+time until April 7, 2005. The Preferred Stock is subject to mandatory conversion
+into shares of the Company's common stock when such stock has traded at $35 per
+share or more for a 30-day period ending on or after April 7, 2003, or for a
+60-day period beginning on or after April 7, 2002. The Preferred Stock is
+redeemable at the option of the holders on or after April 7, 2005 at $1,000 per
+share plus any unpaid dividends. On April 7, 2007, the Company has the right to
+require (1) redemption of the Preferred Stock at $1,000 per share plus any
+unpaid dividends or (2) conversion of the Preferred Stock at $9.00 per common
+share. Upon a change of control (which the Company does not believe probable),
+holders have the right to redeem the Preferred Stock for 200% of the Stated
+Value plus any unpaid dividends. The holders of the Preferred Stock have certain
+voting rights and are entitled to receive a cumulative annual dividend of $70
+per share, payable quarterly, and have preference to any other dividends, if
+any, paid by the Company.
+The Company's capital expenditures were approximately $2,415,000,
+$2,742,000 and $2,232,000 in 2000, 1999 and 1998, respectively. These
+expenditures primarily included new product tooling, computer equipment, and
+factory machinery and equipment. The Company's capital expenditures for 2001 are
+expected to be approximately $2,000,000, a majority for new product tooling.
+15
+16
+The Company estimates that the non-recurring costs associated with the
+Consolidation will be approximately $3.0 to $3.5 million, and will be recognized
+during 2001. Of these costs, approximately $2.5 to $3.0 million will require
+future cash outlays. The Company expects to pay approximately $500,000 to
+$800,000 in 2001 and the remainder in 2002.
+The Company believes that cash flows generated from operations and
+borrowings available under the Webster Credit Facility, as necessary, will
+provide sufficient resources to meet the Company's working capital needs,
+including costs associated with the Consolidation, finance its capital
+expenditures and meet its liquidity requirements through December 31, 2001
+(C) IMPACT OF INFLATION
+TransAct believes that its business has not been affected to a
+significant degree by inflationary trends because of the low rate of inflation
+during the past three years.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
+INTEREST RATE RISK
+The Company's exposure to market risk for changes in interest rates
+relates primarily to borrowings under the Company's Credit Facility with Webster
+Bank. These borrowings bear interest at variable rates and the fair value of
+this indebtedness is not significantly affected by changes in market interest
+rates. An effective increase or decrease of 10% in the current effective
+interest rates under the Credit Facility would not have a material effect on the
+Company's results of operations or cash flow.
+FOREIGN CURRENCY EXCHANGE RISK
+A substantial portion of the Company's sales are denominated in U.S.
+dollars and, as a result, the Company has relatively little exposure to foreign
+currency exchange risk with respect to sales made. This exposure may change over
+time as business practices evolve and could have a material adverse impact on
+the Company's financial results in the future. The Company does not use forward
+exchange contracts to hedge exposures denominated in foreign currencies or any
+other derivative financial instruments for trading or speculative purposes. The
+effect of an immediate 10% change in exchange rates would not have a material
+impact on the Company's future results of operations or cash flow.
+16
+17
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Page
+Number
+------
+Report of Independent Accountants 18
+TransAct Technologies Incorporated consolidated financial statements:
+Consolidated balance sheets as of December 31, 2000 and December 31, 1999. 19
+Consolidated statements of operations for the years ended December 31, 2000, 1999 and 1998. 20
+Consolidated statements of cash flows for the years ended December 31, 2000, 1999 and 1998. 21
+Consolidated statement of changes in shareholders' equity for the period from December 31, 22
+1997 through December 31, 2000.
+Notes to consolidated financial statements. 23
+17
+18
+REPORT OF INDEPENDENT ACCOUNTANTS
+To the Board of Directors and Shareholders
+of TransAct Technologies Incorporated
+In our opinion, the accompanying consolidated balance sheets and the related
+consolidated statements of operations, of cash flows and of changes in
+shareholders' equity present fairly, in all material respects, the financial
+position of TransAct Technologies Incorporated and its subsidiaries at December
+31, 2000 and 1999, and the results of their operations and their cash flows for
+each of the three years in the period ended December 31, 2000 in conformity with
+accounting principles generally accepted in the United States. 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 of these statements in accordance with
+auditing standards generally accepted in the United States, which 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, assessing the accounting principles used and
+significant estimates made by management, and evaluating the overall financial
+statement presentation. We believe that our audits provide a reasonable basis
+for the opinion expressed above.
+/s/ PricewaterhouseCoopers LLP
+Hartford, Connecticut
+February 27, 2001
+18
+19
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED BALANCE SHEETS
+(In thousands)
+December 31, December 31,
+2000 1999
+---- ----
+ASSETS:
+Current assets:
+Cash and cash equivalents $ 992 $ 279
+Receivables, net (Note 4) 6,137 4,863
+Inventories (Note 5) 9,857 10,257
+Deferred tax assets 1,205 1,144
+Other current assets 811 396
+-------- --------
+Total current assets 19,002 16,939
+-------- --------
+Fixed assets, net (Note 6) 6,794 6,705
+Goodwill, net (Note 2) 1,678 1,886
+Other assets 145 154
+-------- --------
+8,617 8,745
+-------- --------
+$ 27,619 $ 25,684
+======== ========
+LIABILITIES AND SHAREHOLDERS' EQUITY:
+Current liabilities:
+Account payable $ 2,690 $ 3,056
+Accrued liabilities (Note 7) 2,681 2,789
+-------- --------
+Total current liabilities 5,371 5,845
+-------- --------
+Long-term debt (Note 9) 5,944 7,100
+Other liabilities 445 532
+-------- --------
+6,389 7,632
+-------- --------
+Commitments and contingencies (Note 10)
+Mandatorily redeemable preferred stock, Series B, 7%
+cumulative convertible, $1,000 stated value, 8,000 shares
+authorized, 4,000 shares issued and outstanding (Note 15) 3,668 --
+-------- --------
+Shareholders' equity (Notes 11 and 12):
+Preferred stock, Series A, $0.01 par value, 5,000,000
+authorized, none issued and outstanding -- --
+Common stock, $0.01 par value; 20,000,000 authorized;
+5,607,827 and 5,576,800 shares issued 56 56
+Additional paid-in capital 6,069 5,656
+Retained earnings 6,929 7,592
+Unamortized restricted stock compensation (477) (747)
+Loan receivable from officer (330) (330)
+Accumulated other comprehensive income (56) (20)
+-------- --------
+Total shareholders' equity 12,191 12,207
+-------- --------
+$ 27,619 $ 25,684
+======== ========
+See accompanying notes to consolidated financial statements.
+19
+20
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except per share data)
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+Net sales $ 53,720 $ 44,889 $ 52,239
+Cost of sales 39,578 33,135 38,413
+-------- -------- --------
+Gross profit 14,142 11,754 13,826
+-------- -------- --------
+Operating expenses:
+Engineering, design and product
+development expenses 3,481 3,235 3,642
+Selling and marketing expenses 5,086 3,887 3,280
+General and administrative expenses 5,540 4,597 4,456
+Provision for restructuring (Note 15) 189 -- 300
+-------- -------- --------
+14,296 11,719 11,678
+-------- -------- --------
+Operating income (loss) (154) 35 2,148
+-------- -------- --------
+Other income (expense):
+Interest, net (649) (399) (353)
+Other, net (Note 15) 11 790 32
+-------- -------- --------
+(638) 391 (321)
+-------- -------- --------
+Income (loss) before income taxes (792) 426 1,827
+Income tax provision (benefit) (Note 13) (448) 102 621
+-------- -------- --------
+Net income (loss) (344) 324 1,206
+Dividends and accretion charges on preferred
+stock (Note 15) (320) -- --
+-------- -------- --------
+Net income (loss) available to common
+shareholders $ (664) $ 324 $ 1,206
+======== ======== ========
+Net income (loss) per share:
+Basic $ (0.12) $ 0.06 $ 0.20
+======== ======== ========
+Diluted $ (0.12) $ 0.06 $ 0.20
+======== ======== ========
+Weighted average common shares outstanding:
+Basic 5,504 5,565 6,163
+======== ======== ========
+Diluted 5,504 5,614 6,170
+======== ======== ========
+See accompanying notes to consolidated financial statements.
+20
+21
+TransAct Technologies Incorporated
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+Cash flows from operating activities:
+Net income (loss) $ (344) $ 324 $ 1,206
+Adjustments to reconcile net income (loss) to
+net cash provided by operating activities:
+Depreciation and amortization 2,750 2,238 2,030
+Deferred income taxes (78) (19) (415)
+Loss on disposal of equipment -- 11 8
+Changes in operating assets and liabilities:
+Receivables (1,274) 371 2,082
+Inventories 400 (1,475) (174)
+Other current assets (415) 158 173
+Other assets (162) (100) (134)
+Accounts payable (366) 858 (855)
+Accrued liabilities and other liabilities (178) (333) 126
+------- ------- -------
+Net cash provided by operating activities 333 2,033 4,047
+------- ------- -------
+Cash flows from investing activities:
+Purchases of fixed assets (2,415) (2,742) (2,232)
+Loans to officers 15 (345) --
+Acquisition of Tridex Ribbon Business -- (295) --
+Proceeds from sale of assets 217 -- 3
+------- ------- -------
+Net cash used in investing activities (2,183) (3,382) (2,229)
+------- ------- -------
+Cash flows from financing activities:
+Bank line of credit borrowings (repayments), net (1,156) 1,300 5,500
+Proceeds from option exercises 175 24 2
+Net proceeds from issuance of preferred stock 3,785 -- --
+Payment of cash dividends on preferred stock (205) -- --
+Purchases of treasury stock -- (229) (7,170)
+Tax benefit related to employee stock sales -- -- 3
+------- ------- -------
+Net cash provided by (used in) financing
+activities 2,599 1,095 (1,665)
+------- ------- -------
+Effect of exchange rate changes on cash (36) (13) 2
+------- ------- -------
+Increase (decrease) in cash and cash equivalents 713 (267) 155
+Cash and cash equivalents at beginning of
+period 279 546 391
+------- ------- -------
+Cash and cash equivalents at end of period $ 992 $ 279 $ 546
+======= ======= =======
+Supplemental cash flow information:
+Interest paid $ 696 $ 433 $ 351
+Income taxes paid 74 171 561
+See accompanying notes to consolidated financial statements.
+21
+22
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
+(In thousands, except share data)
+Additional
+Common Stock Paid-in Retained
+Shares Amount Capital Earnings
+------ ------ ------- --------
+Balance, December 31, 1997 6,610,300 68 14,975 6,062
+Issuance of restricted stock 25,000 -- 228 --
+Cancellation of restricted
+stock (3,000) -- (36) --
+Issuance of shares from
+exercise of stock options 200 -- 2 --
+Amortization of restricted
+stock compensation -- -- -- --
+Tax benefit related to
+employee stock sales -- -- 3 --
+---------- ---------- ---------- ----------
+Purchase of treasury shares (1,003,000) -- -- --
+Retirement of treasury
+shares -- (12) (9,409) --
+Comprehensive income:
+Foreign currency
+translation adjustment -- -- -- --
+Net income -- -- -- 1,206
+---------- ---------- ---------- ----------
+Balance, December 31, 1998 5,629,500 56 5,763 7,268
+Issuance of restricted stock 13,000 -- 98 --
+Issuance of shares from
+exercise of stock options 5,100 -- 24 --
+Amortization of restricted
+stock compensation -- -- -- --
+Purchase of treasury shares (70,800) -- -- --
+Retirement of treasury
+shares -- -- (229) --
+Issuance of loan to officer -- -- -- --
+Comprehensive income:
+Foreign currency
+translation adjustment -- -- -- --
+Net income -- -- -- 324
+---------- ---------- ---------- ----------
+Balance, December 31, 1999 5,576,800 56 5,656 7,592
+Issuance of restricted stock 5,000 -- 44 --
+Cancellation of restricted
+stock (3,800) -- (36) --
+Issuance of shares from
+exercise of stock options 25,000 -- 150 --
+Issuance of shares from
+employee stock purchase plan 4,827 -- 24 --
+Amortization of restricted
+stock compensation -- -- -- --
+Issuance of preferred stock
+warrants -- -- 175 --
+Deemed dividend on beneficial
+conversion of preferred stock -- -- 56 (56)
+Dividends paid on preferred
+stock -- -- -- (205)
+Accretion of preferred stock
+warrants and issuance costs -- -- -- (58)
+Comprehensive income:
+Foreign currency
+translation adjustment -- -- -- --
+Net loss -- -- -- (344)
+---------- ---------- ---------- ----------
+Balance, December 31, 2000 5,607,827 $ 56 $ 6,069 $ 6,929
+========== ========== ========== ==========
+Unamortized Loan Accumulated
+Restricted Receivable Other
+Stock from Comprehensive Treasury
+Compensation Officer Income Stock
+------------ ------- ------ -----
+Balance, December 31, 1997 (942) -- (9) (2,251)
+Issuance of restricted stock (228) -- -- --
+Cancellation of restricted
+stock 36 -- -- --
+Issuance of shares from
+exercise of stock options -- -- -- --
+Amortization of restricted
+stock compensation 231 -- -- --
+Tax benefit related to
+employee stock sales -- -- -- --
+Purchase of treasury shares -- -- -- (7,170)
+Retirement of treasury
+shares -- -- -- 9,421
+Comprehensive income:
+Foreign currency
+translation adjustment -- -- 2 --
+Net income -- -- -- --
+---------- ---------- ---------- ----------
+Balance, December 31, 1998 (903) -- (7) --
+Issuance of restricted stock (98) -- -- --
+Issuance of shares from
+exercise of stock options -- -- -- --
+Amortization of restricted
+stock compensation 254 -- -- --
+Purchase of treasury shares -- -- -- (229)
+Retirement of treasury
+shares -- -- -- 229
+Issuance of loan to officer -- (330) -- --
+Comprehensive income:
+Foreign currency
+translation adjustment -- -- (13) --
+Net income -- -- -- --
+---------- ---------- ---------- ----------
+Balance, December 31, 1999 (747) (330) (20) --
+Issuance of restricted stock (44) -- -- --
+Cancellation of restricted
+stock 36 -- -- --
+Issuance of shares from
+exercise of stock options -- -- -- --
+Issuance of shares from
+employee stock purchase plan -- -- -- --
+Amortization of restricted
+stock compensation 278 -- -- --
+Issuance of preferred stock
+warrants -- -- -- --
+Deemed dividend on beneficial
+conversion of preferred stock -- -- -- --
+Dividends paid on preferred
+stock -- -- -- --
+Accretion of preferred stock
+warrants and issuance costs -- -- -- --
+Comprehensive income:
+Foreign currency
+translation adjustment -- -- (36) --
+Net loss -- -- -- --
+---------- ---------- ---------- ----------
+Balance, December 31, 2000 $ (477) $ (330) $ (56) $ --
+========== ========== ========== ==========
+See accompanying notes to consolidated financial statements.
+22
+23
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+1. BASIS OF PRESENTATION
+TransAct Technologies Incorporated ("TransAct" or the "Company") began
+operating as a stand-alone, publicly-held company in August 1996 to conduct
+the printer business that was formerly operated by certain subsidiaries of
+Tridex Corporation ("Tridex").
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+BUSINESS AND PRODUCTS: TransAct, through its two operations, one in
+Wallingford, CT and the other in Ithaca, NY, operates in one industry
+segment, transaction-based printers and related products. TransAct designs,
+develops, manufactures and markets transaction-based printers and related
+products under the Ithaca(R), Magnetec(R) and TransAct.com brand
+names. The Company's printers are used worldwide to provide transaction
+records such as receipts, tickets, coupons, register journals and other
+documents. The Company focuses on five vertical markets: point-of-sale
+("POS"), gaming and lottery, financial services, kiosk and Internet. The
+Company sells its products directly to end users, original equipment
+manufacturers ("OEM"), value-added resellers and selected distributors,
+primarily in the United States, Canada, Europe and Latin America.
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing inkjet, thermal and impact printing
+technology for applications requiring up to 60 character columns in each of
+its vertical markets. The Company's printers are configurable, which offer
+customers the ability to choose from a variety of features and functions.
+Options typically include PC board configuration, paper cutting devices,
+paper handling capacities and number of print stations. In addition to its
+configurable printers, TransAct manufactures custom printers for certain
+OEM customers. In collaboration with these customers, the Company provides
+engineering and manufacturing expertise for the design and development of
+specialized printers.
+USE OF ESTIMATES: The preparation of financial statements in conformity
+with generally accepted accounting principles requires management to make
+estimates and assumptions that affect the reported amounts of assets and
+liabilities and disclosure of contingent assets and liabilities at the date
+of the financial statements and the reported amounts of revenues and
+expenses during the reporting period. Significant estimates have been made
+in areas including inventory valuation, estimated lives of fixed assets and
+goodwill, deferred tax assets, accrued liabilities, allowance for doubtful
+accounts and tax provisions (benefits). Actual results could differ from
+those estimates.
+PRINCIPLES OF CONSOLIDATION: The accompanying consolidated financial
+statements include the accounts of the Company and its wholly-owned
+subsidiaries, after elimination of all material intercompany accounts and
+transactions.
+CASH AND CASH EQUIVALENTS: The Company considers all highly liquid
+investments with a maturity date of three months or less at date of
+purchase to be cash equivalents.
+INVENTORIES: Inventories are stated at the lower of cost (principally
+standard cost which approximates actual cost on a first-in, first-out
+basis) or market.
+FIXED ASSETS: Fixed assets are stated at cost. Depreciation is provided
+for primarily by the straight-line method over the estimated useful lives.
+The estimated useful life of machinery, furniture and equipment is three to
+ten years. Leasehold improvements are amortized over the shorter of the
+term of the lease or the useful life of the asset. Depreciation amounted to
+$2,176,000, $1,699,000 and $1,546,000 in 2000, 1999 and 1998, respectively.
+23
+24
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+GOODWILL: Goodwill resulted from the acquisition of (i) Ithaca
+Peripherals, Inc. in 1991 and the (ii) ribbon business formerly conducted
+by Tridex ("Tridex Ribbon Business") in 1999. The original amount
+applicable to the Ithaca acquisition totaled $3,536,000 and is being
+amortized on the straight-line method over 20 years. The original amount
+applicable to the Tridex Ribbon Business acquisition totaled $180,000 and
+is being amortized on the straight-line method over five years. Accumulated
+amortization of goodwill was $2,038,000 and $1,830,000 at December 31, 2000
+and 1999, respectively. The Company periodically reviews goodwill to assess
+recoverability based upon expectations of non-discounted cash flows from
+operations of the acquired businesses. The Company believes that no
+impairment of goodwill exists at December 31, 2000.
+REVENUE RECOGNITION: Sales are recognized when evidence of an
+arrangement exists, delivery has occurred, the selling price is fixed and
+determinable, and collectibility is reasonably assured. Revenue from
+extended warranty and maintenance agreements is recognized over the term of
+such agreements as services are performed. Sales to GTECH Corporation
+("GTECH") (for lottery printers) and ICL Pathway (for the British Post
+Office project) accounted for approximately 22% and 20% of net sales during
+2000, respectively. No one customer accounted for more than 10% of net
+sales during 1999. Sales to one customer, GTECH, accounted for
+approximately 32% of net sales for the year ended December 31, 1998.
+FOREIGN CURRENCY: The financial position and results of operations of
+the Company's foreign subsidiaries are measured using local currency as the
+functional currency. Assets and liabilities of such subsidiaries have been
+translated at end of period exchange rates, and related revenues and
+expenses have been translated at weighted average exchange rates.
+Transaction gains (losses) are included in other income and amounted to
+$(26,000), $11,000 and 17,000 in 2000, 1999 and 1998, respectively.
+INCOME TAXES: The income tax amounts reflected in the accompanying
+financial statements are accounted for under the liability method in
+accordance with FAS 109 "Accounting for Income Taxes."
+STOCK-BASED COMPENSATION: The Company has elected to follow Accounting
+Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
+("APB 25"), and related interpretations in accounting for its stock
+options. Since the exercise price of employee stock options granted by the
+Company generally equals the market price of the underlying stock on the
+date of grant, no compensation expense is recorded. The Company has adopted
+the disclosure-only provisions of Statement of Financial Accounting
+Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123").
+See Note 11.
+SEGMENT REPORTING: FASB Statement of Financial Accounting Standards No.
+131, "Disclosures about Segments of an Enterprise and Related Information"
+("FAS 131") requires that a public business enterprise report financial and
+descriptive information about its reportable operating segments. Generally,
+financial information is required to be reported on the basis that it is
+used internally for evaluating segment performance and allocating
+resources. The Company has assessed its operating and reportable segments
+and determined that it operates in one reportable segment as defined in FAS
+131.
+DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES: The Financial Accounting
+Standards Board issued Statement of Financial Standards No. 133,
+"Accounting for Derivative Instruments and Hedging Activities" ("FAS 133")
+in June 1998 which, as amended, is currently effective January 1, 2001 for
+the Company. The Company believes adoption of FAS 133 will not have a
+material impact on the Company's financial position, results of operations
+or cash flows.
+24
+25
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+3. ACQUISITION
+On May 28, 1999, the Company acquired the business and substantially
+all the assets of the Tridex Ribbon Business for total cash consideration
+of approximately $295,000. The acquisition has been accounted for by the
+purchase method of accounting. The purchased assets and liabilities have
+been recorded in the Company's financial statements at their estimated fair
+values at the acquisition date. The results of operations of the acquired
+company have been included with those of the Company since the date of
+acquisition. The acquisition cost exceeded the fair value of the net assets
+acquired by $180,000. Such goodwill is being amortized over a five-year
+period on a straight-line basis. Prior to the acquisition, the Company
+provided Tridex with space within its Wallingford, CT manufacturing
+facility and certain support services for the Tridex Ribbon Business.
+4. RECEIVABLES
+Receivables are net of the allowance for doubtful accounts. The
+reconciliation of the allowance for doubtful accounts is as follows:
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+(In thousands)
+Balance at beginning of period $ 132 $ 139 $ 102
+Doubtful accounts provision (reversal) (24) - 41
+Accounts written off, net of recoveries (1) (7) (4)
+------ ------ ------
+Balance at end of period $ 107 $ 132 $ 139
+====== ====== ======
+5. INVENTORIES
+The components of inventories are:
+December 31,
+(In thousands) 2000 1999
+---- ----
+Raw materials and component parts $ 9,603 $ 9,198
+Work-in-process 200 542
+Finished goods 54 517
+-------- --------
+$ 9,857 $ 10,257
+======== ========
+6. FIXED ASSETS
+The components of fixed assets are:
+December 31,
+(In thousands) 2000 1999
+---- ----
+Tooling, machinery and equipment $10,974 $ 9,501
+Furniture, office and computer equipment 3,811 3,746
+Leasehold improvements 749 660
+------- -------
+15,534 13,907
+Less: accumulated depreciation (8,740) (7,202)
+------- -------
+$ 6,794 $ 6,705
+======= =======
+25
+26
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+7. ACCRUED LIABILITIES
+The components of accrued liabilities are:
+December 31,
+(In thousands) 2000 1999
+---- ----
+Payroll and fringe benefits $ 382 $ 521
+Income taxes accrued 765 653
+Warranty 657 638
+Deferred revenue 108 129
+Restructuring 105 -
+Other 664 848
+------- -------
+$ 2,681 $ 2,789
+======= =======
+8. EMPLOYEE BENEFIT PLANS
+RETIREMENT SAVINGS PLAN: On April 1, 1997, the Company established the
+TransAct Technologies Retirement Savings Plan (the "401(k) Plan"), a
+defined contribution plan under Section 401(k) of the Internal Revenue
+Code. All full-time employees are eligible to participate in the 401(k)
+Plan at the beginning of the calendar quarter immediately following their
+date of hire. The Company matches employees' contributions at a rate of 50%
+of employees' contributions up to the first 5% of the employees'
+compensation contributed to the 401(k) Plan. The Company's matching
+contributions were $203,000, $145,000 and $159,000 in 2000, 1999 and 1998,
+respectively. During 1999 and 1998, the Company's rate of matching
+contributions was 50% of the employees' contributions up to the first 4% of
+the employees' compensation contributed to the 401(k) Plan.
+EMPLOYEE STOCK PURCHASE PLAN: In May 2000, the Company's shareholders
+approved the Employee Stock Purchase Plan (the "ESPP"), under which 50,000
+shares of the Company's common stock are available for issuance to
+employees beginning June 1, 2000. All full-time employees are eligible to
+participate in the ESPP at the beginning of each six-month period (the
+"Offering Period"), which begin on June 1 and December 1. Eligible
+employees may elect to withhold up to 5% of their salary to purchase shares
+of the Company's common stock at a price equal to 85% of the fair market
+value of the stock on the first or last day of each Offering Period,
+whichever is lower. The ESPP will terminate at the earlier of May 31, 2005
+or the date on which all 50,000 shares available for issuance under the
+ESPP have been sold. During 2000, the Company sold 4,827 shares of common
+stock at $4.88 per share under the ESPP. At December 31, 2000, 45,173
+shares remained available for sale. Compensation costs related to the ESPP
+are immaterial.
+9. BANK CREDIT AGREEMENT
+On January 29, 1998, the Company entered into a $15,000,000 credit
+facility with Fleet National Bank ("Fleet"). On May 7, 1999, the Company
+replaced this facility with a new two-year $10,000,000 revolving credit
+facility with Fleet (the "Fleet Credit Facility"). The Fleet Credit
+Facility provided the Company with a $10,000,000 credit facility used to
+fund working capital. Borrowings under the Fleet Credit facility bore
+interest on outstanding borrowings at Fleet's prime rate and bore a
+commitment fee ranging from 0.25% to 0.625% on any unused portion of the
+Fleet Credit Facility. The Fleet Credit Facility also permitted the Company
+to designate a LIBOR rate on outstanding borrowings with a margin ranging
+from 1.50 to 2.25 percentage points over the market rate ("Margin"),
+depending on the Company meeting certain ratios. Concurrent with the Fleet
+Credit Facility, the Company entered into a swap agreement with Fleet under
+which the Company fixed its interest rate at 5.63% plus the applicable
+Margin for two years on $3,000,000 of outstanding borrowings under the
+Fleet Credit Facility. The Fleet Credit Facility was secured by a lien on
+substantially all the assets of the Company, imposed certain financial
+covenants and restricted the payment of cash dividends and the creation of
+liens.
+26
+27
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+9. BANK CREDIT AGREEMENT (CONTINUED)
+On March 14, 2000, the Company entered into a new two-year $13,000,000
+revolving credit facility (the "New Fleet Credit Facility") with Fleet. The
+New Fleet Credit Facility replaced the Fleet Credit Facility. The New Fleet
+Credit Facility provided the Company with a $13,000,000 credit facility
+used to fund working capital. Borrowings under the New Fleet Credit
+facility bore interest on outstanding borrowings at Fleet's prime rate plus
+a margin ranging from zero to 0.75 percentage points and bore a commitment
+fee ranging from 0.375% to 0.75% on any unused portion of the New Fleet
+Credit Facility. The New Fleet Credit Facility also permitted the Company
+to designate a LIBOR rate on outstanding borrowings with a margin ranging
+from 1.5 to 3.0 percentage points over the market rate, depending on the
+Company meeting certain ratios. The New Fleet Credit Facility was secured
+by a lien on substantially all the assets of the Company, imposed certain
+financial covenants and restricted the creation of liens.
+On September 21, 2000, the Company entered into a two-year revolving
+credit facility (the "Webster Credit Facility) with Webster Bank
+("Webster") expiring on September 21, 2002. The Webster Credit Facility
+replaced the New Fleet Credit Facility. Under the Webster Credit Facility,
+the Company may borrow up to $12 million, based on certain financial
+criteria of the Company at the time of any borrowing, to fund working
+capital. Borrowings under the Webster Credit Facility bear a floating rate
+of interest at the higher of the "Prime Rate" as published in The Wall
+Street Journal or one-half of one percent (1/2%) over the federal funds
+rate (as defined in the Webster Credit Facility) (9.5% at December 31,
+2000). Under certain circumstances, the Company may select a fixed interest
+rate for a specified period of up to 90 days on borrowings based on the
+current LIBOR rate (as adjusted as specified in the Webster Credit
+Facility) plus 2.5%, which may be reduced to 2.25% on July 1, 2001 if there
+is no Event of Default (as defined in the Webster Credit Facility). The
+Company will also pay a fee of three-eighths of one percent (3/8%) on
+unused borrowing capacity under the Webster Credit Facility. Borrowings
+under the Webster Credit Facility are secured by a lien on substantially
+all the assets of the Company. The Webster Credit facility also imposes
+certain financial covenants on the Company and restricts the payment of
+dividends on its common stock and the creation of other liens. The Company
+had $5,944,000 of outstanding borrowings under this facility at December
+31, 2000.
+10. COMMITMENTS AND CONTINGENCIES
+At December 31, 2000, the Company was lessee on operating leases for
+equipment and real property. The terms of certain leases provide for
+escalating rent payments in later years of the lease as well as payment of
+minimum rent and real estate taxes. Rent expense amounted to approximately
+$991,000, $953,000 and $957,000 in 2000, 1999 and 1998, respectively.
+Minimum aggregate rental payments required under operating leases that have
+initial or remaining non-cancelable lease terms in excess of one year as of
+December 31, 2000 are as follows: $891,000 in 2001; $871,000 in 2002;
+$873,000 in 2003; $855,000 in 2004; $868,000 in 2005 and $1,663,000
+thereafter.
+The Company has a long-term purchase agreement for certain printer
+components. Under the terms of the agreement, the Company receives
+favorable pricing for volume purchases over the life of the contract. In
+the event anticipated purchase levels are not achieved, the Company would
+be subject to retroactive price increases on previous purchases. Management
+currently anticipates achieving sufficient purchase levels to maintain the
+favorable prices.
+11. STOCK OPTIONS AND WARRANTS
+STOCK OPTIONS. On July 30, 1996, the Company adopted the 1996 Stock
+Plan which provides for the grant of awards to officers and other key
+employees of the Company, and the Directors' Stock Plan which provides for
+non-discretionary awards to non-employee directors. The plans provide for
+awards in the form of: (i) incentive stock options, (ii) non-qualified
+stock options, (iii) shares of restricted stock, (iv) restricted units, (v)
+stock appreciation rights or (vi) limited stock appreciation rights.
+Options granted are at prices equal to 100% of the fair market value of the
+common stock at the date of grant. Options granted have a ten-year term and
+generally vest over a five-year period, unless automatically accelerated
+for certain defined events. At December 31, 2000, the Company has reserved
+1,150,000 and 110,000 shares of common stock for issuance under the 1996
+Stock Plan and Directors' Stock Plan, respectively.
+27
+28
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+11. STOCK OPTIONS AND WARRANTS (CONTINUED)
+During the fourth quarter of 1998, the Company approved the
+cancellation and reissuance of certain outstanding options under the 1996
+Stock Plan. Under the program, holders of outstanding options as of
+December 10, 1998, excluding the Company's executive officers, obtained in
+substitution for existing options new options for the same number of
+shares. The new options, totaling 190,600, are exercisable at a price of
+$4.75 per share, the fair market value of the common stock on the reissue
+date. The new options maintain the vesting schedule established by the
+canceled option. These 190,600 options have been treated as canceled and
+granted in 1998 in the table below.
+The 1996 Stock Plan and Directors' Stock Plan option activity is
+summarized below:
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+------ ----- ------ ----- ------ -----
+Outstanding at beginning of
+period: 818,100 $7.89 752,300 $8.04 542,600 $10.97
+Granted 190,500 9.86 104,500 5.86 428,100 5.75
+Exercised (25,000) 6.05 (5,100) 4.75 (200) 8.50
+Canceled (64,600) 7.53 (33,600) 5.07 (218,200) 10.83
+------- ----- ------- ----- ------- ------
+Outstanding at end of period 919,000 $8.34 818,100 $7.89 752,300 $ 8.04
+======= ===== ======= ===== ======= ======
+Options exercisable at end
+of period 436,580 $8.19 296,140 $8.33 165,360 $ 8.28
+======= ===== ======= ===== ======= ======
+Options Outstanding Options Exercisable
+------------------- -------------------
+Weighted- Weighted- Weighted-
+Outstanding at Average Average Exercisable at Average
+December 31, Exercise Remaining December 31, Exercise
+Range of Exercise Prices 2000 Price Contractual Life 2000 Price
+------------------------ ---- ----- ---------------- ---- -----
+(In years)
+$ 2.50 - $ 5.00 238,400 $4.28 6.1 139,740 $4.40
+5.01 - 7.50 84,300 6.17 8.0 18,400 6.15
+7.51 - 10.00 344,800 8.76 6.1 208,840 8.64
+10.01 - 12.50 145,000 10.22 9.1 4,900 11.69
+12.51 - 15.00 45,500 13.75 5.8 28,100 13.75
+15.01 - 17.50 61,000 16.38 6.6 36,600 16.38
+The Company applies APB 25 and related interpretations in accounting
+for its long-term incentive stock plans. Accordingly, no compensation cost
+has been recognized for its stock options.
+Had compensation expense been recognized based on the fair value of
+the options at their grant dates, as prescribed in FAS 123, the Company's
+net income (loss) and net income (loss) per share would have been as
+follows:
+28
+29
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+11. STOCK OPTIONS AND WARRANTS (CONTINUED)
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+(In thousands, except per share data)
+Net income (loss) available to common shareholders:
+As reported $ (664) $ 324 $ 1,206
+Pro forma under FAS 123 (1,171) (422) 747
+Net income (loss) per share:
+Basic and diluted:
+As reported (0.12) 0.06 0.20
+Pro forma under FAS 123 (0.21) (0.08) 0.12
+The fair value of each option grant is estimated on the date of grant
+using the Black-Scholes option pricing model with the following assumptions
+used for the grants made during the years ended December 31, 2000, 1999 and
+1998.
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+Risk-free interest rate 6.3% 5.8% 4.9%
+Dividend yield 0% 0% 0%
+Expected volatility factor 83.1% 78.0% 78.1%
+Expected option term 7.1 years 7.5 years 10 years
+Weighted average fair value of options granted during period $7.78 $4.55 $ 4.69
+RESTRICTED STOCK: Under the 1996 Stock Plan, the Company has granted
+shares of restricted common stock, for no consideration, to its officers,
+one outside director and certain key employees. The 1996 Stock Plan
+restricted stock activity is summarized below:
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+Outstanding shares at beginning of period 95,080 91,440 78,800
+Granted 5,000 13,000 25,000
+Vested (12,960) (9,360) (9,360)
+Canceled (3,800) - (3,000)
+------ ------ ------
+Outstanding shares at end of period 83,320 95,080 91,440
+====== ====== ======
+Of the 83,320 shares of restricted stock outstanding at December 31,
+2000, 29,320 shares vest over a five-year period, while 54,000 shares vest
+at the end of a five-year period. Under certain conditions, vesting may be
+automatically accelerated. Upon issuance of the restricted stock, unearned
+compensation equivalent to the market value at the date of grant is charged
+to a separate component of shareholders' equity and subsequently amortized
+over the vesting period. Amortization expense of $277,000, $254,000 and
+$231,000 was recorded during 2000, 1999 and 1998, respectively.
+WARRANTS: On August 22, 1996, the Company sold to the underwriters of
+its initial public offering, for nominal consideration, a warrant to
+purchase from the Company up to 115,000 shares of common stock at an
+exercise price of $10.20 per share. The warrant is exercisable until
+August 20, 2001.
+On April 7, 2000, in connection with the sale of the Preferred Stock,
+the Company issued to its investment advisors, McFarland Dewey & Co.,
+warrants to purchase from the Company up to 10,000 shares of common stock
+at an exercise price of $9.00 per share. The warrants are exercisable
+through April 7, 2005.
+29
+30
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+12. STOCKHOLDER RIGHTS PLAN
+In December 1997, the Board of Directors adopted a Stockholder Rights
+Plan declaring a distribution of one right (the "Rights") for each
+outstanding share of the Company's common stock to shareholders of record
+at December 15, 1997. Initially, each of the Rights will entitle the
+registered holder to purchase from the Company one one-thousandth of a
+share of Series A Preferred Stock, $0.01 par value, at a price of $69 per
+one one-thousandth of a share. The Rights, however, will not become
+exercisable unless and until, among other things, any person or group of
+affiliated persons acquires beneficial ownership of 15 percent or more of
+the then outstanding shares of the Company's Common Stock. If a person, or
+group of persons, acquires 15 percent or more of the outstanding Common
+Stock of the Company (subject to certain conditions and exceptions more
+fully described in the Rights Agreement), each Right will entitle the
+holder (other than the person, or group of persons, who acquired 15 percent
+or more of the outstanding Common Stock) to purchase Preferred Stock of the
+Company having a market value equal to twice the exercise price of the
+Right. The Rights are redeemable, under certain circumstances, for $0.0001
+per Right and will expire, unless earlier redeemed, on December 2, 2007.
+On February 16, 1999, the Company amended its Stockholder Rights Plan
+to remove the provision in the plan that stipulated that the plan may be
+modified or redeemed only by those members of the Board of Directors who
+are defined as continuing directors.
+13. INCOME TAXES
+The components of the income tax provision are as follows:
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+(In thousands)
+Current:
+Federal $ (561) $ 88 $ 779
+State 43 18 126
+Foreign 194 12 131
+------- ------- -------
+(324) 118 1,036
+------- ------- -------
+Deferred:
+Federal (94) (37) (371)
+State (34) 18 (44)
+Foreign 4 3 --
+------- ------- -------
+(124) (16) (415)
+------- ------- -------
+Total income tax provision (benefit) $ (448) $ 102 $ 621
+======= ======= =======
+The Company had foreign income before taxes of $665,000, $65,000 and
+$435,000 in 2000, 1999 and 1998, respectively.
+Deferred income taxes arise from temporary differences between the tax
+basis of assets and liabilities and their reported amounts in the financial
+statements. The Company's gross deferred tax assets and liabilities were
+comprised of the following:
+December 31,
+(In thousands) 2000 1999
+---- ----
+Gross deferred tax assets:
+Liabilities and reserves $1,435 $1,320
+====== ======
+Gross deferred tax liabilities:
+Depreciation $ 576 $ 539
+====== ======
+30
+31
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. INCOME TAXES (CONTINUED)
+Differences between the U.S. statutory federal income tax rate and the
+Company's effective income tax rate are analyzed below:
+Year Ended December 31,
+2000 1999 1998
+---- ---- ----
+Federal statutory tax rate (34.0)% 34.0% 34.0%
+State income taxes, net of federal income taxes (0.3) 13.2 6.0
+Non-deductible purchase accounting adjustments 9.9 41.6 4.4
+Tax benefit from foreign sales corporation (3.1) -- (2.2)
+Tax benefit from tax credits (22.9) (60.0) (5.8)
+Foreign rate differential (3.5) (1.6) (0.9)
+Other (2.7) (3.2) (1.5)
+----- ---- ----
+Effective tax rate (56.6)% 24.0% 34.0%
+===== ==== ====
+14. DISCLOSURE REGARDING FAIR VALUE OF FINANCIAL INSTRUMENTS
+The carrying amount for cash and cash equivalents approximates fair
+value because of the short maturity of these instruments. The carrying
+amount of receivables, other current assets, other assets, accounts payable
+and accrued liabilities is a reasonable estimate of fair value because of
+the short nature of the transactions. The carrying value of long-term debt
+approximates the fair value based upon the variable rate on that debt.
+Off-balance sheet derivative financial instruments include
+interest-rate swaps. At December 31, 1999, interest-rate swaps, held for
+purposes other than trading, had a fair value settlement of $35,000, based
+on the underlying principal amount of $3,000,000. The Company sold its
+interest-rate swap during 2000.
+15. SIGNIFICANT TRANSACTIONS
+RESTRUCTURING: During the fourth quarter of 2000 and fourth quarter of
+1998, the Company recorded a restructuring charge of $189,000 and $300,000,
+respectively, for severance costs related to the downsizing and
+reorganization of its manufacturing facility in Wallingford, CT. Severance
+costs resulted from the reduction of 11 and 14 employees in 2000 and 1999,
+respectively. At December 31, 2000, approximately $105,000 of restructuring
+expenses remained accrued.
+PREFERRED STOCK SALE: On April 7, 2000 the Company sold 4,000 shares of
+7% Series B Cumulative Convertible Redeemable Preferred Stock (the
+"Preferred Stock") to Advance Capital Advisors, L.P. and its affiliate in
+consideration of $1,000 per share (the "Stated Value"), for a total of
+$4,000,000, less issuance costs. The Preferred Stock is convertible at any
+time by the holders at a conversion price of $9.00 per common share. In
+addition, the Company issued warrants pro-rata to the Preferred Stock
+holders to purchase an aggregate of 44,444 shares of the Company's common
+stock at an exercise price of $9.00 per common share. The warrants, valued
+at $175,000, are exercisable at any time until April 7, 2005, and will be
+accreted to preferred stock ratably over 60 months. The Preferred Stock is
+subject to mandatory conversion into shares of the Company's common stock
+when such stock has traded at $35 per share or more for a 30-day period
+ending on or after April 7, 2003, or for a 60-day period beginning on or
+after April 7, 2002. The Preferred Stock is redeemable at the option of the
+holders on April 7, 2005 at $1,000 per share plus any unpaid dividends. On
+or after April 7, 2007, the Company has the right to require (1) redemption
+of the Preferred Stock at $1,000 per share plus any unpaid dividends or (2)
+conversion of the Preferred Stock at $9.00 per common share. Upon a change
+of control (which the Company does not believe probable), holders have the
+right to redeem the Preferred Stock for 200% of the Stated Value plus any
+unpaid dividends. The holders of the Preferred Stock have certain voting
+rights and are entitled to receive a cumulative annual dividend of $70 per
+share, payable quarterly and have preference to any other dividends, if
+any, paid by the Company.
+31
+32
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+15. SIGNIFICANT TRANSACTIONS (CONTINUED)
+PREFERRED STOCK SALE (CONTINUED): Concurrent with the issuance of the
+Preferred Stock, the Company recorded a beneficial conversion charge. The
+beneficial conversion charge was calculated as the difference between the
+assigned fair value of the Preferred Stock and the fair value of the
+related common stock, as of April 7, 2000, into which the Preferred Stock
+was immediately convertible. Accordingly, a deemed preferred dividend of
+approximately $56,000 as of the issuance date has been recognized as a
+charge to retained earnings and net loss attributable to common
+shareholders, and as an increase to additional paid-in capital.
+GTECH LAWSUIT SETTLEMENT: On June 25, 1999, the Company commenced a
+lawsuit in the United States District Court for the District of Rhode
+Island against GTECH for misappropriation of trade secrets, breach of
+contract and related claims, seeking injunctive relief and compensatory and
+punitive damages. On July 15, 1999, GTECH and the Company signed a new
+five-year agreement under which the Company will be the exclusive
+manufacturer and supplier to GTECH of an impact printer for use in GTECH's
+Isys(R) online lottery terminal. As part of the agreement, GTECH agreed to
+pay the Company $1 million for past design efforts, development costs and
+manufacturing interruption costs and agreed to place a non-cancelable order
+for delivery of a minimum of approximately $8 million of printers in the
+year 2000. In connection with the execution of this agreement, the parties
+agreed to have all claims under the lawsuits dismissed and filed dismissal
+stipulations to terminate the federal and state lawsuits. As a result of
+the settlement, the Company reported $770,000 ($1 million cash settlement,
+less $230,000 of directly-related expenses) in other income during 1999.
+LOAN TO OFFICER: On February 23, 1999, with the Board of Directors'
+approval, the Company provided a $330,000 loan to an officer of the
+Company. The loan proceeds were used to purchase 104,000 shares of the
+Company's common stock on the open market during January and February 1999.
+The loan is payable on February 23, 2004, and is a full recourse obligation
+to the officer secured by 154,000 shares of the Company's common stock,
+which includes 50,000 shares of restricted stock. The loan bears interest
+at a rate equivalent to the Company's average borrowing rate under its
+current credit facility, and is payable annually. The principal amount of
+the loan is deducted from shareholders' equity.
+STOCK REPURCHASE PROGRAM: During November 1997, the Board of Directors
+approved the repurchase of up to 500,000 shares of the Company's common
+stock at a price of no more than $12 per share. During May, August and
+October 1998, the Board approved the repurchase of an additional 500,000,
+250,000 and 250,000 shares, respectively, bringing the total authorized to
+1.5 million shares. The Company acquired 70,800 shares of its common stock
+for $229,000 in 1999, 1,003,000 shares for $7,170,000 in 1998, and 200,000
+shares for $2,251,000 in 1997. Since the Company began the stock repurchase
+program in December 1997 through December 31, 1999, it has repurchased
+1,273,800 shares for $9,650,000 (an average cost of $7.58 per share). The
+Company did not repurchase any shares during 2000, and management does not
+expect to repurchase any additional shares in the foreseeable future.
+16. INTERNATIONAL OPERATIONS
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary, which had sales to its customers of
+$11,164,000, $700,000 and $4,990,000 in the year ended December 31, 2000,
+1999 and 1998, respectively. The Company had export sales to its foreign
+customers from the United States of approximately $5,156,000, $7,807,000
+and $3,396,00 in the year ended December 31, 2000, 1999 and 1998,
+respectively.
+32
+33
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+17. SUBSEQUENT EVENTS (unaudited)
+On February 15, 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of
+this strategic decision, the Company will consolidate all manufacturing and
+engineering into its existing Ithaca, NY facility and close its
+Wallingford, CT facility by the end of 2001. Production is planned to
+continue at the Wallingford facility until the end of 2001, with individual
+product lines scheduled to move over the course of 2001. The closing of the
+Wallingford facility is expected to result in the termination of employment
+of approximately 70 employees. The Company estimates that the non-recurring
+costs associated with the consolidation, including severance pay, employee
+benefits, moving expenses, non-cancelable lease payments, and other costs,
+will be approximately $3.0 to $3.5 million and will be recognized during
+2001.
+On February 27, 2001, the Company amended the Webster Credit Facility
+to (1) provide the Company with the ability to borrow up to $1,500,000 in
+excess of the amount permitted under the Webster Credit Facility's
+borrowing base formula ("Permitted Over-Formula Borrowing") and (2) revise
+certain financial covenants. The Permitted Over-Formula Borrowing is
+effective from March 1, 2001 through August 31, 2001.
+18. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
+The Company's quarterly results of operations for the years ended
+December 31, 2000, 1999 and 1998 (unaudited) are as follows:
+Quarter Ended
+-------------
+(In thousands, except per share amounts) March 27 June 26 September 23 December 31
+-------- ------- ------------ -----------
+2000:
+Net sales $ 11,238 $ 13,740 $ 14,604 $ 14,138
+Gross profit 3,013 3,665 3,867 3,597
+Net income (loss) (300) (186) 290 (148)
+Net income (loss) available to common
+Shareholders (300) (326) 200 (238)
+Net income (loss) per share:
+Basic and diluted (0.05) (0.06) 0.04 (0.04)
+March 27 June 26 September 25 December 31
+-------- ------- ------------ -----------
+1999:
+Net sales $ 9,201 $ 12,524 $ 13,020 $ 10,144
+Gross profit 2,428 3,238 3,335 2,753
+Net income (loss) (279) 146 837 (380)
+Net income (loss) per share:
+Basic and diluted (0.05) 0.03 0.15 (0.07)
+March 28 June 27 September 26 December 31
+-------- ------- ------------ -----------
+1998:
+Net sales $ 13,280 $ 12,500 $ 13,600 $ 12,859
+Gross profit 3,746 3,435 3,778 2,867
+Net income (loss) 634 231 533 (192)
+Net income (loss) per share:
+Basic and diluted 0.10 0.04 0.09 (0.03)
+33
+34
+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.
+Information contained in "Election of Directors" and "Section 16(a)
+Beneficial Ownership Reporting Compliance" of the Company's Proxy Statement (the
+"Proxy Statement") for its Annual Meeting of Shareholders which is scheduled to
+be held on May 23, 2001 is hereby incorporated herein by reference. Also, see
+information under "Executive Officers of Registrant" in Item 1.
+ITEM 11. EXECUTIVE COMPENSATION.
+The information contained in "Executive Compensation" other than the
+"Compensation Committee Report on Executive Compensation" of the Proxy Statement
+is hereby incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
+The information contained in "Security Ownership of Certain Beneficial
+Owners and Management" of the Proxy Statement is hereby incorporated herein by
+reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
+34
+35
+PART IV
+ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
+(A) THE FOLLOWING FINANCIAL STATEMENTS AND EXHIBITS ARE FILED AS PART
+OF THIS REPORT:
+(i) Financial statements
+See Item 8.
+(ii) Financial statement schedules
+All schedules are omitted since the required information is
+either (a) not present or not present in amounts sufficient to
+require submission of the schedule or (b) included in the
+financial statements or notes thereto.
+35
+36
+(iii) List of exhibits
+3.1(a) Certificate of Incorporation of the Company, filed with the Secretary of State of (2)
+Delaware on June 17, 1996.
+3.1(b) Certificate of Amendment of Certificate of Incorporation of the Company, filed with (4)
+the Secretary of State of Delaware on May 30, 1997.
+3.2 Amended and Restated By-laws of the Company. (6)
+4.1 Specimen Common Stock Certificate. (2)
+4.2 Amended and Restated Rights Agreement between TransAct and American Stock Transfer & (5)
+Trust Company dated February 16, 1998.
+10.1 Tax Sharing Agreement dated as of July 31, 1996 between Tridex and TransAct. (3)
+10.2 Purchase Agreement dated as of October 17, 1996 between ICL Pathway Limited, Ithaca (3)
+Peripherals Limited and TransAct. (Pursuant to Rule 24b-2 under the Securities
+Exchange Act of 1934, as amended (the "Exchange Act"), the Company has requested
+confidential treatment of portions of this exhibit deleted from the filed copy.)
+10.3(x) 1996 Stock Plan, effective July 30, 1996. (3)
+10.4(x) Non-Employee Directors' Stock Plan, effective August 22, 1996. (3)
+10.5 Sales and Marketing Agreement by and between the Company and Oki Europe Limited, (2)
+dated May 9, 1996. (Pursuant to Rule 477 under the Securities Act of 1993, as
+amended (the "Securities Act"), the Company has requested confidential treatment
+of portions of this exhibit deleted from the filed copy.)
+10.6 OEM Purchase Agreement by and between OKIDATA and Tridex, dated January 21, 1991. (2)
+(Pursuant to Rule 477 under the Securities Act, the Company has requested
+confidential treatment of portions of this exhibit deleted from the filed copy.)
+10.7 Strategic Agreement by and between OKIDATA and Tridex, dated May 9, 1996. (Pursuant (2)
+to Rule 477 under the Securities Act, the Company has requested confidential
+treatment of portions of this exhibit deleted from the filed copy.)
+10.8 Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, (2)
+1992.
+10.9(x) Employment Agreement, dated July 31, 1996, by and between the Company and Bart C. (2)
+Shuldman.
+10.10(x) Employment Agreement, dated July 31, 1996, by and between the Company and Richard L. (2)
+Cote.
+10.11(x) Severance Agreement by and between TransAct and Lucy H. Staley, dated September 4, (3)
+1996.
+10.12(x) Severance Agreement by and between TransAct and Michael S. Kumpf, dated September 4, (3)
+1996.
+10.13 Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, (4)
+dated December 2, 1996.
+10.14 Lease Agreement by and between Pyramid Construction Company and Magnetec, dated (4)
+July 30, 1997.
+10.15 Amendment to OEM Purchase Agreement by and between Okidata and Tridex, dated May 31, (4)
+1996. (Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested
+confidential treatment of portions of this exhibit deleted from the filed copy.)
+10.16(x) Severance Agreement by and between TransAct and Steven A. DeMartino, dated January (6)
+21, 1998.
+10.17 Loan Agreement by and between the Company and Bart C. Shuldman, dated February 23, (6)
+1999.
+36
+37
+10.18 Asset Transfer Agreement dated as of May 28, 1999 between Magnetec Corporation and (7)
+Tridex Corporation.
+10.19 OEM Purchase Agreement by and between GTECH Corporation, TransAct Technologies and (8)
+Magnetec Corporation commencing July 14, 1999. (Pursuant to Rule 24-b-2 under the
+Exchange Act, the Company has requested confidential treatment of portions of this
+exhibit deleted from the filed copy.)
+10.20 Amendment to OEM Purchase Agreement by and between Okidata and Tridex, dated August (9)
+28, 1999. (Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested
+confidential treatment of portions of this exhibit deleted from the filed copy.)
+10.21 Preferred Stock Purchase Agreement and Certificate of Designation dated as of March (10)
+20, 2000 between TransAct Technologies Incorporated and Advance Capital Partners,
+L.P. and affiliate
+10.22 Revolving Credit Agreement dated as of September 21, 2000 by and between TransAct (11)
+Technologies Incorporated and Webster Bank.
+10.23(x) Severance Agreement by and between TransAct and Catherine J. Dawson, dated April 21, (1)
+1999.
+10.24(x) Severance Agreement by and between TransAct and Mark Goebel, dated July 31, 1996. (1)
+10.25(x) Severance Agreement by and between TransAct and James B. Stetson, dated January 24, (1)
+2001.
+10.26 Amendment to Revolving Credit Agreement dated February 27, 2001 by and between (1)
+TransAct Technologies Incorporated and Webster Bank.
+11.1 Computation of earnings per share. (1)
+21.1 Subsidiaries of the Company. (1)
+23.1 Consent of PricewaterhouseCoopers LLP. (1)
+(1) These exhibits are filed herewith.
+(2) These exhibits, which were previously filed with the
+Company's Registration Statement on Form S-1 (No.
+333-06895), are incorporated by reference.
+(3) These exhibits, which were previously filed with the
+Company's Quarterly Report on Form 10-Q for the
+period ended September 30, 1996, are incorporated by
+reference.
+(4) These exhibits, which were previously filed with the
+Company's Annual Report on Form 10-K for the year
+ended December 31, 1997, are incorporated by
+reference.
+(5) This exhibit, which was previously filed with the
+Company's Current Report on Form 8-K filed February
+18, 1999, is incorporated by reference.
+(6) These exhibits, which were previously filed with the
+Company's Annual Report on Form 10-K for the year
+ended December 31, 1998, are incorporated by
+reference.
+(7) These exhibits, which were previously filed with the
+Company's Quarterly Report on Form 10-Q for the
+period ended June 26, 1999, are incorporated by
+reference.
+(8) This exhibit, which was previously filed with the
+Company's Quarterly Report on Form 10-Q for the
+period ended September 25, 1999, is incorporated by
+reference.
+(9) These exhibits, which were previously filed with the
+Company's Annual Report on Form 10-K for the year
+ended December 31, 1999, are incorporated by
+reference.
+(10) These exhibits, which were previously filed with the
+Company's Quarterly Report on Form 10-Q for the
+period ended March 25, 2000, are incorporated by
+reference.
+(11) This exhibit, which was previously filed with the
+Company's Current Report on Form 8-K filed October
+11, 2000, is incorporated by reference.
+37
+38
+(x) Management contract or compensatory plan or
+arrangement required to be filed pursuant to Item
+14(c).
+(B) REPORTS ON FORM 8-K.
+A Form 8-K was filed on October 11, 2000 to report under Item
+5 a new revolving credit agreement with Webster Bank.
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized.
+TRANSACT TECHNOLOGIES INCORPORATED
+By: /s/ Bart C. Shuldman
+---------------------------------------
+Bart C. Shuldman
+Chairman of the Board, President and
+Chief Executive Officer
+Date: March 28, 2001
+Pursuant to the requirements of the Securities 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/ Bart C. Shuldman Chairman of the Board, President and March 28, 2001
+------------------------------------ Chief Executive Officer
+Bart C. Shuldman (Principal Executive Officer)
+/s/ Richard L. Cote Executive Vice President, Chief Financial March 28, 2001
+------------------------------------ Officer, Treasurer, Secretary and Director
+Richard L. Cote (Principal Financial Officer)
+/s/ Steven A. DeMartino Vice President and Corporate Controller March 28, 2001
+------------------------------------ (Principal Accounting Officer)
+Steven A. DeMartino
+/s/ Charles A. Dill Director March 28, 2001
+------------------------------------
+Charles A. Dill
+/s/ Jeffrey T. Leeds Director March 28, 2001
+------------------------------------
+Jeffrey T. Leeds
+/s/ Thomas R. Schwarz Director March 28, 2001
+------------------------------------
+Thomas R. Schwarz
+/s/ Graham Y. Tanaka Director March 28, 2001
+------------------------------------
+Graham Y. Tanaka
+38
+39
+EXHIBIT LIST
+The following exhibits are filed herewith.
+Exhibit
+10.23(x) Severance Agreement by and between TransAct and
+Catherine J. Dawson, dated April 21, 1999.
+10.24(x) Severance Agreement by and between TransAct and Mark
+Goebel, dated July 23, 1996.
+10.25(x) Severance Agreement by and between TransAct and James
+B. Stetson, dated January 24, 2001
+10.26 Amendment to Revolving Credit Agreement dated
+February 27, 2001 by and between TransAct
+Technologies Incorporated and Webster Bank.
+11.1 Computation of earnings per share.
+21.1 Subsidiaries of the Company.
+23.1 Consent of PricewaterhouseCoopers LLP.
+39
\ No newline at end of file
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new file mode 100644
index 0000000000000000000000000000000000000000..a11087bf60ab69d7bcc5b1516a868f9781807d71
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@@ -0,0 +1,2 @@
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diff --git a/raw/filings/0001017303/2000/0000914039-01-000108/item1.txt b/raw/filings/0001017303/2000/0000914039-01-000108/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..bcc253cb34d553a42e17c6251157cbb98893196d
--- /dev/null
+++ b/raw/filings/0001017303/2000/0000914039-01-000108/item1.txt
@@ -0,0 +1,249 @@
+ITEM 1. BUSINESS.
+(A) GENERAL DEVELOPMENT OF BUSINESS
+TransAct began operating as a stand-alone business in August 1996 to
+operate the printer business that was formerly conducted by certain subsidiaries
+of Tridex Corporation. TransAct completed an initial public offering on August
+22, 1996. In April 1999, the Company formed and incorporated a new wholly-owned
+subsidiary, TransAct.Com. Through TransAct.com, the Company plans to explore
+leveraging its inkjet printing technology into the expanding online, e-commerce
+market.
+On February 15, 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company will consolidate all manufacturing and
+engineering into its existing Ithaca, NY facility and close its Wallingford, CT
+facility by the end of 2001. Production is planned to continue at the
+Wallingford facility until the end of 2001, with individual product lines
+scheduled to move over the course of 2001. The closing of the Wallingford
+facility is expected to result in the termination of employment of approximately
+70 employees.
+(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
+TransAct has assessed its operating and reportable segments and
+determined that it operates in one reportable segment, the design, development,
+manufacture and marketing of transaction-based printers and
+printer-related products.
+(C) NARRATIVE DESCRIPTION OF BUSINESS
+(i) PRINCIPAL PRODUCTS AND SERVICES
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing dot matrix, thermal and inkjet printing
+technology for applications requiring up to 60 character columns in each of its
+five vertical markets: POS, gaming and lottery, kiosk, financial services and
+Internet. The Company's printers are configurable, which offer customers the
+ability to choose from a variety of features and functions. Options typically
+include PC board configuration, paper cutting devices, paper handling capacities
+and number of print stations. In addition to its configurable printers, TransAct
+manufactures custom printers for certain OEM customers. In collaboration with
+these customers, the Company provides engineering and manufacturing expertise
+for the design and development of specialized printers.
+2
+3
+The Company also manufactures and sells document transport mechanisms
+which deliver the finished printed output to the consumer in unattended
+applications, such as ATMs and kiosks. In addition, the Company offers inkjet
+cartridges, printer ribbons, paper and replacement parts for all of its
+products.
+The Company provides customers with telephone sales and technical
+support, a personal account representative for orders, shipping and general
+information and expedited shipping for orders of its configurable and custom
+products. Technical and sales support personnel receive training in all of the
+Company's products and services manufactured at their facility. The Company's
+printers generally carry a one- or two-year limited warranty; extended
+warranties are available for purchase on selected printers to supplement the
+original warranty.
+(ii) STATUS OF PRODUCT REQUIRING MATERIAL INVESTMENT
+None.
+(iii) SOURCES AND AVAILABILITY OF RAW MATERIALS
+The principal materials used in manufacturing are copper wire, magnetic
+metals, injection molded plastic parts, formed metal parts and electronic
+components. Although the Company could experience temporary disruption if
+certain suppliers ceased doing business with the Company, the Company's
+requirements generally are available from a number of sources, except as
+described below.
+Okidata, Division of Oki America, Inc. ("Okidata") is the sole supplier
+for a printer component kit consisting of a printhead, control board and
+carriage (the "Oki Kit"), which is used in all of the Company's Ithaca(R) brand
+impact printers. The loss of the supply of Oki Kits would have a material
+adverse effect on the Company. TransAct has a supply agreement with Okidata to
+provide Oki Kits until May 2001 at a fixed price through May 2001. The Company
+and Okidata are currently negotiating for future supplies and pricing.
+Hewlett-Packard Company ("HP") is the sole supplier of inkjet cartridges which
+are used in all of the Company's inkjet printers. The loss of the supply of HP
+inkjet cartridges would have a material adverse effect on the sale of the
+Company's inkjet printers. TransAct has a supply agreement with HP to purchase
+inkjet cartridges until June 1, 2001 at a fixed price. The Company and HP are
+currently negotiating for future supplies and pricing. TransAct believes its
+relations with Okidata and HP are good and has received no indication that
+either of the supply agreements will not be renewed beyond the respective
+expiration dates of the current contracts. TransAct cannot be certain, however,
+that either of the supply agreements will be renewed, or if renewed, that the
+terms will be as favorable as those under the current contracts.
+(iv) PATENTS AND PROPRIETARY INFORMATION
+The Company owns several patents, one of which it considers material.
+That patent covers an automated paper cut-off device, which is a feature offered
+on certain of the Company's POS printers. The Company also has sought patent and
+other protection for certain design features of its new family of printers
+utilizing inkjet printing technology. The Company regards certain manufacturing
+processes and designs to be proprietary and attempts to protect them through
+employee and third-party nondisclosure agreements and similar means. It may be
+possible for unauthorized third parties to copy certain portions of the
+Company's products or to reverse engineer or otherwise obtain and use, to the
+Company's detriment, information that the Company regards as proprietary.
+Moreover, the laws of some foreign countries do not afford the same protection
+to the Company's proprietary rights as do United States laws. There can be no
+assurance that legal protections relied upon by the Company to protect its
+proprietary position will be adequate or that the Company's competitors will not
+independently develop technologies that are substantially equivalent or superior
+to the Company's technologies.
+3
+4
+(v), (vi) SEASONALITY AND PRACTICES RELATING TO WORKING CAPITAL ITEMS
+Retailers typically reduce purchases of new POS equipment in the fourth quarter,
+due to the increased volume of consumer transactions in that period, and the
+Company's sales of printers in the POS market historically have increased in the
+third quarter and decreased in the fourth quarter. However, the Company has not
+experienced material seasonality in its total net sales, due to offsetting sales
+in other markets.
+(vii) CERTAIN CUSTOMERS
+The Company has an OEM purchase agreement with GTECH Corporation
+("GTECH") to provide on-line lottery printers and spare parts, at prices to be
+negotiated, through July 2004. Firm purchase orders for printers may be placed
+annually by GTECH. For 2001, the Company has received an order for approximately
+$14,000,000 for delivery between May and December 2001. The Company also sells
+printers to GTECH for use in lottery terminals at grocery check-out lanes
+("in-lane lottery printers"). Sales to GTECH accounted for approximately 22.1%
+and 31.8% of net sales in 2000 and 1998, respectively. The Company made no
+on-line lottery printer shipments to GTECH during 1999. The Company also
+provides printers to ICL Pathway for use in the British Post Office. During
+2000, sales to ICL Pathway accounted for approximately 20.2% of net sales. The
+Company completed shipping printers to ICL Pathway for use in the British Post
+Office in February 2001 and no further shipments are expected. The Company had
+no sales to any one customer greater than 10% of net sales in 1999.
+(viii) BACKLOG
+The Company's backlog of firm orders was approximately $18,100,000 as
+of March 16, 2001 and $19,900,000 as of March 17, 2000. Based on customers'
+current delivery requirements, TransAct expects to fill its current backlog of
+approximately $18,100,000 during 2001.
+(ix) MATERIAL PORTION OF BUSINESS SUBJECT TO RENEGOTIATION OF PROFITS
+None.
+(x) COMPETITION
+The market for transaction-based printers is extremely competitive, and
+the Company expects such competition to intensify in the future. The Company
+competes with a number of companies, many of which have greater financial,
+technical and marketing resources than the Company. TransAct believes its
+ability to compete successfully depends on a number of factors both within and
+outside its control, including durability, reliability, quality, design
+capability, product customization, price, customer support, success in
+developing new products, manufacturing expertise and capacity, supply of
+component parts and materials, strategic relationships with suppliers, the
+timing of new product introductions by the Company and its competitors, general
+market and economic conditions and, in some cases, the uniqueness of its
+products.
+4
+5
+Three of the Company's competitors, Epson America, Inc., Axiohm
+Transaction Solutions and Star Micronics America, Inc. together control
+approximately 70% of the United States market for POS printers, a market in
+which the Company's strategy calls for increased market share. Another principal
+competitor in the POS market is Citizen -- CBM America Corporation. Certain
+competitors of the Company have greater financial resources, lower costs
+attributable to higher volume production and off-shore manufacturing locations,
+and offer lower prices than the Company from time to time.
+In the gaming and lottery, financial services and kiosk markets, no
+single supplier holds a dominant position. Certain of the Company's products
+sold for gaming and lottery, kiosk and financial service applications compete
+based upon the Company's ability to provide highly specialized products, custom
+engineering and ongoing technical support.
+The Company's strategy for competing in its markets is to continue to
+develop new products and product line extensions, to increase its geographic
+market penetration, and to take advantage of strategic relationships. The
+Company expects to particularly focus on gaining market acceptance for its new
+family of printers utilizing Hewlett Packard's inkjet printing technology.
+Although the Company believes that its products, operations and relationships
+provide a competitive foundation, there can be no assurance that the Company
+will compete successfully in the future.
+(xi) RESEARCH AND DEVELOPMENT ACTIVITIES
+The Company spent approximately $3,481,000, $3,235,000 and $3,642,000
+in 2000, 1999 and 1998, respectively, on engineering, design and product
+development efforts in connection with specialized engineering and design to
+introduce new products and to customize existing products. During 2001, the
+Company expects to focus the majority of its research and development activities
+on the development of (1) a family of printers for the POS market utilizing
+Hewlett Packard's inkjet printing technology and (2) new voucher-issuing
+printers for use in the casino market.
+(xii) ENVIRONMENT
+The Company is not aware of any material noncompliance with federal,
+state and local provisions which have been enacted or adopted regulating the
+discharge of materials into the environment, or otherwise relating to the
+protection of the environment.
+(xiii) EMPLOYEES
+As of March 16, 2001, TransAct Technologies and its subsidiaries
+employed 205 persons, of whom 190 were full-time and 15 were temporary
+employees. None of the Company's employees is unionized and the Company
+considers its relationships with its employees to be good.
+(D) FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS AND
+EXPORT SALES
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary located in the United Kingdom, which had sales
+to its customers of $11,164,000, $700,000 and $4,990,000 in 2000, 1999 and 1998,
+respectively. The Company had export sales to its customers from its domestic
+operations of approximately $5,156,000, $7,807,000, and $3,396,000 in 2000, 1999
+and 1998, respectively.
+5
+6
+(E) EXECUTIVE OFFICERS OF THE REGISTRANT AS OF DECEMBER 31, 2000
+Name Age Position
+---- --- --------
+Thomas R. Schwarz 64 Chairman of the Board
+Bart C. Shuldman 43 President, Chief Executive Officer and Director
+Richard L. Cote 59 Executive Vice President, Chief Financial Officer, Treasurer,
+Secretary and Director
+Mark B. Goebel 46 Senior Vice President - General Manger (Wallingford, CT facility)
+Michael S. Kumpf 51 Senior Vice President - Engineering
+Lucy H. Staley 50 Senior Vice President - General Manager (Ithaca, NY facility)
+James B. Stetson 43 Senior Vice President - Sales
+Catherine J. Dawson 33 Vice President - Marketing
+Steven A. DeMartino 31 Vice President and Corporate Controller
+THOMAS R. SCHWARZ, Chairman of the Board, has been a Director of the
+Company since its formation in June 1996. Mr. Schwarz was Chairman and Chief
+Executive Officer of Grossman's Inc., a retailer of building materials, from
+1990 until his retirement in 1994. Mr. Schwarz is a Director of Tridex,
+Foilmark, Inc., Tanaka Growth Fund, Lebhar-Friedman Publishing Company and
+Yorkshire Global Restaurants. In February 2001, Mr. Schwarz resigned from his
+position as Chairman of the Board, but remains a director of the Company.
+BART C. SHULDMAN has been Chief Executive Officer, President and a
+Director of the Company since its formation in June 1996. Previously, Mr.
+Shuldman served as President of Magnetec and later the combined operations of
+Magnetec and Ithaca from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+RICHARD L. COTE has been Executive Vice President, Chief Financial
+Officer, Treasurer, Secretary and a Director of the Company since its formation
+in June 1996. Prior thereto, he served as Senior Vice President and Chief
+Financial Officer of Tridex from September 1993 to June 1996.
+MARK B. GOEBEL, Senior Vice President - General Manager (Wallingford,
+CT facility), joined TransAct in November 1993 as Engineering Manager. From
+April 1994, Mr. Goebel served as Vice President-Engineering until he was
+appointed Senior Vice President of Engineering of Wallingford, and an officer of
+the Company, in January 2000. In November 2000, Mr. Goebel was named Senior Vice
+President - General Manager of the Wallingford, CT facility.
+MICHAEL S. KUMPF, Senior Vice President-Engineering since June 1996,
+served as Vice President of Engineering of Ithaca from 1991 until June 1996.
+LUCY H. STALEY, Senior Vice President-General Manager (Ithaca, NY
+facility) since June 1996, served as a Vice President of Ithaca from 1984 until
+June 1996.
+JAMES B. STETSON was appointed Senior Vice President of Worldwide Sales
+of the Company in February 2000, and served as Vice President of Sales, Latin
+America from October 1997 to February 2000. Prior to joining TransAct, Mr.
+Stetson served as Vice President and Sales Manager at Gekay Sales and Service
+Company from 1995 until October 1997.
+6
+7
+CATHERINE J. DAWSON joined TransAct in June 1998 as Vice President of
+Marketing, and was appointed an officer of the Company on January 1, 2000. Prior
+to joining TransAct, Ms. Dawson served as Product Marketing Manager for the
+visual systems division of 3M Corporation from March 1996 to March 1998, and as
+a Senior Marketing Analyst from June 1994 to March 1996.
+STEVEN A. DEMARTINO joined TransAct as Corporate Controller in August
+1996 and was appointed an officer of the Company in January 1998 and Vice
+President in December 1999. Prior to joining TransAct, Mr. DeMartino was a
+self-employed financial consultant from May 1996 to August 1996. Prior thereto,
+Mr. DeMartino, served as Controller of NER/Copart, Inc. from September 1994 to
+May 1996.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2000/0000914039-01-000108/item13.txt b/raw/filings/0001017303/2000/0000914039-01-000108/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..08d40b2c90ec5d5de8e66455a855fd2f24a13860
--- /dev/null
+++ b/raw/filings/0001017303/2000/0000914039-01-000108/item13.txt
@@ -0,0 +1,5 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
+34
+35
\ No newline at end of file
diff --git a/raw/filings/0001017303/2000/0000914039-01-000108/item9a.txt b/raw/filings/0001017303/2000/0000914039-01-000108/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2000/0000914039-01-000108/rp_note.txt b/raw/filings/0001017303/2000/0000914039-01-000108/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2000/0000914039-01-000108/rpt_disclosure.txt b/raw/filings/0001017303/2000/0000914039-01-000108/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f39adb1bd0d74e9c92a9150ab6cb3c14cd286fd5
--- /dev/null
+++ b/raw/filings/0001017303/2000/0000914039-01-000108/rpt_disclosure.txt
@@ -0,0 +1,15 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+On February 23, 1999, the Company loaned Bart C. Shuldman, the Chairman,
+Chief Executive Officer and President of the Company, $330,000 to fund his
+purchase in the market of 104,000 shares of the Company's common stock. Mr.
+Shuldman pledged 93,423 of the shares purchased with the loan proceeds and
+50,000 shares of restricted common stock as security for the promissory note.
+The principal and any unpaid interest under the note is due in a balloon payment
+five years after the date of the loan. The interest rate on the note is
+calculated based on the Company's average variable lending rate under its
+primary credit facility. Interest payments through December 31, 2001 have been
+added to principal, which was increased to $409,340 at that date. During 2002,
+interest will be compounded and added to principal monthly and be payable at
+maturity. Thereafter, it will accrue annually and be payable at maturity. At
+March 31, 2002, the aggregate amount outstanding under the loan was $415,253.
+6
\ No newline at end of file
diff --git a/raw/filings/0001017303/2001/0000914039-02-000121/filing.txt b/raw/filings/0001017303/2001/0000914039-02-000121/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cd48a8753005fbed58701d66d13a91644bd10489
--- /dev/null
+++ b/raw/filings/0001017303/2001/0000914039-02-000121/filing.txt
@@ -0,0 +1,2245 @@
+10-K
+1
+y58940e10-k.txt
+FORM 10-K
+SECURITIES AND EXCHANGE COMMISSION
+Washington, DC. 20549
+------------------------------
+FORM 10-K
+(Mark One)
+|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934
+For the fiscal year ended December 31, 2001
+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: 0-21121
+TRANSACT TECHNOLOGIES INCORPORATED
+--------------------------------------------------------------------------------
+(Exact name of registrant as specified in its charter)
+DELAWARE 06-1456680
+------------------------------------------------ ------------------------
+(State or other jurisdiction of incorporation or (I.R.S. Employer
+organization) Identification No.)
+7 LASER LANE, WALLINGFORD, CT 06492
+------------------------------------------------ ------------------------
+(Address of principal executive offices) (Zip Code)
+Registrant's telephone number, including area code 203-269-1198
+------------------------
+Securities registered pursuant to Section 12 (b) of the Act:
+NONE
+--------------------------------------------------------------------------------
+Securities registered pursuant to Section 12 (g) of the Act:
+COMMON STOCK, $0.01 PAR VALUE
+--------------------------------------------------------------------------------
+(Title of class)
+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 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 other amendment
+to this Form 10-K. |X|
+As of March 15, 2002 the aggregate market value of the registrant's issued and
+outstanding voting stock held by non-affiliates of the registrant was
+$24,600,000.
+As of March 15, 2002 the registrant had outstanding 5,703,670 shares of common
+stock, $0.01 par value.
+DOCUMENTS INCORPORATED BY REFERENCE
+Proxy Statement for the Annual Meeting of Shareholders to be held on May 17,
+2002 - Part III.
+PART I
+GENERAL
+TransAct Technologies Incorporated ("TransAct" or the "Company") designs,
+develops, manufactures and markets transaction-based printers under the
+Ithaca(R) and Magnetec(R) brand names. In addition, the Company markets related
+consumables, spare parts and service. The Company's printers are used worldwide
+to provide transaction records such as receipts, tickets, coupons, register
+journals and other documents. The Company focuses on the following vertical
+markets: point-of-sale ("POS"), gaming and lottery, financial services and
+kiosk. The Company sells its products directly to end users, original equipment
+manufacturers ("OEMs"), value-added resellers ("VARs") and selected
+distributors, primarily in the United States, Canada, Europe and Latin America.
+TransAct has one primary operating facility located in Ithaca, New York, five
+sales offices located in the United States, and one sales office and service
+depot in the United Kingdom. The Company also has a manufacturing facility in
+Wallingford, CT which it expects to close in May 2002 (see "General Development
+of Business" below).
+ITEM 1. BUSINESS.
+(A) GENERAL DEVELOPMENT OF BUSINESS
+TransAct began operating as a stand-alone business in August 1996 to
+operate the printer business that was formerly conducted by certain subsidiaries
+of Tridex Corporation. TransAct completed an initial public offering on August
+22, 1996.
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company undertook a plan to consolidate all
+manufacturing and engineering into its existing Ithaca, NY facility and close
+its Wallingford, CT facility (the "Consolidation"). The Company's technology
+shift to inkjet and thermal printing from dot matrix impact printing has
+dramatically reduced the labor content in printers, and therefore, lowers the
+required production capacity. As of December 31, 2001, substantially all
+Wallingford product lines were successfully transferred to Ithaca, NY. The
+Company expects to maintain one small component production line in Wallingford
+until May 2002, after which the manufacturing facility will be closed. The
+closing of the Wallingford facility is expected to result in the termination of
+employment of approximately 70 production, administrative and management
+employees.
+(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
+TransAct has assessed its operating and reportable segments and has
+determined that it operates in one reportable segment, the design, development,
+manufacture and marketing of transaction-based printers and printer-related
+products.
+(C) NARRATIVE DESCRIPTION OF BUSINESS
+(i) PRINCIPAL PRODUCTS AND SERVICES
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing dot matrix, thermal and inkjet printing
+technology for applications requiring up to 60 character columns in each of the
+following vertical markets: POS, gaming and lottery, financial services and
+kiosk. The Company's printers are configurable and offer customers the ability
+to choose from a variety of features and functions. Options typically include PC
+board configuration, paper cutting devices, paper handling capacities and number
+of print stations. In addition to its configurable printers, TransAct
+manufactures custom printers for certain OEM customers. In collaboration with
+these customers, the Company provides engineering and manufacturing expertise
+for the design and development of specialized printers. In addition, the Company
+offers inkjet cartridges, printer ribbons, paper and replacement parts for all
+of its products.
+The Company provides customers with telephone sales and technical support,
+a personal account representative for orders, shipping and general information
+and expedited shipping for orders of its configurable and custom products.
+Technical and sales support personnel receive training in all of the Company's
+products and services manufactured at their facility. The Company's printers
+generally carry a one- or two-year limited warranty; extended warranties are
+available for purchase on selected printers to supplement the original warranty.
+Service contracts for the repair and maintenance of printers beyond the original
+warranty period are also available for purchase.
+(ii) STATUS OF PRODUCT REQUIRING MATERIAL INVESTMENT
+None.
+2
+(iii) SOURCES AND AVAILABILITY OF RAW MATERIALS
+The principal materials used in manufacturing are copper wire, magnetic
+metals, injection molded plastic parts, formed metal parts and electronic
+components. Although the Company could experience temporary disruption if
+certain suppliers ceased doing business with the Company, the Company's
+requirements generally are available from a number of sources, except as
+described below.
+Okidata Americas, Inc. ("Okidata"), is the sole supplier for a printer
+component kit consisting of a printhead, control board and carriage (the "Oki
+Kit"), which is used in all of the Company's Ithaca(R) brand impact printers.
+The loss of the supply of Oki Kits would have a material adverse effect on the
+Company. TransAct has a supply agreement with Okidata to provide Oki Kits until
+June 2003 at fixed prices through at least March 31, 2002. The Company and
+Okidata are currently negotiating for future pricing. Additionally,
+Hewlett-Packard Company ("HP") is the sole supplier of inkjet cartridges which
+are used in all of the Company's inkjet printers. The loss of the supply of HP
+inkjet cartridges would have a material adverse effect on the sale of the
+Company's inkjet printers. TransAct has a supply agreement with HP to purchase
+inkjet cartridges until June 1, 2002 at a fixed price. TransAct believes its
+relations with Okidata and HP are good and has received no indication that
+either of the supply agreements will not be renewed beyond the respective
+expiration dates of the current contracts. TransAct cannot be certain, however,
+that either of the supply agreements will be renewed, or if renewed, that the
+terms will be as favorable as those under the current contracts.
+(iv) PATENTS AND PROPRIETARY INFORMATION
+The Company owns several patents, three of which it considers material.
+The earliest expiration date of these patents is in 2008. The first patent
+covers an automated paper cut-off device, which is a feature offered on certain
+of the Company's POS printers; the second is a patent that relates to an
+automatic paper loader for a printer; and the third is a patent that covers a
+method for converting a full color image into a two-color image, plus a
+background color. The Company also has sought patent protection for certain
+design features of 1) printers using inkjet technology, 2) POS printers using
+thermal technology, and 3) thermal printers for use in casino slot machines. The
+Company regards certain manufacturing processes and designs to be proprietary
+and attempts to protect them through employee and third-party nondisclosure
+agreements and similar means. It may be possible for unauthorized third parties
+to copy certain portions of the Company's products or to reverse engineer or
+otherwise obtain and use, to the Company's detriment, information that the
+Company regards as proprietary. Moreover, the laws of some foreign countries do
+not afford the same protection to the Company's proprietary rights as do United
+States laws. There can be no assurance that legal protections relied upon by the
+Company to protect its proprietary position will be adequate or that the
+Company's competitors will not independently develop technologies that are
+substantially equivalent or superior to the Company's technologies.
+(v), (vi) SEASONALITY AND PRACTICES RELATING TO WORKING CAPITAL ITEMS
+Retailers typically reduce purchases of new POS equipment in the fourth
+quarter, due to the increased volume of consumer transactions in that period,
+and the Company's sales of printers in the POS market historically have
+increased in the third quarter and decreased in the fourth quarter. However, the
+Company has not experienced material seasonality in its total net sales, due to
+offsetting sales in other markets.
+(vii) CERTAIN CUSTOMERS
+The Company has an OEM purchase agreement with GTECH Corporation ("GTECH")
+to provide on-line lottery printers and spare parts, at prices to be negotiated,
+through December 31, 2004. Firm purchase orders for printers may be placed
+annually by GTECH. The Company has received orders for approximately $9,800,000
+worth of printers for delivery between January 2002 and February 2003. The
+Company also sells printers to GTECH for use in lottery terminals at grocery
+check-out lanes ("in-lane lottery printers"). Sales to GTECH accounted for
+approximately 33.0% and 22.1% of net sales in 2001 and 2000, respectively. The
+Company made no on-line lottery printer shipments and approximately $1,100,000
+of in-lane lottery printer shipments to GTECH during 1999. The Company also
+provides printers to ICL Pathway for use in the British Post Office. During
+2000, sales to ICL Pathway accounted for approximately 20.2% of net sales. The
+Company completed shipping printers to ICL Pathway for use in the British Post
+Office in February 2001 and no further shipments are expected. The Company had
+no sales to any one customer greater than 10% of net sales in 1999.
+(viii) BACKLOG
+The Company's backlog of firm orders was approximately $8,700,000 as of
+March 25, 2002 and $18,100,000 as of March 16, 2001, including approximately
+$6,600,000 and $7,800,000 to GTECH, respectively. Based on customers' current
+delivery requirements, TransAct expects to fill approximately $8,200,000 of its
+current backlog during 2002 and approximately $500,000 during 2003.
+3
+(ix) MATERIAL PORTION OF BUSINESS SUBJECT TO RENEGOTIATION OF PROFITS
+None.
+(x) COMPETITION
+The market for transaction-based printers is extremely competitive, and
+the Company expects such competition to intensify in the future. The Company
+competes with a number of companies, many of which have greater financial,
+technical and marketing resources than the Company. TransAct believes its
+ability to compete successfully depends on a number of factors both within and
+outside its control, including durability, reliability, quality, design
+capability, product customization, price, customer support, success in
+developing new products, manufacturing expertise and capacity, supply of
+component parts and materials, strategic relationships with suppliers, the
+timing of new product introductions by the Company and its competitors, general
+market and economic conditions and, in some cases, the uniqueness of its
+products.
+Three of the Company's competitors, Epson America, Inc., Axiohm
+Transaction Solutions and Star Micronics America, Inc. together control
+approximately 70% of the United States market for POS printers, a market in
+which the Company's strategy calls for increased market share. Another principal
+competitor in the POS market is Citizen -- CBM America Corporation. Certain
+competitors of the Company have greater financial resources, lower costs
+attributable to higher volume production and off-shore manufacturing locations,
+and offer lower prices than the Company from time to time.
+In the gaming and lottery, financial services and kiosk markets, no single
+supplier holds a dominant position. Certain of the Company's products sold for
+gaming and lottery, kiosk and financial services applications compete based upon
+the Company's ability to provide highly specialized products, custom engineering
+and ongoing technical support.
+The Company's strategy for competing in its markets is to continue to
+develop new products and product line extensions, to increase its geographic
+market penetration, and to take advantage of strategic relationships. The
+Company expects to particularly focus on (1) gaining market acceptance for its
+new family of printers utilizing Hewlett Packard's inkjet printing technology,
+(2) promoting its new line of slot machine printers into the gaming market and
+(3) expanding its consumables, spares and service business. Although the Company
+believes that its products, operations and relationships provide a competitive
+foundation, there can be no assurance that the Company will compete successfully
+in the future.
+(xi) RESEARCH AND DEVELOPMENT ACTIVITIES
+The Company spent approximately $3,070,000, $3,481,000 and $3,235,000 in
+2001, 2000 and 1999, respectively, on engineering, design and product
+development efforts in connection with specialized engineering and design to
+introduce new products and to customize existing products. During 2002, the
+Company expects to focus the majority of its research and development activities
+on the continuing development and enhancement of (1) its family of printers for
+the POS market utilizing inkjet and thermal printing technology and (2) its
+ticket-issuing printers for use in the casino market.
+(xii) ENVIRONMENT
+The Company is not aware of any material noncompliance with federal, state
+and local provisions that have been enacted or adopted regulating the discharge
+of materials into the environment, or otherwise relating to the protection of
+the environment.
+(xiii) EMPLOYEES
+As of March 15, 2002, TransAct Technologies and its subsidiaries employed
+176 persons, of whom 141 were full-time and 35 were temporary employees. None of
+the Company's employees is unionized and the Company considers its relationships
+with its employees to be good.
+(D) FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS AND EXPORT
+SALES
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary located in the United Kingdom, which had sales
+to its customers of $1,791,000, $11,164,000 (primarily to ICL Pathway for use in
+the British Post Office) and $700,000 in 2001, 2000 and 1999, respectively. The
+Company had export sales to its customers from its domestic operations of
+approximately $6,131,000, $5,156,000 and $7,807,000 in 2001, 2000 and 1999,
+respectively.
+4
+(E) EXECUTIVE OFFICERS OF THE REGISTRANT AS OF DECEMBER 31, 2001
+Name Age Position
+------------------- --- --------------------------------------------------
+Bart C. Shuldman 44 Chairman of the Board, President and Chief
+Executive Officer
+Richard L. Cote 60 Executive Vice President, Chief Financial Officer,
+Treasurer, Secretary and Director
+James B. Stetson 44 Executive Vice President - Sales and Marketing
+Steven A. DeMartino 32 Senior Vice President - Finance and Information
+Technology
+Mark B. Goebel 47 Senior Vice President - General Manager
+(Wallingford, CT facility)
+Michael S. Kumpf 52 Senior Vice President - Engineering
+Lucy H. Staley 51 Senior Vice President - General Manager (Ithaca,
+NY facility)
+BART C. SHULDMAN has been Chief Executive Officer, President and a
+Director of the Company since its formation in June 1996. Previously, Mr.
+Shuldman served as President of Magnetec and later the combined operations of
+Magnetec and Ithaca from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+RICHARD L. COTE has been Executive Vice President, Chief Financial
+Officer, Treasurer, Secretary and a Director of the Company since its formation
+in June 1996. Prior thereto, he served as Senior Vice President and Chief
+Financial Officer of Tridex from September 1993 to June 1996.
+JAMES B. STETSON was appointed Executive Vice President, Sales and
+Marketing in November 2001, and served as Senior Vice President of Worldwide
+Sales from February 2000 to November 2001, and Vice President of Sales, Latin
+America from October 1997 to February 2000. Prior to joining TransAct, Mr.
+Stetson served as Vice President and Sales Manager at Gekay Sales and Service
+Company from 1995 until October 1997.
+STEVEN A. DEMARTINO joined TransAct as Corporate Controller in August 1996
+and was appointed an officer of the Company in January 1998, Vice President in
+December 1999, and Senior Vice President, Finance and Information Technology in
+October 2001. Prior to joining TransAct, Mr. DeMartino was a self-employed
+financial consultant from May 1996 to August 1996. Prior thereto, Mr. DeMartino,
+served as Controller of NER/Copart, Inc. from September 1994 to May 1996.
+MICHAEL S. KUMPF, Senior Vice President-Engineering since June 1996,
+served as Vice President of Engineering of Ithaca from 1991 until June 1996. Mr.
+Kumpf was appointed Executive Vice President of Engineering in January 2002.
+MARK B. GOEBEL, Senior Vice President - General Manager (Wallingford, CT
+facility), served as Vice President-Engineering from April 1994 until he was
+appointed Senior Vice President of Engineering of Wallingford, and an officer of
+the Company, in January 2000. In November 2000, Mr. Goebel was named Senior Vice
+President - General Manager of the Wallingford, CT facility. As a result of the
+Consolidation, Mr. Goebel terminated employment with the Company on March 1,
+2002.
+LUCY H. STALEY, Senior Vice President-General Manager (Ithaca, NY
+facility) since June 1996, served as a Vice President of Ithaca from 1984 until
+June 1996. As a result of the Consolidation, Ms. Staley terminated employment
+with the Company on January 31, 2002.
+ITEM 2. PROPERTIES.
+The Company's operations are currently conducted at the facilities
+described below. In February 2001, the Company announced plans to establish a
+global engineering and manufacturing center at its Ithaca, NY facility. As part
+of this strategic decision, the Company will complete the consolidation of all
+manufacturing and engineering into its existing Ithaca, NY facility and close
+its Wallingford, CT manufacturing facility in May 2002. The Company expects to
+be able to sublease the Wallingford facility for the remaining term of the
+lease, however there can be no assurance that the Company will be successful in
+doing so, or that it will be able to do so at terms comparable to those of its
+existing lease.
+In connection with the consolidation of facilities into Ithaca, the
+Company has entered into an agreement to add approximately 10,000 square feet of
+manufacturing space and 3,000 square feet of office space to its Ithaca
+facility. The Company expects to occupy the additional space in April 2002.
+5
+Size Owned or Lease Expiration
+Location Operations Conducted (Approx. Sq. Ft.) Leased Date
+--------------------------- -------------------------- ----------------- -------- ----------------
+Wallingford, Connecticut Manufacturing facility and 49,000 Leased March 31, 2008
+executive offices
+Ithaca, New York Manufacturing facility 59,000 Leased June 30, 2007
+Doncaster, United Kingdom Sales office and service 2,800 Leased August 1, 2009
+depot
+Georgia, Florida, Illinois, Five (5) regional sales 600 Leased Various
+New York and Texas offices
+The Company believes that its facilities generally are in good condition,
+adequately maintained and suitable for their present and currently contemplated
+uses.
+ITEM 3. LEGAL PROCEEDINGS.
+None.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
+No matters were submitted to a vote of security holders during the last
+quarter of the year covered by this report.
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
+The Company's common stock is traded on the Nasdaq National Market under
+the symbol TACT. As of March 15, 2002, there were 886 holders of record of the
+common stock. The high and low sales prices of the common stock reported during
+each quarter of the years ended December 31, 2001 and 2000 were as follows:
+Year Ended Year Ended
+December 31, 2001 December 31, 2000
+--------------------- --------------------
+High Low High Low
+------ ------ ------ ------
+First Quarter $ 7.03 $ 3.88 $10.25 $ 6.03
+Second Quarter 9.65 5.05 11.38 8.00
+Third Quarter 9.85 3.95 11.50 5.75
+Fourth Quarter 6.00 3.88 8.25 5.25
+No dividends on common stock have been declared and the Company does not
+anticipate declaring dividends in the foreseeable future. The Company's credit
+agreement with LaSalle Business Credit restricts the payment of cash dividends
+on its common stock for the term of the agreement.
+ITEM 6. SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+Year Ended December 31,
+---------------------------------------------------
+2001 2000 1999 1998 1997
+-------- -------- ------- ------- -------
+Statement of Operations Data:
+Net sales $ 43,974 $ 53,720 $44,889 $52,239 $58,400
+Gross profit 9,774 14,142 11,754 13,826 18,173
+Operating income (loss) (7,286) (154) 35 2,148 7,831
+Net income (loss) (4,922) (344) 324 1,206 4,893
+Net income (loss) available
+to common shareholders (5,280) (664) 324 1,206 4,893
+Net income (loss) per share:
+Basic (0.95) (0.12) 0.06 0.20 0.72
+Diluted (0.95) (0.12) 0.06 0.20 0.71
+6
+December 31,
+---------------------------------------------------
+2001 2000 1999 1998 1997
+-------- -------- ------- ------- -------
+Balance Sheet Data:
+Total assets $ 25,791 $ 27,619 $25,684 $23,788 $24,699
+Long-term debt 5,344 5,944 7,100 5,075 --
+Shareholders' equity:
+Preferred 3,746 3,668 -- -- --
+Common 7,315 12,191 12,207 12,177 17,903
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS.
+This discussion should be read in conjunction with the Consolidated
+Financial Statements and notes thereto.
+Certain statements included in this report, including without limitation
+statements in this Management's Discussion and Analysis of Financial Condition
+and Results of Operations, which are not historical facts are "forward-looking
+statements" within the meaning of Section 27A of the Securities Act of 1933, as
+amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All
+forward-looking statements involve risks and uncertainties, including, but not
+limited to, customer acceptance and market share gains, both domestically and
+internationally, in the face of substantial competition from competitors that
+have broader lines of products and greater financial resources; introduction of
+new products into the marketplace by competitors; successful product
+development; dependence on significant customers; dependence on third parties
+for sales in Europe and Latin America; economic conditions in the United States,
+Europe and Latin America; marketplace acceptance of new products; risks
+associated with foreign operations; the Company's ability to successfully
+sublease its facility in Wallingford, CT subsequent to its closing; availability
+of third-party components at reasonable prices; and the absence of price wars or
+other significant pricing pressures affecting the Company's products in the
+United States or abroad. Actual results may differ materially from those
+discussed in, or implied by, the forward-looking statements. The forward-looking
+statements speak only as of the date this report and the Company assumes no duty
+to update them to reflect new, changing or unanticipated events or
+circumstances.
+PLANT CONSOLIDATION DURING 2001
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company undertook a plan to consolidate all
+manufacturing and engineering into its existing Ithaca, NY facility and close
+its Wallingford, CT facility (the "Consolidation"). The Company's technology
+shift to inkjet and thermal printing from dot matrix impact printing has
+dramatically reduced the labor content in printers, and therefore, lowers the
+required production capacity. As of December 31, 2001, substantially all
+Wallingford product lines were successfully transferred to Ithaca, NY. The
+Company expects to maintain one small component production line in Wallingford
+until May 2002, after which the manufacturing facility will be closed. The
+closing of the Wallingford facility is expected to result in the termination of
+employment of approximately 70 production, administrative and management
+employees. The Company estimates that the non-recurring costs associated with
+the Consolidation, including severance pay, stay bonuses, employee benefits,
+moving expenses, non-cancelable lease payments, and other costs, will be
+approximately $4.2 million, of which approximately $4.1 million was recognized
+during 2001. See the "Liquidity and Capital Resources" section for a discussion
+of the expected impact of the Consolidation on the Company's future results of
+operations and cash flows.
+CRITICAL ACCOUNTING POLICIES
+The Company's consolidated financial statements have been prepared in
+accordance with generally accepted accounting principles in the United States.
+In preparing the financial statements, the Company is required to make
+estimation judgments. Such judgments are based upon historical experience and
+certain assumptions that are believed to be reasonable in the particular
+circumstances. Those judgments affect both balance sheet items and income
+statement categories. The Company evaluates its assumptions on an ongoing basis
+by comparing actual results with its estimates. Actual results may differ from
+the original estimates. The following accounting policies are those that the
+Company believes to be most critical in the preparation of its financial
+statements.
+Inventory Valuation--The Company's inventories are stated at the lower of
+cost or market. The Company writes down its inventory for any material that has
+become obsolete or may become unsaleable based on estimates of future demand in
+the market. Assumptions are reviewed at least quarterly and adjustments are
+made, as necessary, to reflect changed conditions.
+7
+Deferred Tax Assets--The Company has recorded deferred tax assets, largely
+as the result of the net operating loss incurred in 2001. Based on the Company's
+projection of future taxable income and certain prudent tax planning strategies,
+no valuation allowance against these deferred tax assets is considered
+necessary. Should circumstances change and the Company determine that some or
+all of the deferred taxes would not be realized, a valuation allowance would be
+recorded resulting in a charge to income in the period the determination is
+made.
+Accrued Restructuring Expenses--In connection with the Consolidation of
+manufacturing facilities, the Company has recorded significant accruals. These
+accruals comprise severance pay, stay bonuses, employee benefits, non-cancelable
+lease costs and certain other expenses. Management has made reasonable estimates
+of such costs and expenses, most of which it expects to be paid in 2002.
+However, if actual costs differ from the estimates, charges or credits to income
+could result in the period the adjustments are determined. Also, because certain
+moving and relocation costs are not accruable under generally accepted
+accounting principles in the U.S., those expenses are recorded as incurred. As a
+result, the Company expects to record some additional charges in 2002 related to
+the completion of the Consolidation.
+Accrued Warranty Costs--The Company warranties its products for up to two
+years and records the estimated cost of such product warranties at the time the
+sale is recorded. Estimated warranty costs are based upon actual past experience
+of product returns and the related estimated cost of labor and material to make
+the necessary repairs. If actual future product return rates or the actual costs
+of material and labor differ from the estimates, adjustments to the accrued
+warranty liability would be made.
+(A) RESULTS OF OPERATIONS
+(i) YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000
+NET SALES. Net sales by market for the years ended December 31, 2001 and
+2000 were as follows:
+Year ended Year ended
+(In thousands) December 31, 2001 December 31, 2000
+----------------- -----------------
+Point of sale $20,007 45.5% $29,396 54.7%
+Gaming and lottery 19,869 45.2 19,298 35.9
+Other 4,098 9.3 5,026 9.4
+------- ----- ------- -----
+$43,974 100.0% $53,720 100.0%
+======= ===== ======= =====
+Net sales for 2001 decreased $9,746,000, or 18%, from 2000 largely due to
+significantly lower shipments into the Company's point of sale ("POS") market.
+International sales decreased to $7,922,000, or 18.0% of net sales in 2001, from
+$16,320,000, or 30.4% of net sales in 2000.
+Point of sale: Sales of the Company's POS printers decreased approximately
+$9,389,000, or 32%. International POS printer shipments decreased approximately
+$9,438,000, to $6,193,000, largely due to lower printer shipments to ICL Pathway
+for the British Post Office project. Sales for the British Post Office project,
+which include printer shipments and service revenue, were approximately
+$1,900,000 in 2001 compared to $10,900,000 in 2000. The Company completed
+shipping printers for the British Post Office project during the first quarter
+of 2001, and no future sales, other than spare parts and service, are expected.
+In addition to lower sales to ICL Pathway, the Company experienced a decrease in
+sales, primarily to Europe, of approximately $1,200,000 through Okidata, the
+Company's former exclusive distribution partner in Europe. As of May 2001,
+Okidata no longer exclusively distributes the Company's printers in Europe. The
+Company also experienced a decline of approximately $300,000 of sales to Latin
+America through Okidata, the Company's distribution partner in Latin America.
+The decrease in international POS sales to ICL Pathway and Okidata was somewhat
+offset by an increase of approximately $1,200,000 of shipments of the Company's
+thermal fiscal printer in Europe.
+Despite adverse economic conditions, domestic POS printer sales increased
+slightly by $49,000 to $13,814,000. Due to on-going economic weakness, the
+Company expects continued worldwide softness in demand for its POS products
+during 2002.
+8
+Gaming and lottery: Sales of the Company's gaming and lottery printers
+increased approximately $571,000, or 3%, from the prior year. Sales of the
+Company's on-line lottery printers and spares to GTECH increased by
+approximately $2,400,000, to approximately $14,300,000 in 2001, compared to
+$11,900,000 in 2000. The Company has received follow-on orders from GTECH for
+approximately $9,800,000 of on-line lottery printers of which approximately
+$9,300,000 and $500,00 will be delivered in 2002 and 2003, respectively. In
+addition to the increase of printer sales to GTECH, sales of the Company's slot
+machine printers and other gaming printers increased by approximately $900,000.
+The slot machine printers are primarily for use in casinos in California and
+Nevada. The Company expects sales of its slot machine printers to continue to
+increase during 2002.
+Offsetting the increase of on-line lottery printer and spares sales to
+GTECH and increased slot machine printer sales was a decrease of approximately
+$2,700,000 in sales of the Company's video lottery terminal ("VLT") printers to
+approximately $1,700,000 in 2001. Sales of these VLT printers were unusually
+high in the last half of 2000. Since VLT printer sales are largely
+project-oriented, the Company cannot predict if and when future sales may occur.
+However, based on existing orders, the Company expects higher sales of VLT
+printers in 2002 compared to 2001.
+Other: Sales of the Company's printers into other markets decreased by
+$928,000, or 18%, from the prior year. During 2001, sales of the Company's ATM
+printer and related spares decreased by approximately $1,700,000. In addition,
+sales decreased by approximately $800,000 due to sales of kiosk printers to
+customers for projects primarily in the third quarter of 2000 that did not
+repeat in 2001. Offsetting these decreases was an increase of approximately
+$1,600,000 of the Company's thermal kiosk printers for use in a Canadian
+government application during 2001. No shipments of these printers were made in
+2000. However, the Company expects to ship printers for this application in
+2002. Since printer sales into the kiosk printer market are principally
+project-oriented, the Company cannot predict if and when future sales may occur.
+GROSS PROFIT. Gross profit decreased $4,368,000, or 31%, and the gross
+margin also declined to 22.2% from 26.3%. Both gross profit and gross margin for
+2001 were adversely impacted by lower sales volume, due primarily to the absence
+of printer shipments for the British Post Office project. The Company expects
+its gross margin for the full-year 2002 to improve to between 25% and 26% due to
+lower overhead costs resulting from the Consolidation.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses decreased $411,000, or 12%, to $3,070,000 from 2000. This
+decrease is primarily due to a reduction in engineering staff at the Company's
+Wallingford facility resulting from the Consolidation. Engineering and product
+development expense increased as a percentage of net sales to 7.0% from 6.5%,
+due to lower sales volume in 2001 compared to 2000. The Company expects
+engineering and product development expenses to be significantly lower in 2002
+compared to 2001, due largely to staff reductions resulting from the
+Consolidation.
+SELLING AND MARKETING. Selling and marketing expenses decreased $516,000,
+or 10%, to $4,570,000 from the prior year. Such expenses decreased primarily due
+to (1) unusually high marketing and promotional expenses incurred in 2000
+related to the April 2000 launch of the Company's new family of printers
+utilizing inkjet printing technology and (2) a reduction in marketing staff.
+Selling and marketing expenses as a percentage of net sales increased to 10.3%
+from 9.5%, due to lower sales volume in 2001 compared to 2000. The Company
+expects that selling and marketing expenses for 2002 will be slightly lower than
+those reported in 2001, due mostly to lower planned promotional and advertising
+expenses and staff reductions resulting from the Consolidation.
+GENERAL AND ADMINISTRATIVE. General and administrative expenses increased
+by $559,000, or 10%, to $6,099,000 from 2000 and increased as a percentage of
+net sales to 13.9% from 10.3%. The increase in expenses primarily resulted from
+the inclusion of $680,000 of accelerated depreciation on certain assets
+(primarily leasehold improvements and computer equipment) located at the
+Company's Wallingford, CT facility whose useful lives have been shortened as a
+result of the Consolidation. These increases were partially offset by a
+reduction of staff and certain related expenses at the Company's Wallingford, CT
+facility resulting from the Consolidation. The Company expects general and
+administrative expenses to be significantly lower in 2002 compared to 2001 due
+largely to staff reductions resulting from the Consolidation and non-recurring
+accelerated depreciation charges incurred in 2001.
+BUSINESS CONSOLIDATION AND RESTRUCTURING. During 2001, the Company
+incurred approximately $3,321,000 of business consolidation and restructuring
+expenses related to the Consolidation. These expenses primarily included
+employee severance and termination related expenses, and facility closure and
+consolidation expenses (including moving expenses, estimated non-cancelable
+lease payments and other costs). Although the Consolidation was substantially
+completed in 2001, the Company estimates that it will incur an additional
+$50,000 to $100,000 of non-recurring costs associated with the Consolidation
+during 2002. These costs are expected to include (1) expenses incurred to
+physically move the remaining assets of the Wallingford, CT facility to Ithaca,
+NY and (2) severance costs for employees expected to terminate in 2002. See Note
+8 to the Consolidated Financial Statements for further detail.
+9
+OPERATING LOSS. The Company incurred an operating loss of $7,286,000 in
+2001 compared to an operating loss of $154,000 in 2000. The operating loss in
+2001 resulted primarily from lower gross profit on lower sales in 2001 compared
+to 2000 as well as expenses related to the Consolidation.
+INTEREST. Net interest expense decreased to $397,000 from $649,000 in 2000
+due to decreased average outstanding borrowings on the Company's line of credit
+and a lower average interest rate on such borrowings. See "Liquidity and Capital
+Resources" below.
+INCOME TAXES. As a result of the Company's loss before income taxes, the
+Company recorded an income tax benefit of $2,748,000 and $448,000, or an
+effective rate of 35.8% and 56.6%, in 2001 and 2000, respectively. The
+abnormally high effective tax benefit rate in 2000 is primarily due to the
+recognition of certain tax credits and the benefit from the Company's foreign
+sales corporation on relatively low pre-tax amounts.
+NET LOSS. The Company incurred a net loss during 2001 of $4,922,000, or
+$0.95 per share (basic and diluted) after giving effect to $358,000 of dividends
+and accretion charges on preferred stock issued in April 2000. This compares to
+a net loss for 2000 of $344,000, or $0.12 per share (basic and diluted) after
+giving effect to $320,000 of dividends and accretion charges on preferred stock
+issued in April 2000. In future quarters, dividends and accretion charges on
+preferred stock will be approximately $90,000, before the effect of any
+conversion or redemption of the preferred stock.
+(ii) YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
+NET SALES. Net sales by market for the years ended December 31, 2000 and
+1999 were as follows:
+Year ended Year ended
+(In thousands) December 31, 2000 December 31, 1999
+----------------- ------------------
+Point of sale $29,396 54.7% $26,653 59.4%
+Gaming and lottery 19,298 35.9 8,782 19.5
+Other 5,026 9.4 9,454 21.1
+------- ----- ------- -----
+$53,720 100.0% $44,889 100.0%
+======= ===== ======= =====
+Net sales for the year ended December 31, 2000 increased $8,831,000, or
+20%, to $53,720,000 from $44,889,000 in 1999 due to increased shipments into the
+POS and gaming and lottery markets, partially offset by a decrease in sales in
+the Company's other markets. International sales increased to $16,320,000, or
+30.4% of net sales in 2000, from $8,507,000, or 19.0% of net sales in 1999.
+Point of sale: Sales of the Company's POS printers increased $2,743,000,
+or 10%. International POS printer shipments increased approximately $9,387,000
+due to the resumption of printer shipments to ICL Pathway for the British Post
+Office project. Sales for this project, including printers, spares and service,
+totaled approximately $10,900,000 in 2000. The Company did not make any printer
+shipments related to this project in 1999. The Company completed shipping
+printers for the British Post Office project in February 2001 and no further
+shipments are expected. The increase in international shipments for the British
+Post Office project was offset by a net decrease of approximately $1,300,000 of
+printer shipments to other customers primarily in Europe and Latin America.
+Domestic POS printer shipments decreased by approximately $6,644,000, due
+primarily to continued softness in demand from the Company's domestic
+distributors.
+Gaming and lottery: Sales of the Company's gaming and lottery printers
+increased $10,516,000, or 120%, from 1999. This net increase resulted from a
+number of factors. The primary effect on the revenue in this market during 2000
+was the resumption of shipments to GTECH of the Company's on-line lottery
+printers that totaled $11,400,000 compared to no on-line lottery printer
+shipments during 1999. In addition, the Company's new slot machine printer added
+approximately $2,800,000 to revenue in 2000. The new slot machine printer is
+primarily for use in Indian casinos in California and casinos in Nevada.
+10
+Offsetting the sales increases noted above was a decrease of approximately
+$2,400,000 in shipments of printers for use in video lottery terminals (VLTs),
+primarily due to the absence in 2000 of sales into the South Carolina market,
+which banned VLTs in October 1999. The absence of VLT printer sales for the
+South Carolina market was partially offset by increased sales of these printers
+into other jurisdictions. Also, sales of in-lane lottery printers to GTECH did
+not recur in 2000, resulting in a decrease in sales of $1,100,000. Sales of
+in-lane lottery printers are project-oriented and the Company cannot predict if
+and when future sales may occur.
+Other: Sales of the Company's printers into other markets decreased
+$4,428,000, or 47% from 1999 due to decreased shipments of printers used in
+automated teller machines, decreased shipments of printers for use in bank
+teller applications, and the absence of shipments of the Company's thermal kiosk
+printers for use in a Canadian government application.
+GROSS PROFIT. Gross profit increased $2,388,000, or 20%, to $14,142,000
+from $11,754,000 in 1999 due primarily to higher sales volume in 2000. The gross
+margin remained essentially the same at 26.3% in 2000 compared to 26.2% in 1999.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses increased $246,000, or 8%, to $3,481,000 from $3,235,000 in
+1999. The increase in spending was primarily due to increased development and
+design expenses related to inkjet printers, including additional engineering
+staff. These expenses decreased as a percentage of net sales to 6.5% from 7.2%,
+due to higher sales in 2000 compared to 1999.
+SELLING AND MARKETING. Selling and marketing expenses increased
+$1,199,000, or 31%, to $5,086,000 from $3,887,000 in 1999, and increased as a
+percentage of net sales to 9.5% from 8.7% in 1999. Such expenses increased by
+approximately $1,400,000 due primarily to marketing and promotional activities
+related to the launch of the Company's new family of printers utilizing inkjet
+printing technology in April 2000, including additional marketing staff. This
+increase was somewhat offset by lower sales commissions resulting from a
+decrease in sales eligible for commissions in 2000 compared to 1999.
+GENERAL AND ADMINISTRATIVE. General and administrative expenses increased
+by $943,000, or 21% to $5,540,000 in 2000 from $4,597,000 in 1999, and increased
+slightly as a percentage of net sales to 10.3% from 10.2%. The increase
+primarily resulted from (1) higher expenses resulting from the Company's upgrade
+of its telecommunications system, (2) an increase in administrative
+compensation-related expenses and (3) higher professional expenses.
+PROVISION FOR RESTRUCTURING. During the year ended December 31, 2000, the
+Company recorded a provision for restructuring of $189,000 to cover severance
+costs related to the downsizing at the Company's manufacturing facility in
+Wallingford, Connecticut. At December 31, 2000, approximately $105,000 of
+restructuring expenses remained accrued.
+OPERATING INCOME (LOSS). The Company incurred an operating loss of
+$154,000 in 2000 compared to operating income of $35,000 in 1999. The operating
+loss was primarily the result of higher operating expenses, including planned
+marketing and product development expenses related to the launch of the
+Company's new inkjet printer, higher general and administrative expenses, and
+the restructuring provision recorded in 2000.
+OTHER INCOME. In 1999, the Company recorded a one-time pre-tax gain of
+$770,000 related to the favorable settlement of a lawsuit with GTECH.
+INTEREST. Net interest expense increased to $649,000 from $399,000 in 1999
+due to increased average outstanding borrowings on the Company's line of credit
+and a higher average borrowing rate in 2000 compared to 1999.
+INCOME TAXES. As a result of the Company's loss before income taxes in
+2000, the Company recorded an income tax benefit of $448,000, or an effective
+rate of 56.6%, compared to an income tax provision of $102,000 in 1999, or an
+effective rate of 24%. The abnormally high effective tax benefit rate in 2000
+and the low effective tax rate in 1999 are primarily due to the recognition of
+certain tax credits and the benefit from the Company's foreign sales corporation
+on relatively low pre-tax amounts.
+NET INCOME (LOSS). The Company incurred a net loss of $344,000 for 2000,
+or $0.12 per share (basic and diluted), after giving effect to $264,000 of
+dividends and accretion charges and a one-time beneficial conversion charge of
+approximately $56,000 on preferred stock issued in April of 2000. This compares
+to net income of $324,000, or $0.06 per share (basic and diluted) in 1999.
+11
+(B) LIQUIDITY AND CAPITAL RESOURCES
+CASH FLOW
+The Company generated cash from operations of $1,445,000, $333,000 and
+$2,033,000 in 2001, 2000 and 1999, respectively. The increase in cash generated
+from operations in 2001 compared to 2000 resulted from a number of factors:
+receivables decreased due to lower sales volume in the fourth quarter of 2001
+compared to the fourth quarter of 2000; other current assets decreased due
+largely to the receipt of federal and state tax refunds; accounts payable and
+accrued liabilities increased largely due to higher inventory purchases at
+year-end; accrued restructuring expenses increased as a result of expenses
+related to the Consolidation; and increased depreciation and amortization, due
+primarily to accelerated depreciation on certain assets as a result of the
+Consolidation. Offsetting these increases in cash generated from operations in
+2001 were the following: funding the Company's net loss of $4,922,000 in 2001
+compared to $344,000 in 2000; higher inventory levels at December 31, 2001 due
+largely to inventory bought during the year for recently-introduced products;
+and increased deferred taxes resulting largely from expenses related to the
+Consolidation and the Company's net loss in 2001. Based on recent tax law
+changes, the Company will carry back its federal net operating losses to prior
+years, which is expected to result in a tax refund of approximately $700,000 in
+2002.
+WORKING CAPITAL
+The Company's working capital decreased to $8,366,000 at December 31, 2001
+from $13,631,000 at December 31, 2000. The current ratio also decreased to 1.90
+to 1 at December 31, 2001 from 3.54 to 1 at December 31, 2000. The decrease in
+both working capital and the current ratio were largely due to (1) lower
+receivables at December 31, 2001 resulting from lower sales volume in the fourth
+quarter of 2001 compared to the fourth quarter of 2000 and (2) an increase in
+accrued restructuring expenses of approximately $2.9 million related to the
+Consolidation at December 31, 2001.
+CREDIT FACILITY AND BORROWINGS
+On May 25, 2001, the Company entered into a three-year, $13.5 million
+credit facility (the "LaSalle Credit Facility") with LaSalle Business Credit,
+Inc. ("LaSalle") expiring on May 25, 2004 to replace its prior credit facility
+with Webster Bank. The LaSalle Credit Facility provides a $12 million revolving
+credit line, a $0.5 million term loan and a $1 million equipment loan facility.
+Borrowings under the LaSalle Credit Facility bear a floating rate of interest
+based on LaSalle's prime rate. Under certain circumstances, the Company may
+select a fixed interest rate for a specified period of time of up to 180 days on
+borrowings based on the current LIBOR rate.
+On October 30, 2001, the Company amended the LaSalle Credit Facility.
+Under the terms of the amendment ("LaSalle Amendment No.1"), LaSalle (1) waived
+compliance with the minimum EBITDA financial covenant as of September 30, 2001,
+(2) revised certain other financial covenants through December 31, 2001, (3)
+increased the floating rate of interest on borrowings under the revolving credit
+line to LaSalle's prime rate plus 1.0%, or the current LIBOR rate plus 3.5%, and
+(4) increased the floating rate of interest on borrowings under the term loan
+and equipment loan to LaSalle's prime rate plus 1.5%, or the current LIBOR rate
+plus 4.0%. Upon execution of LaSalle Amendment No. 1, the Company paid a fee of
+$20,000 to LaSalle.
+On December 21, 2001, the Company amended the LaSalle Credit Facility to
+reset certain financial covenants for 2002 and beyond ("LaSalle Amendment No.
+2). Upon execution of LaSalle Amendment No. 2, the Company paid a fee of $5,000
+to LaSalle.
+As of December 31, 2001, the Company had $4,994,000 and $450,000
+outstanding on the revolving credit line and term loan, respectively, and no
+borrowings under the equipment loan. Annual principal payments on the term loan
+are $100,000.
+On February 22, 2002, at the request of a major customer, the Company
+received a cash payment of approximately $5,800,000 in advance of printer
+shipments to be made from March through August 2002. This amount has been
+classified as a current liability and will be reduced by the sales value of
+shipments as they are made. As a result of this payment, the Company repaid all
+its outstanding revolving borrowings under the LaSalle Credit Facility in
+February 2002. However, as shipments are made to the customer between March and
+August 2002, the Company expects to resume borrowings under the LaSalle Credit
+Facility. The Company expects its revolving borrowings to return to
+approximately the same level as December 31, 2001 by the end of the third
+quarter 2002. Due to the classification of the advance payment as a current
+liability, the Company expects to report lower working capital and a lower
+current ratio at March 31, 2002 and June 30, 2002.
+12
+SALE OF PREFERRED STOCK
+On April 7, 2000 the Company sold 4,000 shares of 7% Series B Cumulative
+Convertible Redeemable Preferred Stock (the "Preferred Stock") to Advance
+Capital Advisors, L.P. and its affiliate in consideration of $1,000 per share
+(the "Stated Value"), for a total of $4,000,000, less issuance costs of
+approximately $200,000. The Preferred Stock is redeemable at the holders on
+April 7, 2005 at $1,000 per share plus any unpaid dividends. The Company used
+the net proceeds repay outstanding borrowings under the Company's revolving
+credit facility. The Company paid $280,000 and $205,000 of cash dividends to
+Advance Capital Advisors, L.P. in 2001 and 2000, respectively, and expects to
+pay $280,000 in 2002.
+CAPITAL EXPENDITURES
+The Company's capital expenditures were approximately $1,382,000,
+$2,415,000 and $2,742,000 in 2001, 2000 and 1999, respectively. These
+expenditures primarily included new product tooling, computer equipment, and
+factory machinery and equipment. The Company's capital expenditures for 2002 are
+expected to be approximately $1,000,000, a majority for new product tooling.
+CONSOLIDATION EXPENSES
+During 2001, the Company incurred approximately $4,096,000 of business
+consolidation, restructuring and related charges as a result of the
+Consolidation. These expenses primarily included employee severance and
+termination related expenses, facility closure and consolidation expenses
+(including moving expenses, estimated non-cancelable lease payments and other
+costs) and accelerated depreciation and asset disposal losses on certain
+leasehold improvements and other fixed assets. Although the Consolidation was
+substantially completed in 2001, the Company estimates that it will incur an
+additional $50,000 to $100,000 of non-recurring costs associated with the
+Consolidation during 2002. These costs are expected to include (1) expenses
+incurred to physically move the remaining assets of the Wallingford, CT facility
+to Ithaca, NY and (2) severance costs for employees expected to terminate in
+2002. The Company believes that the Consolidation will significantly lower the
+Company's cost structure in 2002, with estimated annual cost savings of at least
+$4 million compared to 2001. See Note 8 to the Consolidated Financial Statements
+for further detail.
+Of the total of $4,100,000 of expenses, approximately $3,300,000 require
+cash outlays. During 2001, the Company paid approximately $400,000 of these
+costs, with substantially all the remaining costs expected to be paid during
+2002. The Company expects to realize improved gross margins and lower operating
+expenses in 2002 as a result of the Consolidation.
+The Company believes that cash flows generated from operations and
+borrowings available under the LaSalle Credit Facility, as amended, will provide
+sufficient resources to meet the Company's working capital needs, including
+costs associated with the Consolidation, finance its capital expenditures and
+meet its liquidity requirements through December 31, 2002.
+(C) IMPACT OF INFLATION
+TransAct believes that its business has not been affected to a significant
+degree by inflationary trends because of the low rate of inflation during the
+past three years, nor does it believe it will be significantly affected during
+2002.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
+INTEREST RATE RISK
+The Company's exposure to market risk for changes in interest rates
+relates primarily to borrowings under the Company's Credit Facility with LaSalle
+Business Credit. These borrowings bear interest at variable rates and the fair
+value of this indebtedness is not significantly affected by changes in market
+interest rates. An effective increase or decrease of 10% in the current
+effective interest rates under the Credit Facility would not have a material
+effect on the Company's results of operations or cash flow.
+FOREIGN CURRENCY EXCHANGE RISK
+A substantial portion of the Company's sales are denominated in U.S.
+dollars and, as a result, the Company has relatively little exposure to foreign
+currency exchange risk with respect to sales made. This exposure may change over
+time as business practices evolve and could have a material adverse impact on
+the Company's financial results in the future. The Company does not use forward
+exchange contracts to hedge exposures denominated in foreign currencies or any
+other derivative financial instruments for trading or speculative purposes. The
+effect of an immediate 10% change in exchange rates would not have a material
+impact on the Company's future results of operations or cash flow.
+13
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Page
+Number
+------
+Report of Independent Accountants 15
+TransAct Technologies Incorporated consolidated financial
+statements:
+Consolidated balance sheets as of December 31, 2001 and 16
+December 31, 2000.
+Consolidated statements of operations for the years ended 17
+December 31, 2001, 2000 and 1999.
+Consolidated statements of cash flows for the years ended 18
+December 31, 2001, 2000 and 1999.
+Consolidated statement of changes in shareholders' equity 19
+for the period from December 31, 1998 through
+December 31, 2001. 20
+Notes to consolidated financial statements.
+14
+REPORT OF INDEPENDENT ACCOUNTANTS
+To the Board of Directors and Shareholders
+of TransAct Technologies Incorporated:
+In our opinion, the accompanying consolidated balance sheets and the related
+consolidated statements of operations, of cash flows and of changes in
+shareholders' equity present fairly, in all material respects, the financial
+position of TransAct Technologies Incorporated and its subsidiaries at December
+31, 2001 and 2000, and the results of their operations and their cash flows for
+each of the three years in the period ended December 31, 2001 in conformity with
+accounting principles generally accepted in the United States. 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 of these statements in accordance with
+auditing standards generally accepted in the United States, which 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, assessing the accounting principles used and
+significant estimates made by management, and evaluating the overall financial
+statement presentation. We believe that our audits provide a reasonable basis
+for the opinion expressed above.
+/s/ PricewaterhouseCoopers LLP
+Hartford, Connecticut
+February 8, 2002
+15
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED BALANCE SHEETS
+(In thousands)
+December 31, December 31,
+2001 2000
+------------ ------------
+ASSETS:
+Current assets:
+Cash and cash equivalents $ 417 $ 992
+Receivables, net (Note 4) 4,047 6,137
+Inventories (Note 5) 10,633 9,857
+Deferred tax assets 2,382 1,205
+Other current assets 212 811
+-------- --------
+Total current assets 17,691 19,002
+-------- --------
+Fixed assets, net (Note 6) 5,190 6,876
+Goodwill, net (Note 6) 1,469 1,678
+Deferred tax assets 1,120 --
+Other assets 321 63
+-------- --------
+8,100 8,617
+-------- --------
+$ 25,791 $ 27,619
+======== ========
+LIABILITIES AND SHAREHOLDERS' EQUITY:
+Current liabilities:
+Current portion of term loan $ 100 $ --
+Accounts payable 2,903 2,690
+Accrued liabilities (Note 7) 3,320 2,576
+Accrued restructuring expenses (Note 8) 3,002 105
+-------- --------
+Total current liabilities 9,325 5,371
+-------- --------
+Revolving bank loan payable (Note 10) 4,994 5,944
+Long-term portion of term loan 350 --
+Other liabilities 61 445
+-------- --------
+5,405 6,389
+-------- --------
+Commitments and contingencies (Note 11)
+Mandatorily redeemable preferred stock, Series B, 7%
+cumulative convertible, $1,000 stated value,
+8,000 shares authorized, 4,000 shares issued
+and outstanding (Note 16) 3,746 3,668
+-------- --------
+Shareholders' equity (Notes 12 and 13):
+Preferred stock, Series A, $0.01 par value, 5,000,000
+authorized, none issued and outstanding -- --
+Common stock, $0.01 par value, 20,000,000 authorized,
+5,684,770 and 5,607,827 shares issued and outstanding 57 56
+Additional paid-in capital 6,303 6,069
+Retained earnings 1,649 6,929
+Unamortized restricted stock compensation (286) (477)
+Loan receivable from officer (330) (330)
+Accumulated other comprehensive income (78) (56)
+-------- --------
+Total shareholders' equity 7,315 12,191
+-------- --------
+$ 25,791 $ 27,619
+======== ========
+See accompanying notes to consolidated financial statements.
+16
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except per share data)
+Year Ended December 31,
+2001 2000 1999
+-------- -------- --------
+Net sales $ 43,974 $ 53,720 $ 44,889
+Cost of sales 34,200 39,578 33,135
+-------- -------- --------
+Gross profit 9,774 14,142 11,754
+-------- -------- --------
+Operating expenses:
+Engineering, design and product
+development expenses 3,070 3,481 3,235
+Selling and marketing expenses 4,570 5,086 3,887
+General and administrative expenses
+(Note 8) 6,099 5,540 4,597
+Business consolidation and restructuring
+expenses (Note 8) 3,321 189 --
+-------- -------- --------
+17,060 14,296 11,719
+-------- -------- --------
+Operating income (loss) (7,286) (154) 35
+-------- -------- --------
+Other income (expense):
+Interest, net (397) (649) (399)
+Other, net (Note 16) 13 11 790
+-------- -------- --------
+(384) (638) 391
+-------- -------- --------
+Income (loss) before income taxes (7,670) (792) 426
+Income tax provision (benefit) (Note 14) (2,748) (448) 102
+-------- -------- --------
+Net income (loss) (4,922) (344) 324
+Dividends and accretion charges on preferred
+stock (Note 16) (358) (320) --
+-------- -------- --------
+Net income (loss) available to common
+shareholders $ (5,280) $ (664) $ 324
+======== ======== ========
+Net income (loss) per share:
+Basic $ (0.95) $ (0.12) $ 0.06
+======== ======== ========
+Diluted $ (0.95) $ (0.12) $ 0.06
+======== ======== ========
+Shares used in per share calculation:
+Basic 5,551 5,504 5,565
+======== ======== ========
+Diluted 5,551 5,504 5,614
+======== ======== ========
+See accompanying notes to consolidated financial statements.
+17
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In Thousands)
+Year Ended December 31,
+2001 2000 1999
+-------- -------- --------
+Cash flows from operating activities:
+Net income (loss) $ (4,922) $ (344) $ 324
+Adjustments to reconcile net income (loss)
+to net cash provided by operating
+activities:
+Depreciation and amortization 3,398 2,750 2,238
+Deferred income taxes (2,643) (78) (19)
+Loss on disposal of fixed assets 209 -- 11
+Changes in operating assets and
+liabilities:
+Receivables 2,090 (1,274) 371
+Inventories (776) 400 (1,475)
+Other current assets 599 (415) 158
+Other assets (326) (162) (100)
+Accounts payable 213 (366) 858
+Accrued liabilities and other 706 (283) (333)
+liabilities
+Accrued restructuring expenses 2,897 105 --
+-------- -------- --------
+Net cash provided by operating activities 1,445 333 2,033
+-------- -------- --------
+Cash flows from investing activities:
+Purchases of fixed assets (1,382) (2,415) (2,742)
+Loans to officers -- 15 (345)
+Acquisition of Tridex Ribbon Business -- -- (295)
+Proceeds from sale of assets 2 217 --
+-------- -------- --------
+Net cash used in investing activities (1,380) (2,183) (3,382)
+-------- -------- --------
+Cash flows from financing activities:
+Revolving bank loan borrowings
+(repayments), net (950) (1,156) 1,300
+Term loan borrowings, net 450 -- --
+Proceeds from option exercises 262 175 24
+Net proceeds from issuance of preferred -- 3,785 --
+stock
+Payments of cash dividends on preferred (280) (205) --
+stock
+Tax charge related to restricted stock (100) -- --
+vested
+Purchase of treasury stock -- -- (229)
+-------- -------- --------
+Net cash provided by (used in) financing
+activities (618) 2,599 1,095
+-------- -------- --------
+Effect of exchange rate changes on cash (22) (36) (13)
+-------- -------- --------
+Increase (decrease) in cash and cash (575) 713 (267)
+equivalents
+Cash and cash equivalents at beginning of
+period 992 279 546
+-------- -------- --------
+Cash and cash equivalents at end of period $ 417 $ 992 $ 279
+======== ======== ========
+Supplemental cash flow information:
+Interest paid $ 403 $ 696 $ 433
+Income taxes paid (refunded) (637) 74 171
+See accompanying notes to consolidated financial statements.
+18
+TransAct Technologies Incorporated
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
+(In thousands, except share data)
+Unamortized Loan Accumulated
+Common Stock Additional Restricted Receivable Other
+------------------ Paid-in Retained Stock from Comprehensive Treasury
+Shares Amount Capital Earnings Compensation Officer Income Stock
+--------- ------ ---------- -------- ------------ ---------- ------------ --------
+Balance, December 31, 1998 5,629,500 $ 56 $ 5,763 $ 7,268 $ (903) $ -- $ (7) $ --
+Issuance of restricted stock 13,000 -- 98 -- (98) -- -- --
+Issuance of shares from
+exercise of stock options 5,100 -- 24 -- -- -- -- --
+Amortization of restricted
+stock compensation -- -- -- -- 254 -- -- --
+Purchase of treasury shares (70,800) -- -- -- -- -- -- (229)
+Retirement of treasury shares -- -- (229) -- -- -- -- 229
+Issuance of loan to officer -- -- -- -- -- (330) -- --
+Comprehensive income:
+Foreign currency translation
+adjustment -- -- -- -- -- -- (13) --
+Net income -- -- -- 324 -- -- -- --
+--------- ------ ---------- -------- ------------ ---------- ------------ --------
+Balance, December 31, 1999 5,576,800 56 5,656 7,592 (747) (330) (20) --
+Issuance of restricted stock 5,000 -- 44 -- (44) -- -- --
+Cancellation of restricted
+stock (3,800) -- (36) -- 36 -- -- --
+Issuance of shares from
+exercise of stock
+options 25,000 -- 150 -- -- -- -- --
+Issuance of shares from
+employee stock
+purchase plan 4,827 -- 24 -- -- -- -- --
+Amortization of restricted
+stock compensation -- -- -- -- 278 -- -- --
+Issuance of preferred stock
+warrants -- -- 175 -- -- -- -- --
+Deemed dividend on beneficial
+conversion of preferred stock -- -- 56 (56) -- -- -- --
+Dividends paid on preferred
+stock -- -- -- (205) -- -- -- --
+Accretion of preferred stock
+warrants and issuance costs -- -- -- (58) -- -- -- --
+Comprehensive income (loss):
+Foreign currency translation -- --
+adjustment -- -- -- -- -- -- (36) --
+Net loss -- -- -- (344) -- -- -- --
+--------- ------ ---------- -------- ------------ ---------- ------------ --------
+Balance, December 31, 2000 5,607,827 56 6,069 6,929 (477) (330) (56) --
+Issuance of restricted stock 20,000 -- 95 -- (95) -- -- --
+Cancellation of restricted (3,000) -- (22) -- 22 -- -- --
+stock
+Issuance of shares from
+exercise of stock
+options 53,500 1 233 -- -- -- -- --
+Issuance of shares from
+employee purchase plan stock 6,443 -- 28 -- -- -- -- --
+Amortization of restricted
+stock compensation -- -- -- -- 264 -- -- --
+Tax charge related to
+restricted stock vested -- -- (100) -- -- -- -- --
+Dividends paid on preferred
+stock -- -- -- (280) -- -- -- --
+Accretion of preferred stock
+warrants and issuance costs -- -- -- (78) -- -- -- --
+Comprehensive income (loss):
+Foreign currency translation
+adjustment -- -- -- -- -- -- (22) --
+Net loss -- -- -- (4,922) -- -- -- --
+--------- ------ ---------- -------- ------------ ---------- ------------ --------
+Balance, December 31, 2001 5,684,770 $ 57 $ 6,303 $ 1,649 $ (286) $ (330) $ (78) $ --
+========= ====== ========== ======== ============ ========== ============ ========
+See accompanying notes to consolidated financial statements.
+19
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+1. BASIS OF PRESENTATION
+TransAct Technologies Incorporated ("TransAct" or the "Company")
+began operating as a stand-alone, publicly-held company in August 1996 to
+conduct the printer business that was formerly operated by certain
+subsidiaries of Tridex Corporation ("Tridex").
+Certain prior year amounts have been reclassified to conform to the
+current year's presentation.
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+BUSINESS AND PRODUCTS: TransAct, through its primary operating
+facility in Ithaca, NY, operates in one industry segment,
+transaction-based printers and related products. TransAct designs,
+develops, manufactures and markets transaction-based printers under the
+Ithaca(R) and Magnetec(R) brand names. In addition, the Company markets
+related consumables, spare parts and service. The Company also operates a
+small component production line in a manufacturing facility in
+Wallingford, CT that it expects to close in May 2002 (see Note 8 for a
+further discussion). The Company's printers are used worldwide to provide
+transaction records such as receipts, tickets, coupons, register journals
+and other documents. The Company focuses on the following vertical
+markets: point-of-sale ("POS"), gaming and lottery, financial services and
+kiosk. The Company sells its products directly to end users, original
+equipment manufacturers ("OEM"), value-added resellers and selected
+distributors, primarily in the United States, Canada, Europe and Latin
+America.
+TransAct designs, develops, manufactures and markets a broad array
+of transaction-based printers utilizing inkjet, thermal and impact
+printing technology for applications requiring up to 60 character columns
+in each of its vertical markets. The Company's printers are configurable,
+which offer customers the ability to choose from a variety of features and
+functions. Options typically include printed circuit board configuration,
+paper cutting devices, paper handling capacities and number of print
+stations. In addition to its configurable printers, TransAct manufactures
+custom printers for certain OEM customers. In collaboration with these
+customers, the Company provides engineering and manufacturing expertise
+for the design and development of specialized printers.
+USE OF ESTIMATES: The preparation of financial statements in
+conformity with generally accepted accounting principles requires
+management to make estimates and assumptions that affect the reported
+amounts of assets and liabilities and disclosure of contingent assets and
+liabilities at the date of the financial statements and the reported
+amounts of revenues and expenses during the reporting period. Estimates
+have been made in areas including inventory valuation, estimated lives of
+fixed assets and goodwill, deferred tax assets, accrued liabilities,
+restructuring reserves related to the Consolidation, allowance for
+doubtful accounts and tax provisions (benefits). Actual results could
+differ from those estimates.
+PRINCIPLES OF CONSOLIDATION: The accompanying consolidated financial
+statements include the accounts of the Company and its wholly-owned
+subsidiaries, after elimination of all material intercompany accounts and
+transactions.
+CASH AND CASH EQUIVALENTS: The Company considers all highly liquid
+investments with a maturity date of three months or less at date of
+purchase to be cash equivalents.
+INVENTORIES: Inventories are stated at the lower of cost
+(principally standard cost which approximates actual cost on a first-in,
+first-out basis) or market.
+FIXED ASSETS: Fixed assets are stated at cost. Depreciation is
+provided for primarily by the straight-line method over the estimated
+useful lives. The estimated useful life of machinery, furniture and
+equipment is three to ten years. Leasehold improvements are amortized over
+the shorter of the term of the lease or the useful life of the asset.
+Depreciation amounted to $2,858,000, $2,176,000 and $1,699,000 in 2001,
+2000 and 1999, respectively. Depreciation for 2001 included $680,000 of
+accelerated depreciation on certain leasehold improvements and other fixed
+assets due to the closing of the Company's Wallingford, CT facility.
+20
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+GOODWILL: On July 20, 2001, the Financial Accounting Standards Board
+approved Statements of Financial Accounting Standards No. 141, "Business
+Combinations" ("FAS 141") and No. 142, "Goodwill and Other Intangible
+Assets" ("FAS 142").
+FAS 141 supercedes Accounting Principles Board Opinion ("APB") No.
+16, "Business Combinations." The most significant changes made by FAS 141
+are: (1) requiring that the purchase method of accounting be used for all
+business combinations initiated after June 30, 2001, (2) establishing
+specific criteria for the recognition of intangible assets separately from
+goodwill, and (3) requiring unallocated negative goodwill to be written
+off immediately as an extraordinary gain instead of being deferred and
+amortized.
+FAS 142 supercedes APB No. 17, "Intangibles Assets." FAS 142
+primarily addresses the accounting for goodwill and intangible assets
+subsequent to their acquisition. The provisions of FAS 142 will be
+effective for the Company for the year ended December 31, 2002. The most
+significant changes made by FAS 142 are: (1) goodwill and indefinite lived
+intangible assets will no longer be amortized, (2) goodwill will be tested
+for impairment at least annually at the reporting unit level, (3)
+intangible assets deemed to have an indefinite life will be tested for
+impairment at least annually, and (4) the amortization period of
+intangible assets with finite lives will no longer be limited to forty
+years.
+The Company has not entered into any business combinations
+subsequent to June 30, 2001. However, the Company is currently amortizing
+goodwill related to the acquisition of (i) Ithaca Peripherals, Inc.
+("Ithaca") in 1991 and the (ii) ribbon business formerly conducted by
+Tridex ("Tridex Ribbon Business"). The original amount applicable to the
+Ithaca acquisition totaled $3,536,000 and is being amortized on the
+straight-line method over 20 years. The original amount applicable to the
+Tridex Ribbon Business acquisition totaled $180,000 and is being amortized
+on the straight-line method over five years. Accumulated amortization of
+goodwill was $2,247,000 and $2,038,000 at December 31, 2001 and 2000,
+respectively. The Company believes there will be no impact upon the
+adoption of FAS 142.
+ACCRUED WARRANTY COSTS: The Company warranties its products for up
+to two years and records the estimated cost of such product warranties at
+the time the sale is recorded. Estimated warranty costs are based upon
+actual past experience of product returns and the related estimated cost
+of labor and material to make the necessary repairs.
+REVENUE RECOGNITION: Sales are recognized when evidence of an
+arrangement exists, delivery has occurred, the selling price is fixed and
+determinable, and collectibility is reasonably assured. Revenue from
+extended warranty and maintenance agreements is recognized over the term
+of such agreements as services are performed. Sales to GTECH Corporation
+("GTECH") (for lottery printers) accounted for approximately 33% of net
+sales during 2001. Sales to GTECH and ICL Pathway (for the British Post
+Office project) accounted for approximately 22% and 20% of net sales
+during 2000, respectively. No one customer accounted for more than 10% of
+net sales during 1999.
+FOREIGN CURRENCY: The financial position and results of operations
+of the Company's foreign subsidiaries are measured using local currency as
+the functional currency. Assets and liabilities of such subsidiaries have
+been translated at end of period exchange rates, and related revenues and
+expenses have been translated at weighted average exchange rates.
+Transaction gains (losses) are included in other income and amounted to
+$12,000, $(26,000) and $11,000 in 2001, 2000 and 1999, respectively.
+INCOME TAXES: The income tax amounts reflected in the accompanying
+financial statements are accounted for under the liability method in
+accordance with FAS 109 "Accounting for Income Taxes." Deferred tax assets
+and liabilities are recognized for the estimated future tax consequences
+attributable to differences between the financial statement carrying
+amounts of existing assets and liabilities and their respective tax bases
+and operating loss and tax credit carryforwards. Deferred tax assets and
+liabilities are measured using enacted tax rates in effect for the year in
+which those temporary differences are expected to be recovered or settled.
+21
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+STOCK-BASED COMPENSATION: The Company has elected to follow
+Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
+to Employees" ("APB 25"), and related interpretations in accounting for
+its stock options. Since the exercise price of employee stock options
+granted by the Company generally equals the market price of the underlying
+stock on the date of grant, no compensation expense is recorded. The
+Company has adopted the disclosure-only provisions of Statement of
+Financial Accounting Standards No. 123, "Accounting for Stock-Based
+Compensation" ("FAS 123"). See Note 11.
+SEGMENT REPORTING: FASB Statement of Financial Accounting Standards
+No. 131, "Disclosures about Segments of an Enterprise and Related
+Information" ("FAS 131") requires that a public business enterprise report
+financial and descriptive information about its reportable operating
+segments. Generally, financial information is required to be reported on
+the basis that it is used internally for evaluating segment performance
+and allocating resources. The Company has assessed its operating and
+reportable segments and determined that it operates in one reportable
+segment as defined in FAS 131.
+DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES: The Financial
+Accounting Standards Board ("FASB") issued Statement of Financial
+Standards No. 133, "Accounting for Derivative Instruments and Hedging
+Activities" ("FAS 133") in June 1998 which, as amended, is currently
+effective January 1, 2001 for the Company. The Company believes adoption
+of FAS 133 will not have a material impact on the Company's financial
+position, results of operations or cash flows.
+ASSET RETIREMENT OBLIGATIONS: In July 2001, the FASB issued
+Statement of Financial Standards No. 143, "Accounting for Asset Retirement
+Obligations" ("FAS 143). FAS 143 requires recognition of the fair value of
+liabilities associated with the retirement of long-lived assets when a
+legal obligation to incur such costs arises as a result of the
+acquisition, construction, development and/or the normal operation of a
+long-lived asset. FAS 143 is effective for fiscal years beginning after
+June 15, 2002. The Company does not expect that the issuance of FAS 143
+will have any impact on the Company's consolidated financial statements.
+IMPAIRMENT OF DISPOSAL OF LONG-LIVED ASSETS: In August 2001, the
+FASB issued Statement of Financial Standards No. 144, "Accounting for the
+Impairment or Disposal of Long-Lived Assets" ("FAS 144), which supercedes
+FAS 121, "Accounting for the Impairment of Long-Lived Assets and for
+Long-Lived Assets to be Disposed." FAS 144 requires that long-lived assets
+to be disposed of by sale, including discontinued operations, be measured
+at the lower of carrying amount or fair value less cost to sell, whether
+reported in continuing operations or in discontinued operations. The
+provisions of FAS 144 are effective for fiscal years beginning after
+December 15, 2001. The Company does not expect that the issuance of FAS
+144 will have any impact on the Company's consolidated financial
+statements.
+3. ACQUISITION
+On May 28, 1999, the Company acquired the business and substantially
+all the assets of the Tridex Ribbon Business for total cash consideration
+of approximately $295,000. The acquisition has been accounted for by the
+purchase method of accounting. The purchased assets and liabilities have
+been recorded in the Company's financial statements at their estimated
+fair values at the acquisition date. The results of operations of the
+acquired company have been included with those of the Company since the
+date of acquisition. The acquisition cost exceeded the fair value of the
+net assets acquired by $180,000. Such goodwill is being amortized over a
+five-year period on a straight-line basis. Prior to the acquisition, the
+Company provided Tridex with space within its Wallingford, CT
+manufacturing facility and certain support services for the Tridex Ribbon
+Business.
+22
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+4. RECEIVABLES
+Receivables are net of the allowance for doubtful accounts. The
+reconciliation of the allowance for doubtful accounts is as follows:
+Year Ended December 31,
+2001 2000 1999
+------ ------ ------
+(In thousands)
+Balance at beginning of period $ 107 $ 132 $ 139
+Doubtful accounts provision (reversal) 45 (24) --
+Accounts written off, net of recoveries (68) (1) (7)
+------ ------ ------
+Balance at end of period $ 84 $ 107 $ 132
+====== ====== ======
+5. INVENTORIES
+The components of inventories are:
+December 31,
+(In thousands) 2001 2000
+-------- --------
+Raw materials and component parts $ 10,299 $ 9,603
+Work-in-process 25 200
+Finished goods 309 54
+-------- --------
+$ 10,633 $ 9,857
+======== ========
+6. FIXED ASSETS
+The components of fixed assets are:
+December 31,
+(In thousands) 2001 2000
+-------- --------
+Tooling, machinery and equipment $ 11,295 $ 10,974
+Furniture, office and computer equipment 4,107 4,243
+Leasehold improvements 794 749
+16,196 15,966
+Less: accumulated depreciation (11,006) (9,090)
+-------- --------
+$ 5,190 $ 6,876
+======== ========
+7. ACCRUED LIABILITIES
+The components of accrued liabilities are:
+December 31,
+(In thousands) 2001 2000
+-------- --------
+Payroll and fringe benefits $ 533 $ 382
+Income taxes 604 765
+Warranty 710 657
+Deferred revenue 551 108
+Rent 290 292
+Other 632 372
+-------- --------
+$ 3,320 $ 2,576
+======== ========
+23
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+8. ACCRUED BUSINESS CONSOLIDATION AND RESTRUCTURING EXPENSES
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part
+of this strategic decision, the Company undertook a plan to consolidate
+all manufacturing and engineering into its existing Ithaca, NY facility
+and close its Wallingford, CT facility (the "Consolidation"). As of
+December 31, 2001, substantially all Wallingford product lines were
+successfully transferred to Ithaca, NY. The Company expects to maintain
+one small component production line in Wallingford until May 2002, after
+which the manufacturing facility will be closed. The closing of the
+Wallingford facility is expected to result in the termination of
+employment of approximately 70 production, administrative and management
+employees. The Company has applied the consensus set forth in EITF 94-3,
+"Liability Recognition for Certain Employee Termination Benefits and Other
+Costs to Exit an Activity (Including Certain Costs Incurred in a
+Restructuring)" in recognizing the accrued restructuring expenses. The
+Company estimates that the non-recurring costs associated with the
+Consolidation, including severance pay, stay bonuses, employee benefits,
+moving expenses, non-cancelable lease payments, accelerated depreciation
+and other costs, will be approximately $4.2 million, of which
+approximately $4.1 million was recognized during 2001.
+During the fourth quarter of 2000, the Company recorded a
+restructuring charge of $189,000 for severance costs related to the
+downsizing and reorganization of its manufacturing facility in
+Wallingford, CT. Severance costs resulted from the reduction of 11
+employees.
+The following table summarizes the activity recorded in the
+restructuring accrual during 2001 and 2000.
+Year ended Year ended
+December 31, December 31,
+(In thousands) 2001 2000
+------------ ------------
+Accrual balance, beginning of year $ 105 $ --
+-------- --------
+Business consolidation and restructuring expenses:
+Employee severance and termination expenses (1) 2,070 189
+Facility closure and consolidation expenses (2) 1,251 --
+-------- --------
+3,321 189
+-------- --------
+Cash payments (424) (84)
+-------- --------
+Accrual balance, end of year $ 3,002 $ 105
+======== ========
+(1) Employee severance and termination related expenses are the
+estimated termination salaries, benefits, outplacement, counseling
+services and other related costs expected to be paid to employees
+who will be involuntarily terminated.
+(2) Facility closure and consolidation expenses are the estimated costs
+to close the Wallingford, CT facility including lease termination
+costs and other related costs, in accordance with the restructuring
+plan. The Wallingford facility closure was substantially completed
+by December 31, 2001.
+The following table summarizes the components of all charges related
+to the Consolidation.
+Year ended Year ended
+December 31, December 31,
+(In thousands) 2001 2000
+------------ ------------
+Business consolidation and restructuring expenses $ 3,321 $ 189
+Accelerated depreciation and asset disposal losses (1) 775 --
+-------- --------
+Total business consolidation, restructuring and
+related charges $ 4,096 $ 189
+======== ========
+(1) Represents accelerated depreciation ($680) and asset disposal losses
+($95) on certain leasehold improvements and other fixed assets, due
+to the closing of the Wallingford facility. These charges are
+included in general and administrative expenses.
+24
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+9. EMPLOYEE BENEFIT PLANS
+RETIREMENT SAVINGS PLAN: On April 1, 1997, the Company established
+the TransAct Technologies Retirement Savings Plan (the "401(k) Plan"), a
+defined contribution plan under Section 401(k) of the Internal Revenue
+Code. All full-time employees are eligible to participate in the 401(k)
+Plan at the beginning of the calendar quarter immediately following their
+date of hire. The Company matches employees' contributions at a rate of
+50% of employees' contributions up to the first 6% of the employees'
+compensation contributed to the 401(k) Plan. The Company's matching
+contributions were $204,000, $203,000 and $145,000 in 2001, 2000 and 1999,
+respectively. During 1999 and 1998, the Company's rate of matching
+contributions was 50% of the employees' contributions up to the first 5%
+and 4% of the employees' compensation contributed to the 401(k) Plan,
+respectively.
+EMPLOYEE STOCK PURCHASE PLAN: In May 2000, the Company's
+shareholders approved the Employee Stock Purchase Plan (the "ESPP"), under
+which 50,000 shares of the Company's common stock are available for
+issuance to employees beginning June 1, 2000. All full-time employees are
+eligible to participate in the ESPP at the beginning of each six-month
+period (the "Offering Period"), which begin on June 1 and December 1.
+Eligible employees may elect to withhold up to 5% of their salary to
+purchase shares of the Company's common stock at a price equal to 85% of
+the fair market value of the stock on the first or last day of each
+Offering Period, whichever is lower. The ESPP will terminate at the
+earlier of May 31, 2005 or the date on which all 50,000 shares available
+for issuance under the ESPP have been sold. The Company sold 6,443 and
+4,827 shares of common stock under the ESPP during 2001 and 2000,
+respectively. At December 31, 2001, 38,730 shares remained available for
+sale. Compensation costs related to the ESPP are immaterial.
+10. BORROWINGS
+On March 14, 2000, the Company entered into a two-year $13,000,000
+revolving credit facility (the "Fleet Credit Facility") with Fleet Bank
+("Fleet"). The Fleet Credit Facility replaced a previous credit facility
+also with Fleet. The Fleet Credit Facility provided the Company with a
+$13,000,000 credit facility used to fund working capital. Borrowings under
+the Fleet Credit facility bore interest on outstanding borrowings at
+Fleet's prime rate plus a margin ranging from zero to 0.75 percentage
+points and bore a commitment fee ranging from 0.375% to 0.75% on any
+unused portion of the Fleet Credit Facility. The Fleet Credit Facility
+also permitted the Company to designate a LIBOR rate on outstanding
+borrowings with a margin ranging from 1.5 to 3.0 percentage points over
+the market rate, depending on the Company meeting certain ratios. The
+Fleet Credit Facility was secured by a lien on substantially all the
+assets of the Company, imposed certain financial covenants and restricted
+the creation of liens.
+On September 21, 2000, the Company entered into a two-year revolving
+credit facility (the "Webster Credit Facility) with Webster Bank
+("Webster") expiring on September 21, 2002. The Webster Credit Facility
+replaced the Fleet Credit Facility. Under the Webster Credit Facility, the
+Company may borrow up to $12 million, based on certain financial criteria
+of the Company at the time of any borrowing, to fund working capital.
+Borrowings under the Webster Credit Facility bear a floating rate of
+interest at the higher of the "Prime Rate" as published in The Wall Street
+Journal or one-half of one percent (1/2%) over the federal funds rate (as
+defined in the Webster Credit Facility) (9.5% at December 31, 2000). Under
+certain circumstances, the Company may select a fixed interest rate for a
+specified period of up to 90 days on borrowings based on the current LIBOR
+rate (as adjusted as specified in the Webster Credit Facility) plus 2.5%,
+which may be reduced to 2.25% on July 1, 2001 if there is no Event of
+Default (as defined in the Webster Credit Facility). The Company will also
+pay a fee of three-eighths of one percent (3/8%) on unused borrowing
+capacity under the Webster Credit Facility. Borrowings under the Webster
+Credit Facility are secured by a lien on substantially all the assets of
+the Company. The Webster Credit facility also imposes certain financial
+covenants on the Company and restricts the payment of dividends on its
+common stock and the creation of other liens. The Company had $5,944,000
+of outstanding borrowings under this facility at December 31, 2000.
+On February 27, 2001, the Company amended the Webster Credit
+Facility to (1) provide the Company with the ability to borrow up to
+$1,500,000 in excess of the amount permitted under the Webster Credit
+Facility's borrowing base formula ("Permitted Over-Formula Borrowing") and
+(2) revise certain financial covenants. The Permitted Over-Formula
+Borrowing is effective from March 1, 2001 through August 31, 2001.
+25
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+10. BORROWINGS (CONTINUED)
+On May 25, 2001, the Company entered into a new, three-year, $13.5
+million credit facility (the "LaSalle Credit Facility") with LaSalle
+Business Credit, Inc. ("LaSalle") expiring on May 25, 2004. The LaSalle
+Credit Facility replaced the Webster Credit Facility. The LaSalle Credit
+Facility provides a $12 million revolving credit line, a $0.5 million term
+loan and a $1 million equipment loan facility. Borrowings under the
+revolving credit line bear a floating rate of interest at LaSalle's prime
+rate. Borrowings under both the term loan and equipment loan bear a
+floating rate of interest at LaSalle's prime rate plus 0.50%. Under
+certain circumstances, the Company may select a fixed interest rate for a
+specified period of time of up to 180 days on borrowings based on the
+current LIBOR rate plus 2.50% and 3.0% under the revolving credit line
+facility, and the term and equipment loan facilities, respectively. The
+Company also pays a fee of 0.25% on unused borrowings under the revolving
+credit line and equipment loan facilities. Borrowings under the LaSalle
+Credit Facility are secured by a lien on all the personal property assets
+of the Company. The LaSalle Credit Facility also imposes certain financial
+covenants on the Company and restricts the payment of dividends on its
+common stock and the creation of other liens. Concurrent with the signing
+of the LaSalle Credit Facility, the Company borrowed $500,000 under the
+term loan. Principal installment payments for the term loan of $8,333,
+plus accrued interest, are due on the first day of each month beginning
+July 1, 2001, with the unpaid principal balance due on May 25, 2004. The
+Company had no borrowings under the equipment loan during 2001.
+On October 30, 2001, the Company amended the LaSalle Credit
+Facility. Under the terms of the amendment ("LaSalle Amendment No.1"),
+LaSalle (1) waived compliance with the minimum EBITDA financial covenant
+as of September 30, 2001, (2) revised certain other financial covenants
+through December 31, 2001, (3) increased the floating rate of interest on
+borrowings under the revolving credit line to LaSalle's prime rate plus
+1.0% (5.75% at December 31, 2001), or the current LIBOR rate plus 3.5%,
+and (4) increased the floating rate of interest on borrowings under the
+term loan and equipment loan to LaSalle's prime rate plus 1.5% (6.25% at
+December 31, 2001), or the current LIBOR rate plus 4.0%. Upon execution of
+LaSalle Amendment No. 1, the Company paid a fee of $20,000 to LaSalle.
+On December 21, 2001, the Company amended the LaSalle Credit
+Facility to reset certain financial covenants for 2002 and beyond
+("LaSalle Amendment No. 2). Upon execution of LaSalle Amendment No. 2, the
+Company paid a fee of $5,000 to LaSalle. As of December 31, 2001, the
+Company had $4,994,000 and $450,000 outstanding on the revolving credit
+line and term loan, respectively, and no borrowings outstanding on the
+equipment loan.
+11. COMMITMENTS AND CONTINGENCIES
+At December 31, 2001, the Company was lessee on operating leases for
+equipment and real property. The terms of certain leases provide for
+escalating rent payments in later years of the lease as well as payment of
+minimum rent and real estate taxes. Rent expense amounted to approximately
+$983,000, $991,000 and $953,000 in 2001, 2000 and 1999, respectively.
+Minimum aggregate rental payments required under operating leases that
+have initial or remaining non-cancelable lease terms in excess of one year
+as of December 31, 2001 are as follows: $873,000 in 2002; $875,000 in
+2003; $855,000 in 2004; $868,000 in 2005; $877,000 in 2006 and $786,000
+thereafter.
+12. STOCK INCENTIVE PLANS AND WARRANTS
+STOCK INCENTIVE PLANS. The Company currently has three primary stock
+incentive plans: the 1996 Stock Plan which provides for the grant of
+awards to officers and other key employees of the Company, the 1996
+Directors' Stock Plan which provides for non-discretionary awards to
+non-employee directors, and the 2001 Employee Stock Plan which provides
+for the grant of awards to key employees of the Company and other
+non-employees who may provide services to the Company. The plans generally
+provide for awards in the form of: (i) incentive stock options, (ii)
+non-qualified stock options, (iii) shares of restricted stock, (iv)
+restricted units, (v) stock appreciation rights or (vi) limited stock
+appreciation rights. However, the 2001 Employee Stock Plan does not
+provide for incentive stock option awards. Options granted under these
+plans are at prices equal to 100% of the fair market value of the common
+stock at the date of grant. Options granted have a ten-year term and
+generally vest over a three- to five-year period, unless automatically
+accelerated for certain defined events. At December 31, 2001, the Company
+has reserved 1,150,000, 110,000 and 150,000 shares of common stock for
+issuance under the 1996 Stock Plan, the 1996 Directors' Stock Plan, and
+the 2001 Employees Stock Plan, respectively.
+26
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+12. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+OPTION EXCHANGE OFFER. In November 2001, the Company announced an
+offer to certain officers to exchange outstanding employee stock options
+having an exercise price of $9.00 or more per share in return for new
+stock options to be granted by the Company (the "Exchange Offer").
+Pursuant to the Exchange Offer, the option holder received a commitment
+for the grant of one new option for each option tendered and accepted for
+exchange, no sooner than six months and one day from November 16, 2001. A
+total of 215,000 options were accepted for exchange under the Exchange
+Offer and were canceled in November 2001 (and treated as canceled in 2001
+in the table below). The new option grants of 215,000 are expected to be
+granted no sooner than May 17, 2002, and will vest 25% immediately upon
+grant with the remainder vesting 25% annually over the next three years.
+The new options will have an exercise price equal to the fair market value
+of the Company's common stock on the date of grant.
+The 1996 Stock Plan, 1996 Directors' Stock Plan and 2001 Employee
+Stock Plan option activity is summarized below:
+Year Ended December 31,
+2001 2000 1999
+----------------------- ----------------------- -----------------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+-------- -------- -------- -------- -------- --------
+Outstanding at beginning of
+period: 919,000 $8.34 818,100 $7.89 752,300 $8.04
+Granted 189,500 5.67 190,500 9.86 104,500 5.86
+Exercised (53,500) 4.37 (25,000) 6.05 (5,100) 4.75
+Canceled (312,250) 10.71 (64,600) 7.53 (33,600) 5.07
+-------- -------- -------- -------- -------- --------
+Outstanding at end of period 742,750 $6.95 919,000 $8.34 818,100 $7.89
+======== ======== ======== ======== ======== ========
+Options exercisable at end of
+period 383,350 $7.34 436,580 $8.19 296,140 $8.33
+======== ======== ======== ======== ======== ========
+Options Outstanding Options Exercisable
+------------------------------------------- -------------------------
+Weighted- Weighted- Weighted-
+Outstanding at Average Average Exercisable at Average
+December 31, Exercise Remaining December 31, Exercise
+Range of Exercise Prices 2001 Price Contractual Life 2001 Price
+-------------- --------- ---------------- -------------- ---------
+(In years)
+$ 2.50 - $ 5.00 203,200 $4.34 5.5 120,100 $4.38
+5.01 - 7.50 184,700 5.55 8.0 28,300 6.20
+7.51 - 10.00 277,200 8.69 4.9 203,800 8.58
+10.01 - 12.50 64,650 10.31 6.4 20,750 10.59
+12.51 - 15.00 12,000 13.75 2.3 9,600 13.75
+15.01 - 17.50 1,000 16.38 0.4 800 16.38
+The Company applies APB 25 and related interpretations in accounting
+for its long-term incentive stock plans. Accordingly, no compensation cost
+has been recognized for its stock options.
+Had compensation expense been recognized based on the fair value of
+the options at their grant dates, as prescribed in FAS 123, the Company's
+net income (loss) and net income (loss) per share would have been as
+follows:
+27
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+12. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+Year Ended December 31,
+2001 2000 1999
+-------- -------- --------
+(In thousands, except per share data)
+Net income (loss) available to common shareholders:
+As reported $ (5,280) $ (664) $ 324
+Pro forma under FAS 123 (5,981) (1,171) (422)
+Net income (loss) per share:
+Basic and diluted:
+As reported (0.95) (0.12) 0.06
+Pro forma under FAS 123 (1.08) (0.21) (0.08)
+The fair value of each option grant is estimated on the date of
+grant using the Black-Scholes option pricing model with the following
+assumptions used for the grants made during the years ended December 31,
+2001, 2000 and 1999.
+Year Ended December 31,
+2001 2000 1999
+-------- -------- --------
+Risk-free interest rate 4.6% 6.3% 5.8%
+Dividend yield 0% 0% 0%
+Expected volatility factor 85.5% 83.1% 78.0%
+Expected option term 6.1 years 7.1 years 7.5 years
+Weighted average fair value of options granted during period $ 4.25 $ 7.78 $ 4.55
+RESTRICTED STOCK: Under the 1996 Stock Plan, the Company has granted
+shares of restricted common stock, for no consideration, to its officers,
+one outside director and certain key employees. The 1996 Stock Plan
+restricted stock activity is summarized below:
+Year Ended December 31,
+2001 2000 1999
+-------- -------- --------
+Outstanding shares at beginning of period 83,320 95,080 91,440
+Granted 20,000 5,000 13,000
+Vested (10,960) (12,960) (9,360)
+Canceled (3,000) (3,800) --
+-------- -------- --------
+Outstanding shares at end of period 89,360 83,320 95,080
+======== ======== ========
+The weighted average fair value of restricted stock granted was
+$4.75, $8.75 and $7.50 for 2001, 2000 and 1999, respectively. Of the
+89,360 shares of restricted stock outstanding at December 31, 2001, 15,360
+shares vest over a five-year period, 54,000 shares vest at the end of a
+five-year period, 10,000 shares vest over a three-year period and 10,000
+shares vest over a two-year period. Under certain conditions, vesting may
+be automatically accelerated. Upon issuance of the restricted stock,
+unearned compensation equivalent to the market value at the date of grant
+is charged to a separate component of shareholders' equity and
+subsequently amortized over the vesting period. Amortization expense of
+$264,000, $277,000 and $254,000 was recorded during 2001, 2000 and 1999,
+respectively.
+WARRANTS: On August 22, 1996, the Company sold to the underwriters
+of its initial public offering, for nominal consideration, a warrant to
+purchase from the Company up to 115,000 shares of common stock at an
+exercise price of $10.20 per share. The warrant expired on August 20,
+2001.
+On April 7, 2000, in connection with the sale of the Preferred
+Stock, the Company issued to its investment advisors, McFarland Dewey &
+Co., warrants to purchase from the Company up to 10,000 shares of common
+stock at an exercise price of $9.00 per share. The warrants are
+exercisable through April 7, 2005.
+28
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. STOCKHOLDER RIGHTS PLAN
+In December 1997, the Board of Directors adopted a Stockholder
+Rights Plan declaring a distribution of one right (the "Rights") for each
+outstanding share of the Company's common stock to shareholders of record
+at December 15, 1997. Initially, each of the Rights will entitle the
+registered holder to purchase from the Company one one-thousandth of a
+share of Series A Preferred Stock, $0.01 par value, at a price of $69 per
+one one-thousandth of a share. The Rights, however, will not become
+exercisable unless and until, among other things, any person or group of
+affiliated persons acquires beneficial ownership of 15 percent or more of
+the then outstanding shares of the Company's Common Stock. If a person, or
+group of persons, acquires 15 percent or more of the outstanding Common
+Stock of the Company (subject to certain conditions and exceptions more
+fully described in the Rights Agreement), each Right will entitle the
+holder (other than the person, or group of persons, who acquired 15
+percent or more of the outstanding Common Stock) to purchase Preferred
+Stock of the Company having a market value equal to twice the exercise
+price of the Right. The Rights are redeemable, under certain
+circumstances, for $0.0001 per Right and will expire, unless earlier
+redeemed, on December 2, 2007.
+On February 16, 1999, the Company amended its Stockholder Rights
+Plan to remove the provision in the plan that stipulated that the plan may
+be modified or redeemed only by those members of the Board of Directors
+who are defined as continuing directors.
+14. INCOME TAXES
+The components of the income tax provision are as follows:
+Year Ended December 31,
+(In thousands) 2001 2000 1999
+-------- -------- --------
+Current:
+Federal $ (62) $ (561) $ 88
+State -- 43 18
+-------- -------- --------
+Foreign 56 194 12
+-------- -------- --------
+(6) (324) 118
+Deferred:
+Federal (2,523) (94) (37)
+State (219) (34) 18
+Foreign -- 4 3
+-------- -------- --------
+(2,742) (124) (16)
+-------- -------- --------
+Total income tax provision (benefit) $ (2,748) $ (448) $ 102
+======== ======== ========
+At December 31, 2001, the Company has $1,754,000 of federal net
+operating loss carryforwards that begin to expire in 2021, and $3,526,000
+of state net operating loss carryforwards that begin to expire in 2005.
+The Company also has approximately $147,000 in federal research and
+development tax credit carryforwards that expire in 2020. The Company had
+foreign income before taxes of $232,000, $665,000 and $65,000 in 2001,
+2000 and 1999, respectively.
+Deferred income taxes arise from temporary differences between the
+tax basis of assets and liabilities and their reported amounts in the
+financial statements. The Company's gross deferred tax assets and
+liabilities were comprised of the following:
+29
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+14. INCOME TAXES (CONTINUED)
+December 31,
+(In thousands) 2001 2000
+------ ------
+Gross deferred tax assets:
+Net operating losses $ 700 $ 39
+Accrued restructuring expenses 1,109 46
+Other liabilities and reserves 1,693 1,350
+------ ------
+$3,502 $1,435
+====== ======
+Gross deferred tax liabilities:
+Depreciation $ -- $ 576
+====== ======
+The gross deferred tax asset is largely the result of the Company's
+net operating loss in 2001 due to the Consolidation. Based on recent tax
+law changes, the Company will carry back its federal net operating losses
+to prior years, which is expected to result in a tax refund of
+approximately $700,000 in 2002. Based on annual cost savings expected to
+be realized as a result of the Consolidation, future financial projections
+and the ability to carry back net operating losses, the Company has
+determined that no valuation allowance is considered necessary.
+Differences between the U.S. statutory federal income tax rate and
+the Company's effective income tax rate are analyzed below:
+Year Ended December 31,
+2001 2000 1999
+------ ------ ------
+Federal statutory tax rate (34.0)% (34.0)% 34.0%
+State income taxes, net of federal income taxes (0.9) (0.3) 13.2
+Non-deductible purchase accounting adjustments 1.6 9.9 41.6
+Tax benefit from foreign sales corporation -- (3.1) --
+Tax benefit from tax credits (1.7) (22.9) (60.0)
+Foreign rate differential -- (3.5) (1.6)
+Other (0.8) (2.7) (3.2)
+------ ------ ------
+Effective tax rate (35.8)% (56.6)% 24.0%
+====== ====== ======
+15. DISCLOSURE REGARDING FAIR VALUE OF FINANCIAL INSTRUMENTS
+The carrying amount for cash and cash equivalents approximates fair
+value because of the short maturity of these instruments. The carrying
+amount of receivables, other current assets, other assets, accounts
+payable and accrued liabilities is a reasonable estimate of fair value
+because of the short nature of the transactions. The carrying value of
+long-term debt approximates the fair value based upon the variable rate on
+that debt.
+Off-balance sheet derivative financial instruments include
+interest-rate swaps. At December 31, 1999, interest-rate swaps, held for
+purposes other than trading, had a fair value settlement of $35,000, based
+on the underlying principal amount of $3,000,000. The Company sold its
+interest-rate swap during 2000.
+30
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+16. SIGNIFICANT TRANSACTIONS
+PREFERRED STOCK SALE: On April 7, 2000 the Company sold 4,000 shares
+of 7% Series B Cumulative Convertible Redeemable Preferred Stock (the
+"Preferred Stock") to Advance Capital Advisors, L.P. and its affiliate in
+consideration of $1,000 per share (the "Stated Value"), for a total of
+$4,000,000, less issuance costs. The Preferred Stock is convertible at any
+time by the holders at a conversion price of $9.00 per common share. In
+addition, the Company issued warrants pro-rata to the Preferred Stock
+holders to purchase an aggregate of 44,444 shares of the Company's common
+stock at an exercise price of $9.00 per common share. The warrants, valued
+at $175,000, are exercisable at any time until April 7, 2005, and will be
+accreted to preferred stock ratably over 60 months. The Preferred Stock is
+subject to mandatory conversion into shares of the Company's common stock
+when such stock has traded at $35 per share or more for a 30-day period
+ending on or after April 7, 2003, or for a 60-day period beginning on or
+after April 7, 2002. The Preferred Stock is redeemable at the option of
+the holders on April 7, 2005 at $1,000 per share plus any unpaid
+dividends. On or after April 7, 2007, the Company has the right to require
+(1) redemption of the Preferred Stock at $1,000 per share plus any unpaid
+dividends or (2) conversion of the Preferred Stock at $9.00 per common
+share. Upon a change of control (which the Company does not believe
+probable), holders have the right to redeem the Preferred Stock for 200%
+of the Stated Value plus any unpaid dividends. The holders of the
+Preferred Stock have certain voting rights and are entitled to receive a
+cumulative annual dividend of $70 per share, payable quarterly and have
+preference to any other dividends, if any, paid by the Company.
+Concurrent with the issuance of the Preferred Stock, the Company
+recorded a beneficial conversion charge. The beneficial conversion charge
+was calculated as the difference between the assigned fair value of the
+Preferred Stock and the fair value of the related common stock, as of
+April 7, 2000, into which the Preferred Stock was immediately convertible.
+Accordingly, a deemed preferred dividend of approximately $56,000 as of
+the issuance date has been recognized as a charge to retained earnings and
+net loss attributable to common shareholders, and as an increase to
+additional paid-in capital.
+GTECH LAWSUIT SETTLEMENT: On June 25, 1999, the Company commenced a
+lawsuit in the United States District Court for the District of Rhode
+Island against GTECH for misappropriation of trade secrets, breach of
+contract and related claims, seeking injunctive relief and compensatory
+and punitive damages. On July 15, 1999, GTECH and the Company signed a new
+five-year agreement under which the Company will be the exclusive
+manufacturer and supplier to GTECH of an impact printer for use in GTECH's
+Isys(R) online lottery terminal. As part of the agreement, GTECH agreed to
+pay the Company $1 million for past design efforts, development costs and
+manufacturing interruption costs and agreed to place a non-cancelable
+order for delivery of a minimum of approximately $8 million of printers in
+the year 2000. In connection with the execution of this agreement, the
+parties agreed to have all claims under the lawsuits dismissed and filed
+dismissal stipulations to terminate the federal and state lawsuits. As a
+result of the settlement, the Company reported $770,000 ($1 million cash
+settlement, less $230,000 of directly-related expenses) in other income
+during 1999.
+LOAN TO OFFICER: On February 23, 1999, with the Board of Directors'
+approval, the Company provided a $330,000 loan to an officer of the
+Company. The loan proceeds were used to purchase 104,000 shares of the
+Company's common stock on the open market during January and February
+1999. The loan is payable on February 23, 2004, and is a full recourse
+obligation to the officer collateralized by 154,000 shares of the
+Company's common stock, which includes 50,000 shares of restricted stock.
+The loan currently bears compounded interest at a rate equivalent to the
+Company's average borrowing rate under its current credit facility.
+Accrued interest through 2002 is deferred until maturity. The principal
+amount of the loan is deducted from shareholders' equity.
+STOCK REPURCHASE PROGRAM: Under a stock repurchase program, the
+Company acquired 70,800 shares of its common stock for $229,000 in 1999.
+The Company has not repurchased any shares since 1999, and management does
+not expect to repurchase any additional shares in the foreseeable future.
+31
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+17. INTERNATIONAL OPERATIONS
+The Company has foreign operations primarily from TransAct
+Technologies Ltd., a wholly-owned subsidiary, which had sales to its
+customers of $1,791,000, $11,164,000 and $700,000 in the year ended
+December 31, 2001, 2000 and 1999, respectively. The Company had export
+sales to its foreign customers from the United States of approximately
+$6,131,000, $5,156,000 and $7,807,000 in the year ended December 31, 2001,
+2000 and 1999, respectively.
+18. SUBSEQUENT EVENTS (UNAUDITED)
+On February 22, 2002, at the request of a major customer, the
+Company received a cash payment of approximately $5,800,000 in advance of
+printer shipments to be made from March through August 2002. This amount
+has been classified as a current liability, and will be reduced by the
+sales value of shipments as they are made. As a result of this payment,
+the Company repaid all its outstanding revolving borrowings under the
+LaSalle Credit Facility in February 2002.
+19. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
+The Company's quarterly results of operations for the years ended
+December 31, 2001, 2000 and 1999 (unaudited) are as follows:
+Quarter Ended
+------------------------------------------------
+(In thousands, except per share amounts) March 31 June 30 September 30 December 31
+-------- -------- ------------ -----------
+2001:
+Net sales $9,773 $10,796 $ 13,234 $ 10,171
+Gross profit 1,803 2,413 3,570 1,988
+Net loss (1,757) (1,220) (162) (1,783)
+Net loss available to common shareholders (1,847) (1,309) (252) (1,872)
+Net loss per share:
+Basic and diluted (0.33) (0.24) (0.05) (0.34)
+March 25 June 24 September 23 December 31
+-------- -------- ------------ -----------
+2000:
+Net sales $11,238 $13,740 $ 14,604 $ 14,138
+Gross profit 3,013 3,665 3,867 3,597
+Net income (loss) (300) (186) 290 (148)
+Net income (loss) available to common Shareholders (300) (326) 200 (238)
+Net income (loss) per share:
+Basic and diluted (0.05) (0.06) 0.04 (0.04)
+March 27 June 26 September 25 December 31
+-------- -------- ------------ -----------
+1999:
+Net sales $9,201 $12,524 $ 13,020 $ 10,144
+Gross profit 2,428 3,238 3,335 2,753
+Net income (loss) (279) 146 837 (380)
+Net income (loss) per share:
+Basic and diluted (0.05) 0.03 0.15 (0.07)
+32
+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.
+Information contained in "Election of Directors" and "Section 16(a)
+Beneficial Ownership Reporting Compliance" of the Company's Proxy Statement (the
+"Proxy Statement") for its Annual Meeting of Shareholders which is scheduled to
+be held on May 17, 2002 is hereby incorporated herein by reference. Also, see
+information under "Executive Officers of Registrant" in Item 1.
+ITEM 11. EXECUTIVE COMPENSATION.
+The information contained in "Executive Compensation" other than the
+"Compensation Committee Report on Executive Compensation" of the Proxy Statement
+is hereby incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
+The information contained in "Security Ownership of Certain Beneficial
+Owners and Management" of the Proxy Statement is hereby incorporated herein by
+reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
+33
+PART IV
+ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
+(A) THE FOLLOWING FINANCIAL STATEMENTS AND EXHIBITS ARE FILED AS PART OF
+THIS REPORT:
+Financial statements
+(i) See Item 8.
+(ii) Financial statement schedules
+All schedules are omitted since the required information is
+either (a) not present or not present in amounts sufficient to
+require submission of the schedule or (b) included in the
+financial statements or notes thereto.
+34
+(iii) List of exhibits
+3.1(a) Certificate of Incorporation of the
+Company, filed with the Secretary of State
+of Delaware on June 17, 1996. (2)
+3.1(b) Certificate of Amendment of Certificate of (4)
+Incorporation of the Company, filed with
+the Secretary of State of Delaware on May
+30, 1997.
+3.2 Amended and Restated By-laws of the Company. (6)
+4.1 Specimen Common Stock Certificate. (2)
+4.2 Amended and Restated Rights Agreement (5)
+between TransAct and American Stock
+Transfer & Trust Company dated February
+16, 1998.
+10.1 Tax Sharing Agreement dated as of July 31, (3)
+1996 between Tridex and TransAct.
+10.2(x) 1996 Stock Plan, effective July 30, 1996. (3)
+10.3(x) Non-Employee Directors' Stock Plan, (3)
+effective August 22, 1996.
+10.4(x) 2000 Employee Stock Purchase Plan (9)
+10.5(x) 2001 Employee Stock Plan (11)
+10.6 Lease Agreement by and between Bomax (2)
+Properties and Ithaca, dated as of March
+23, 1992.
+10.7 Second Amendment to Lease Agreement by and (4)
+between Bomax Properties and Ithaca, dated
+December 2, 1996.
+10.8 Agreement regarding the Continuation and (1)
+Renewal of Lease by and between Bomax
+Properties, LLC and TransAct, dated July
+18, 2001.
+10.9 Lease Agreement by and between Pyramid (4)
+Construction Company and Magnetec, dated
+July 30, 1997.
+10.10(x) Employment Agreement, dated July 31, 1996, (2)
+by and between the Company and Bart C.
+Shuldman.
+10.11(x) Employment Agreement, dated July 31, 1996, (2)
+by and between the Company and Richard L.
+Cote.
+10.12(x) Severance Agreement by and between (3)
+TransAct and Lucy H. Staley, dated
+September 4, 1996.
+10.13(x) Release and Settlement Agreement by and (1)
+between TransAct and Lucy H. Staley, dated
+December 4, 2001
+10.14(x) Severance Agreement by and between (3)
+TransAct and Michael S. Kumpf, dated
+September 4, 1996.
+10.15(x) Severance Agreement by and between (6)
+TransAct and Steven A. DeMartino, dated
+January 21, 1998.
+10.16(x) Severance Agreement by and between (10)
+TransAct and Mark Goebel, dated July 31,
+1996.
+10.17(x) Release and Settlement Agreement by and (1)
+between TransAct and Mark Goebel, dated
+March 1, 2002
+10.18(x) Severance Agreement by and between (10)
+TransAct and James B. Stetson, dated
+January 24, 2001.
+10.19 Loan Agreement by and between the Company
+and Bart C. Shuldman, dated July 1, 2001 (1)
+10.20 OEM Purchase Agreement by and between (7)
+GTECH Corporation, TransAct Technologies
+and Magnetec Corporation commencing July
+14, 1999. (Pursuant to Rule 24-b-2 under
+the Exchange Act, the Company has
+requested confidential treatment of
+portions of this exhibit deleted from the
+filed copy.)
+35
+10.21 OEM Purchase Agreement by and between (1)
+Okidata Americas, Inc. and TransAct,
+dated June 8, 2001. (Pursuant to Rule
+24b-2 under the Exchange Act,
+the Company has requested confidential
+treatment of portions of this exhibit
+exhibit deleted from the filed copy.)
+10.22 Preferred Stock Purchase Agreement and (8)
+Certificate of Designation dated as of
+March 20, 2000 between TransAct
+Technologies Incorporated and Advance
+Capital Partners, L.P. and affiliate
+10.23 Loan and Security Agreement dated as of (12)
+May 25, 2001 among TransAct, LaSalle
+Business Credit, Inc. ("LaSalle") and the
+institutions from time to time a party
+hereto.
+10.24 Waiver and Amendment No. 1 to Loan and (13)
+Security Agreement dated as of May 25,
+2001 among TransAct, LaSalle and the
+institutions from time to time a party
+hereto.
+10.25 Amendment No. 2 to Loan and Security (1)
+Agreement dated as of May 25, 2001 among
+TransAct, LaSalle and the institutions
+from time to time a party hereto.
+11.1 Computation of earnings per share. (1)
+21.1 Subsidiaries of the Company. (1)
+23.1 Consent of PricewaterhouseCoopers LLP. (1)
+(1) These exhibits are filed herewith.
+(2) These exhibits, which were previously filed with the
+Company's Registration Statement on Form S-1 (No.
+333-06895), are incorporated by reference.
+(3) These exhibits, which were previously filed with the
+Company's Quarterly Report on Form 10-Q for the period
+ended September 30, 1996, are incorporated by reference.
+(4) These exhibits, which were previously filed with the
+Company's Annual Report on Form 10-K for the year ended
+December 31, 1997, are incorporated by reference.
+(5) This exhibit, which was previously filed with the
+Company's Current Report on Form 8-K filed February 18,
+1999, is incorporated by reference.
+(6) These exhibits, which were previously filed with the
+Company's Annual Report on Form 10-K for the year ended
+December 31, 1998, are incorporated by reference.
+(7) This exhibit, which was previously filed with the
+Company's Quarterly Report on Form 10-Q for the period
+ended September 25, 1999, is incorporated by reference.
+(8) This exhibit, which was previously filed with the
+Company's Quarterly Report on Form 10-Q for the period
+ended March 25, 2000, is incorporated by reference.
+(9) This exhibit, which was previously filed with the
+Company's Registration Statement on Form S-8 (No.
+333-49540), is incorporated by reference.
+(10) These exhibits, which were previously filed with the
+Company's Annual Report on Form 10-K for the year ended
+December 31, 2000, are incorporated by reference.
+(11) This exhibit, which was previously filed with the
+Company's Registration Statement on Form S-8 (No.
+333-59570), is incorporated by reference.
+(12) This exhibit, which was previously filed with the
+Company's Quarterly Report on Form 10-Q for the period
+ended June 30, 2001, is incorporated by reference.
+(13) This exhibit, which was previously filed with the
+Company's Quarterly Report on Form 10-Q for the period
+ended September 30, 2001, is incorporated by reference.
+(x) Management contract or compensatory plan or arrangement
+required to be filed pursuant to Item 14(c).
+(B) REPORTS ON FORM 8-K.
+None.
+36
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized.
+TRANSACT TECHNOLOGIES INCORPORATED
+By: /s/ Bart C. Shuldman
+------------------------------------
+Bart C. Shuldman
+Chairman of the Board, President and
+Chief Executive Officer
+Date: March 28, 2002
+Pursuant to the requirements of the Securities 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/ Bart C. Shuldman Chairman of the Board, President March 28, 2002
+---------------------------- and Chief Executive Officer
+Bart C. Shuldman (Principal Executive Officer)
+/s/ Richard L. Cote Executive Vice President, Chief March 28, 2002
+---------------------------- Financial Officer, Treasurer,
+Richard L. Cote Secretary and Director
+(Principal Financial Officer)
+/s/ Steven A. DeMartino Senior Vice President, Finance
+---------------------------- and Information Technology March 28, 2002
+Steven A. DeMartino (Principal Accounting Officer)
+/s/ Charles A. Dill Director March 28, 2002
+----------------------------
+Charles A. Dill
+/s/ Jeffrey T. Leeds Director March 28, 2002
+----------------------------
+Jeffrey T. Leeds
+/s/ Thomas R. Schwarz Director March 28, 2002
+----------------------------
+Thomas R. Schwarz
+/s/ Graham Y. Tanaka Director March 28, 2002
+----------------------------
+Graham Y. Tanaka
+37
+EXHIBIT LIST
+The following exhibits are filed herewith.
+Exhibit
+-------
+10.8 Agreement regarding the Continuation and Renewal of Lease
+by and between Bomax Properties, LLC and TransAct, dated
+July 18, 2001.
+10.13(x) Release and Settlement Agreement by and between TransAct
+and Lucy H. Staley, dated December 4, 2001
+10.17(x) Release and Settlement Agreement by and between TransAct
+and Mark Goebel, dated March 1, 2002
+10.19 Loan Agreement by and between the Company and Bart C.
+Shuldman, dated July 1, 2001
+10.21 OEM Purchase Agreement by and between Okidata Americas,
+Inc. and TransAct, dated June 8, 2001.(Pursuant to Rule
+24b-2 under the Exchange Act, the Company has requested
+confidential treatment of portions of this exhibit deleted
+from the filed copy.)
+10.25 Amendment No. 2 to Loan and Security Agreement dated as of
+May 25, 2001 among TransAct, LaSalle and the institutions
+from time to time a party hereto.
+11.1 Computation of earnings per share.
+21.1 Subsidiaries of the Company.
+23.1 Consent of PricewaterhouseCoopers LLP.
+38
\ No newline at end of file
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diff --git a/raw/filings/0001017303/2001/0000914039-02-000121/item1.txt b/raw/filings/0001017303/2001/0000914039-02-000121/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d88d85417e03fd0b32eb597b3100c8cdb19126a8
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@@ -0,0 +1,244 @@
+ITEM 1. BUSINESS.
+(A) GENERAL DEVELOPMENT OF BUSINESS
+TransAct began operating as a stand-alone business in August 1996 to
+operate the printer business that was formerly conducted by certain subsidiaries
+of Tridex Corporation. TransAct completed an initial public offering on August
+22, 1996.
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company undertook a plan to consolidate all
+manufacturing and engineering into its existing Ithaca, NY facility and close
+its Wallingford, CT facility (the "Consolidation"). The Company's technology
+shift to inkjet and thermal printing from dot matrix impact printing has
+dramatically reduced the labor content in printers, and therefore, lowers the
+required production capacity. As of December 31, 2001, substantially all
+Wallingford product lines were successfully transferred to Ithaca, NY. The
+Company expects to maintain one small component production line in Wallingford
+until May 2002, after which the manufacturing facility will be closed. The
+closing of the Wallingford facility is expected to result in the termination of
+employment of approximately 70 production, administrative and management
+employees.
+(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
+TransAct has assessed its operating and reportable segments and has
+determined that it operates in one reportable segment, the design, development,
+manufacture and marketing of transaction-based printers and printer-related
+products.
+(C) NARRATIVE DESCRIPTION OF BUSINESS
+(i) PRINCIPAL PRODUCTS AND SERVICES
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing dot matrix, thermal and inkjet printing
+technology for applications requiring up to 60 character columns in each of the
+following vertical markets: POS, gaming and lottery, financial services and
+kiosk. The Company's printers are configurable and offer customers the ability
+to choose from a variety of features and functions. Options typically include PC
+board configuration, paper cutting devices, paper handling capacities and number
+of print stations. In addition to its configurable printers, TransAct
+manufactures custom printers for certain OEM customers. In collaboration with
+these customers, the Company provides engineering and manufacturing expertise
+for the design and development of specialized printers. In addition, the Company
+offers inkjet cartridges, printer ribbons, paper and replacement parts for all
+of its products.
+The Company provides customers with telephone sales and technical support,
+a personal account representative for orders, shipping and general information
+and expedited shipping for orders of its configurable and custom products.
+Technical and sales support personnel receive training in all of the Company's
+products and services manufactured at their facility. The Company's printers
+generally carry a one- or two-year limited warranty; extended warranties are
+available for purchase on selected printers to supplement the original warranty.
+Service contracts for the repair and maintenance of printers beyond the original
+warranty period are also available for purchase.
+(ii) STATUS OF PRODUCT REQUIRING MATERIAL INVESTMENT
+None.
+2
+(iii) SOURCES AND AVAILABILITY OF RAW MATERIALS
+The principal materials used in manufacturing are copper wire, magnetic
+metals, injection molded plastic parts, formed metal parts and electronic
+components. Although the Company could experience temporary disruption if
+certain suppliers ceased doing business with the Company, the Company's
+requirements generally are available from a number of sources, except as
+described below.
+Okidata Americas, Inc. ("Okidata"), is the sole supplier for a printer
+component kit consisting of a printhead, control board and carriage (the "Oki
+Kit"), which is used in all of the Company's Ithaca(R) brand impact printers.
+The loss of the supply of Oki Kits would have a material adverse effect on the
+Company. TransAct has a supply agreement with Okidata to provide Oki Kits until
+June 2003 at fixed prices through at least March 31, 2002. The Company and
+Okidata are currently negotiating for future pricing. Additionally,
+Hewlett-Packard Company ("HP") is the sole supplier of inkjet cartridges which
+are used in all of the Company's inkjet printers. The loss of the supply of HP
+inkjet cartridges would have a material adverse effect on the sale of the
+Company's inkjet printers. TransAct has a supply agreement with HP to purchase
+inkjet cartridges until June 1, 2002 at a fixed price. TransAct believes its
+relations with Okidata and HP are good and has received no indication that
+either of the supply agreements will not be renewed beyond the respective
+expiration dates of the current contracts. TransAct cannot be certain, however,
+that either of the supply agreements will be renewed, or if renewed, that the
+terms will be as favorable as those under the current contracts.
+(iv) PATENTS AND PROPRIETARY INFORMATION
+The Company owns several patents, three of which it considers material.
+The earliest expiration date of these patents is in 2008. The first patent
+covers an automated paper cut-off device, which is a feature offered on certain
+of the Company's POS printers; the second is a patent that relates to an
+automatic paper loader for a printer; and the third is a patent that covers a
+method for converting a full color image into a two-color image, plus a
+background color. The Company also has sought patent protection for certain
+design features of 1) printers using inkjet technology, 2) POS printers using
+thermal technology, and 3) thermal printers for use in casino slot machines. The
+Company regards certain manufacturing processes and designs to be proprietary
+and attempts to protect them through employee and third-party nondisclosure
+agreements and similar means. It may be possible for unauthorized third parties
+to copy certain portions of the Company's products or to reverse engineer or
+otherwise obtain and use, to the Company's detriment, information that the
+Company regards as proprietary. Moreover, the laws of some foreign countries do
+not afford the same protection to the Company's proprietary rights as do United
+States laws. There can be no assurance that legal protections relied upon by the
+Company to protect its proprietary position will be adequate or that the
+Company's competitors will not independently develop technologies that are
+substantially equivalent or superior to the Company's technologies.
+(v), (vi) SEASONALITY AND PRACTICES RELATING TO WORKING CAPITAL ITEMS
+Retailers typically reduce purchases of new POS equipment in the fourth
+quarter, due to the increased volume of consumer transactions in that period,
+and the Company's sales of printers in the POS market historically have
+increased in the third quarter and decreased in the fourth quarter. However, the
+Company has not experienced material seasonality in its total net sales, due to
+offsetting sales in other markets.
+(vii) CERTAIN CUSTOMERS
+The Company has an OEM purchase agreement with GTECH Corporation ("GTECH")
+to provide on-line lottery printers and spare parts, at prices to be negotiated,
+through December 31, 2004. Firm purchase orders for printers may be placed
+annually by GTECH. The Company has received orders for approximately $9,800,000
+worth of printers for delivery between January 2002 and February 2003. The
+Company also sells printers to GTECH for use in lottery terminals at grocery
+check-out lanes ("in-lane lottery printers"). Sales to GTECH accounted for
+approximately 33.0% and 22.1% of net sales in 2001 and 2000, respectively. The
+Company made no on-line lottery printer shipments and approximately $1,100,000
+of in-lane lottery printer shipments to GTECH during 1999. The Company also
+provides printers to ICL Pathway for use in the British Post Office. During
+2000, sales to ICL Pathway accounted for approximately 20.2% of net sales. The
+Company completed shipping printers to ICL Pathway for use in the British Post
+Office in February 2001 and no further shipments are expected. The Company had
+no sales to any one customer greater than 10% of net sales in 1999.
+(viii) BACKLOG
+The Company's backlog of firm orders was approximately $8,700,000 as of
+March 25, 2002 and $18,100,000 as of March 16, 2001, including approximately
+$6,600,000 and $7,800,000 to GTECH, respectively. Based on customers' current
+delivery requirements, TransAct expects to fill approximately $8,200,000 of its
+current backlog during 2002 and approximately $500,000 during 2003.
+3
+(ix) MATERIAL PORTION OF BUSINESS SUBJECT TO RENEGOTIATION OF PROFITS
+None.
+(x) COMPETITION
+The market for transaction-based printers is extremely competitive, and
+the Company expects such competition to intensify in the future. The Company
+competes with a number of companies, many of which have greater financial,
+technical and marketing resources than the Company. TransAct believes its
+ability to compete successfully depends on a number of factors both within and
+outside its control, including durability, reliability, quality, design
+capability, product customization, price, customer support, success in
+developing new products, manufacturing expertise and capacity, supply of
+component parts and materials, strategic relationships with suppliers, the
+timing of new product introductions by the Company and its competitors, general
+market and economic conditions and, in some cases, the uniqueness of its
+products.
+Three of the Company's competitors, Epson America, Inc., Axiohm
+Transaction Solutions and Star Micronics America, Inc. together control
+approximately 70% of the United States market for POS printers, a market in
+which the Company's strategy calls for increased market share. Another principal
+competitor in the POS market is Citizen -- CBM America Corporation. Certain
+competitors of the Company have greater financial resources, lower costs
+attributable to higher volume production and off-shore manufacturing locations,
+and offer lower prices than the Company from time to time.
+In the gaming and lottery, financial services and kiosk markets, no single
+supplier holds a dominant position. Certain of the Company's products sold for
+gaming and lottery, kiosk and financial services applications compete based upon
+the Company's ability to provide highly specialized products, custom engineering
+and ongoing technical support.
+The Company's strategy for competing in its markets is to continue to
+develop new products and product line extensions, to increase its geographic
+market penetration, and to take advantage of strategic relationships. The
+Company expects to particularly focus on (1) gaining market acceptance for its
+new family of printers utilizing Hewlett Packard's inkjet printing technology,
+(2) promoting its new line of slot machine printers into the gaming market and
+(3) expanding its consumables, spares and service business. Although the Company
+believes that its products, operations and relationships provide a competitive
+foundation, there can be no assurance that the Company will compete successfully
+in the future.
+(xi) RESEARCH AND DEVELOPMENT ACTIVITIES
+The Company spent approximately $3,070,000, $3,481,000 and $3,235,000 in
+2001, 2000 and 1999, respectively, on engineering, design and product
+development efforts in connection with specialized engineering and design to
+introduce new products and to customize existing products. During 2002, the
+Company expects to focus the majority of its research and development activities
+on the continuing development and enhancement of (1) its family of printers for
+the POS market utilizing inkjet and thermal printing technology and (2) its
+ticket-issuing printers for use in the casino market.
+(xii) ENVIRONMENT
+The Company is not aware of any material noncompliance with federal, state
+and local provisions that have been enacted or adopted regulating the discharge
+of materials into the environment, or otherwise relating to the protection of
+the environment.
+(xiii) EMPLOYEES
+As of March 15, 2002, TransAct Technologies and its subsidiaries employed
+176 persons, of whom 141 were full-time and 35 were temporary employees. None of
+the Company's employees is unionized and the Company considers its relationships
+with its employees to be good.
+(D) FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS AND EXPORT
+SALES
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary located in the United Kingdom, which had sales
+to its customers of $1,791,000, $11,164,000 (primarily to ICL Pathway for use in
+the British Post Office) and $700,000 in 2001, 2000 and 1999, respectively. The
+Company had export sales to its customers from its domestic operations of
+approximately $6,131,000, $5,156,000 and $7,807,000 in 2001, 2000 and 1999,
+respectively.
+4
+(E) EXECUTIVE OFFICERS OF THE REGISTRANT AS OF DECEMBER 31, 2001
+Name Age Position
+------------------- --- --------------------------------------------------
+Bart C. Shuldman 44 Chairman of the Board, President and Chief
+Executive Officer
+Richard L. Cote 60 Executive Vice President, Chief Financial Officer,
+Treasurer, Secretary and Director
+James B. Stetson 44 Executive Vice President - Sales and Marketing
+Steven A. DeMartino 32 Senior Vice President - Finance and Information
+Technology
+Mark B. Goebel 47 Senior Vice President - General Manager
+(Wallingford, CT facility)
+Michael S. Kumpf 52 Senior Vice President - Engineering
+Lucy H. Staley 51 Senior Vice President - General Manager (Ithaca,
+NY facility)
+BART C. SHULDMAN has been Chief Executive Officer, President and a
+Director of the Company since its formation in June 1996. Previously, Mr.
+Shuldman served as President of Magnetec and later the combined operations of
+Magnetec and Ithaca from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+RICHARD L. COTE has been Executive Vice President, Chief Financial
+Officer, Treasurer, Secretary and a Director of the Company since its formation
+in June 1996. Prior thereto, he served as Senior Vice President and Chief
+Financial Officer of Tridex from September 1993 to June 1996.
+JAMES B. STETSON was appointed Executive Vice President, Sales and
+Marketing in November 2001, and served as Senior Vice President of Worldwide
+Sales from February 2000 to November 2001, and Vice President of Sales, Latin
+America from October 1997 to February 2000. Prior to joining TransAct, Mr.
+Stetson served as Vice President and Sales Manager at Gekay Sales and Service
+Company from 1995 until October 1997.
+STEVEN A. DEMARTINO joined TransAct as Corporate Controller in August 1996
+and was appointed an officer of the Company in January 1998, Vice President in
+December 1999, and Senior Vice President, Finance and Information Technology in
+October 2001. Prior to joining TransAct, Mr. DeMartino was a self-employed
+financial consultant from May 1996 to August 1996. Prior thereto, Mr. DeMartino,
+served as Controller of NER/Copart, Inc. from September 1994 to May 1996.
+MICHAEL S. KUMPF, Senior Vice President-Engineering since June 1996,
+served as Vice President of Engineering of Ithaca from 1991 until June 1996. Mr.
+Kumpf was appointed Executive Vice President of Engineering in January 2002.
+MARK B. GOEBEL, Senior Vice President - General Manager (Wallingford, CT
+facility), served as Vice President-Engineering from April 1994 until he was
+appointed Senior Vice President of Engineering of Wallingford, and an officer of
+the Company, in January 2000. In November 2000, Mr. Goebel was named Senior Vice
+President - General Manager of the Wallingford, CT facility. As a result of the
+Consolidation, Mr. Goebel terminated employment with the Company on March 1,
+2002.
+LUCY H. STALEY, Senior Vice President-General Manager (Ithaca, NY
+facility) since June 1996, served as a Vice President of Ithaca from 1984 until
+June 1996. As a result of the Consolidation, Ms. Staley terminated employment
+with the Company on January 31, 2002.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2001/0000914039-02-000121/item13.txt b/raw/filings/0001017303/2001/0000914039-02-000121/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..501ee6572ce52ca817cfe5d23657ca51bc68f164
--- /dev/null
+++ b/raw/filings/0001017303/2001/0000914039-02-000121/item13.txt
@@ -0,0 +1,4 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
+33
\ No newline at end of file
diff --git a/raw/filings/0001017303/2001/0000914039-02-000121/item9a.txt b/raw/filings/0001017303/2001/0000914039-02-000121/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2001/0000914039-02-000121/rp_note.txt b/raw/filings/0001017303/2001/0000914039-02-000121/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2001/0000914039-02-000121/rpt_disclosure.txt b/raw/filings/0001017303/2001/0000914039-02-000121/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f39adb1bd0d74e9c92a9150ab6cb3c14cd286fd5
--- /dev/null
+++ b/raw/filings/0001017303/2001/0000914039-02-000121/rpt_disclosure.txt
@@ -0,0 +1,15 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+On February 23, 1999, the Company loaned Bart C. Shuldman, the Chairman,
+Chief Executive Officer and President of the Company, $330,000 to fund his
+purchase in the market of 104,000 shares of the Company's common stock. Mr.
+Shuldman pledged 93,423 of the shares purchased with the loan proceeds and
+50,000 shares of restricted common stock as security for the promissory note.
+The principal and any unpaid interest under the note is due in a balloon payment
+five years after the date of the loan. The interest rate on the note is
+calculated based on the Company's average variable lending rate under its
+primary credit facility. Interest payments through December 31, 2001 have been
+added to principal, which was increased to $409,340 at that date. During 2002,
+interest will be compounded and added to principal monthly and be payable at
+maturity. Thereafter, it will accrue annually and be payable at maturity. At
+March 31, 2002, the aggregate amount outstanding under the loan was $415,253.
+6
\ No newline at end of file
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/filing.txt b/raw/filings/0001017303/2002/0000950123-03-003629/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..35ccf0f031fbe279151ef8d93261911e08176635
--- /dev/null
+++ b/raw/filings/0001017303/2002/0000950123-03-003629/filing.txt
@@ -0,0 +1,2448 @@
+10-K
+1
+y84806e10vk.txt
+FORM 10-K
+SECURITIES AND EXCHANGE COMMISSION
+Washington, DC. 20549
+__________________________________
+FORM 10-K
+(Mark One)
+(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
+THE SECURITIES EXCHANGE ACT OF 1934
+For the fiscal year ended December 31, 2002
+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: 0-21121
+TRANSACT TECHNOLOGIES INCORPORATED
+--------------------------------------------------------------------------------
+(Exact name of registrant as specified in its charter)
+DELAWARE 06-1456680
+---------------------------------------- --------------------------------------
+(State or other jurisdiction of (I.R.S. Employer Identification No.)
+incorporation organization)
+7 LASER LANE, WALLINGFORD, CT 06492
+---------------------------------------- --------------------------------------
+(Address of principal executive offices) (Zip Code)
+Registrant's telephone number, including 203-269-1198
+area code --------------------------------------
+Securities registered pursuant to Section 12(b) of the Act:
+NONE
+--------------------------------------------------------------------------------
+Securities registered pursuant to Section 12(g) of the Act:
+COMMON STOCK, $0.01 PAR VALUE
+--------------------------------------------------------------------------------
+(Title of class)
+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 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 other amendment
+to this Form 10-K. [X]
+Indicate by check mark whether the registrant is an accelerated filer (as
+defined in Exchange Act Rule 12b-2). Yes [ ] No [X]
+As of June 28, 2002 the aggregate market value of the registrant's issued and
+outstanding voting stock held by non-affiliates of the registrant was
+$24,800,000.
+As of March 14, 2003, the registrant had outstanding 5,715,119 shares of common
+stock, $0.01 par value.
+DOCUMENTS INCORPORATED BY REFERENCE
+Proxy Statement for the Annual Meeting of Shareholders to be held on May 20,
+2003 - Part III (Items 10-13).
+PART I
+GENERAL
+TransAct Technologies Incorporated ("TransAct" or the "Company")
+designs, develops, manufactures and markets transaction-based printers under the
+Ithaca(R) and Magnetec(R) brand names. In addition, the Company markets related
+consumables, spare parts and service. The Company's printers are used worldwide
+to provide transaction records such as receipts, tickets, coupons, register
+journals and other documents. The Company focuses on two core markets:
+point-of-sale ("POS") and gaming and lottery. TransAct sells its products
+directly to original equipment manufacturers ("OEMs"), value-added resellers
+("VARs"), selected distributors and directly to end-users. The Company's product
+distribution spans across the Americas, Europe, the Middle East, Africa, the
+Caribbean Islands and the South Pacific. TransAct has one primary operating
+facility located in Ithaca, New York, five sales offices located in the United
+States, and one sales office and service depot in the United Kingdom. TransAct's
+executive offices are located at 7 Laser Lane, Wallingford, CT 06492 with a
+telephone number of (203) 269-1198.
+ITEM 1. BUSINESS.
+(A) GENERAL DEVELOPMENT OF BUSINESS
+TransAct was incorporated in June 1996 and began operating as a
+stand-alone business in August 1996 to operate the printer business that was
+formerly conducted by certain subsidiaries of Tridex Corporation. TransAct
+completed an initial public offering on August 22, 1996.
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company undertook a plan to consolidate all
+manufacturing and engineering into its existing Ithaca, NY facility and close
+its Wallingford, CT facility (the "Consolidation"). The Company's technology
+shift to inkjet and thermal printing from dot matrix impact printing has
+dramatically reduced the labor content in its printers, and therefore, lowers
+the required production capacity. As of December 31, 2001, substantially all
+Wallingford product lines were successfully transferred to Ithaca, NY. The
+Company maintains a small component production line and service depot in
+Wallingford. The closing of the Wallingford facility resulted in the termination
+of employment of approximately 70 production, administrative and management
+employees.
+As a result of the Consolidation, the Company improved its gross margin
+and significantly reduced its operating expenses in 2002 compared to 2001, and
+lowered its operating income breakeven point from $54 million to $42 million in
+revenues. Management believes this will provide additional operating leverage in
+2003.
+(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
+TransAct has assessed its operating and reportable segments and has
+determined that it operates in one reportable segment, the design, development,
+manufacture and marketing of transaction-based printers and printer-related
+products.
+(C) NARRATIVE DESCRIPTION OF BUSINESS
+(i) PRINCIPAL PRODUCTS AND SERVICES
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing inkjet, thermal and impact printing
+technology for applications requiring up to 60 character columns, primarily in
+the POS and gaming and lottery markets. The Company's printers are configurable
+and offer customers the ability to choose from a variety of features and
+functions. Options typically include PC board configuration, paper cutting
+devices, paper handling capacities and cabinetry color. In addition to its
+configurable printers, TransAct manufactures custom printers for certain OEM
+customers. In collaboration with these customers, the Company provides
+engineering and manufacturing expertise for the design and development of
+specialized printers. In addition, the Company offers inkjet cartridges, printer
+ribbons, paper and replacement parts for all of its products.
+The Company provides customers with telephone sales and technical
+support, a personal account representative for orders, shipping and general
+information and expedited shipping for orders of its configurable and custom
+products. Technical and sales support personnel receive training in all of the
+Company's products and services manufactured at their facility. The Company's
+printers generally carry a one- or two-year limited warranty; extended
+warranties are available for purchase on selected printers to supplement the
+original warranty. Service contracts for the repair and maintenance of printers
+beyond the original warranty period are also available for purchase.
+(ii) STATUS OF PRODUCT REQUIRING MATERIAL INVESTMENT
+None.
+2
+(iii) SOURCES AND AVAILABILITY OF RAW MATERIALS
+The principal materials used in manufacturing are inkjet, thermal and
+impact printheads, injection molded plastic parts, formed/stamped metal parts
+and electronic components. Although the Company could experience temporary
+disruption if certain suppliers ceased doing business with the Company, the
+Company's requirements generally are available from a number of sources, except
+as described below.
+Okidata Americas, Inc. ("Okidata"), is the sole supplier for a printer
+component kit consisting of a printhead, control board and carriage (the "Oki
+Kit"), which is used in all of the Company's Ithaca(R) brand impact printers.
+The loss of the supply of Oki Kits would have a material adverse effect on the
+Company. TransAct has a supply agreement with Okidata to provide Oki Kits until
+June 2003. Although prices under this agreement were fixed until March 2002, the
+Company continues to purchase supplies at these prices. The Company and Okidata
+are currently negotiating for future supplies and pricing.
+Additionally, Hewlett-Packard Company ("HP") is the sole supplier of
+inkjet cartridges that are used in all of the Company's inkjet printers. The
+loss of the supply of HP inkjet cartridges would have a material adverse effect
+on the sale of the Company's inkjet printers. TransAct has a supply agreement
+with HP to purchase inkjet cartridges until February 1, 2004 at fixed prices.
+TransAct believes its relations with Okidata and HP are good and has
+received no indication that either of the supply agreements will not be renewed
+beyond the respective expiration dates of the current contracts. TransAct cannot
+be certain, however, that either of the supply agreements will be renewed, or if
+renewed, that the terms will be as favorable as those under the current
+contracts.
+(iv) PATENTS AND PROPRIETARY INFORMATION
+The Company has significantly expanded its patent portfolio over the
+past two years, and expects to continue to do so in the future. The Company also
+believes its patent portfolio will provide additional opportunities to license
+its intellectual property in the future. The Company currently owns eight
+patents, four of which it considers material. The earliest expiration date of
+these eight patents is in 2008 with the latest expiration date in 2020. Of the
+material patents, one patent covers methods and apparatus for allowing a
+two-color printer to print images using single pass technology by printing
+during both forward and reverse movement of the print mechanism; another patent
+relates to TransAct's proprietary void and reprint receipt printing method which
+is used in certain of the Company's slot machine printers; and two other patents
+cover a method for converting a full color image into a two-color image, plus a
+background color. The Company also has sought patent protection for certain
+design features of 1) printers using inkjet technology, 2) POS printers using
+thermal technology, and 3) thermal printers for use in casino slot machines. The
+Company regards certain manufacturing processes and designs to be proprietary
+and attempts to protect them through employee and third-party nondisclosure
+agreements and similar means. It may be possible for unauthorized third parties
+to copy certain portions of the Company's products or to reverse engineer or
+otherwise obtain and use, to the Company's detriment, information that the
+Company regards as proprietary. Moreover, the laws of some foreign countries do
+not afford the same protection to the Company's proprietary rights as do United
+States laws. There can be no assurance that legal protections relied upon by the
+Company to protect its proprietary position will be adequate or that the
+Company's competitors will not independently develop technologies that are
+substantially equivalent or superior to the Company's technologies.
+(v), (vi)SEASONALITY AND PRACTICES RELATING TO WORKING CAPITAL ITEMS
+Retailers typically reduce purchases of new POS equipment in the fourth
+quarter, due to the increased volume of consumer transactions in that period,
+and the Company's sales of printers in the POS market historically have
+increased in the third quarter and decreased in the fourth quarter. However, the
+Company has not experienced material seasonality in its total net sales, due to
+offsetting sales in other markets.
+(vii) CERTAIN CUSTOMERS
+The Company has two OEM purchase agreements with GTECH Corporation
+("GTECH"). The first OEM purchase agreement ("GTECH Impact Printer Agreement")
+provides for the sale of impact on-line lottery printers and spare parts, at
+prices to be negotiated, through December 31, 2004. The second OEM purchase
+agreement ("GTECH Thermal Printer Agreement") provides for the sale of thermal
+on-line lottery printers and spares parts, at a fixed prices, through June 28,
+2007. Firm purchase orders for printers under either agreement may be placed
+annually by GTECH. Pursuant to orders placed under the GTECH Impact Printer
+Agreement during 2002, the Company has approximately $500,000 of impact printers
+remaining to be shipped during the first quarter of 2003. The Company does not
+expect any further shipments of impact on-line lottery printers in 2003 beyond
+the first quarter. Additionally, pursuant to the GTECH Thermal Printer
+Agreement, the Company has received an initial order for approximately
+$4,300,000 worth of thermal printers for delivery in 2003, beginning in the
+second quarter. The Company also sells printers to GTECH for use in lottery
+terminals at grocery store check-out lanes ("in-lane lottery printers"). Sales
+of in-lane lottery printes are project-oriented, and, as such, the Company
+cannot predict if
+3
+and when future sales may occur. Sales to GTECH accounted for approximately 27%,
+33% and 22% of net sales in 2002, 2001 and 2000, respectively.
+The Company also provides printers to ICL Pathway for use in the
+British Post Office. During 2000, sales to ICL Pathway accounted for
+approximately 20% of net sales. The Company completed shipping printers to ICL
+Pathway for use in the British Post Office in February 2001, and no further
+shipments are expected.
+(viii) BACKLOG
+The Company's backlog of firm orders was approximately $7,628,000 as of
+March 14, 2003 and $8,700,000 as of March 25, 2002, including approximately
+$4,300,000 and $6,600,000 to GTECH, respectively. Based on customers' current
+delivery requirements, TransAct expects to fill its entire current backlog
+during 2003.
+(ix) MATERIAL PORTION OF BUSINESS SUBJECT TO RENEGOTIATION OF
+PROFITS
+None.
+(x) COMPETITION
+The market for transaction-based printers is extremely competitive, and
+the Company expects such competition to intensify in the future. The Company
+competes with a number of companies, many of which have greater financial,
+technical and marketing resources than the Company. TransAct believes its
+ability to compete successfully depends on a number of factors both within and
+outside its control, including durability, reliability, quality, design
+capability, product customization, price, customer support, success in
+developing new products, manufacturing expertise and capacity, supply of
+component parts and materials, strategic relationships with suppliers, the
+timing of new product introductions by the Company and its competitors, general
+market, economic and political conditions and, in some cases, the uniqueness of
+its products.
+In the POS market, the Company's major competitors are, Epson America,
+Inc., Axiohm Transaction Solutions, Star Micronics America, Inc., Citizen -- CBM
+America Corporation, and Korean Printer Solutions (a spin-off company from
+Samsung). Together, these competitors comprise approximately 80% of the POS
+market segments into which the Company sells. Certain competitors of the Company
+have greater financial resources, lower costs attributable to higher volume
+production and off-shore manufacturing locations, and offer lower prices than
+the Company from time to time.
+In the lottery market (consisting principally of on-line lottery
+transaction printing), the Company holds a leading position, based largely on
+its long-term purchase agreements with GTECH, which controls approximately 70%
+of the worldwide on-line lottery market. The Company competes in this market
+based solely on its ability to provide specialized, custom-engineered products
+to GTECH.
+In the gaming market (consisting principally of video lottery terminals
+and slot machine transaction printing), the Company and its major competitor,
+Seiko Instruments Inc. (an affiliate of Seiko Epson Corporation), comprise a
+substantial portion of the market. The Company also competes, to a lesser
+extent, with JCM American Corporation and Money Controls, a division of Coin
+Acceptors, Inc. (Coinco). Certain of the Company's products sold for gaming
+applications compete based upon the Company's ability to provide highly
+specialized products, custom engineering and ongoing technical support.
+The Company's strategy for competing in its markets is to continue to
+develop new products and product line extensions, to increase its geographic
+market penetration, take advantage of strategic relationships, and to lower
+product costs by sourcing certain products overseas. The Company expects to
+particularly focus on (1) promoting its new line of slot machine printers into
+the gaming market, (2) increasing sales of its family of printers utilizing
+Hewlett Packard's inkjet printing technology, and (3) expanding its consumables,
+spare parts and service business. Although the Company believes that its
+products, operations and relationships provide a competitive foundation, there
+can be no assurance that the Company will compete successfully in the future.
+(xi) RESEARCH AND DEVELOPMENT ACTIVITIES
+The Company spent approximately $2,025,000, $3,070,000 and $3,481,000
+in 2002, 2001 and 2000, respectively, on engineering, design and product
+development efforts in connection with specialized engineering and design to
+introduce new products and to customize existing products. During 2003, the
+Company expects to focus the majority of its research and development activities
+on the development of a new thermal on-line lottery printer for GTECH, and on
+the continuing development and enhancement of (1) its family of printers for the
+POS market utilizing inkjet and thermal printing technology and (2) its
+ticket-issuing printers for use in the casino market.
+4
+(xii) ENVIRONMENT
+The Company is not aware of any material noncompliance with federal,
+state and local provisions that have been enacted or adopted regulating the
+discharge of materials into the environment, or otherwise relating to the
+protection of the environment.
+(xiii) EMPLOYEES
+As of March 14, 2003, TransAct Technologies and its subsidiaries
+employed 158 persons, of whom 136 were full-time and 22 were temporary
+employees. None of the Company's employees is unionized, and the Company
+considers its relationships with its employees to be good.
+(D) FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS AND EXPORT
+SALES
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary located in the United Kingdom, which had sales
+to its customers of $738,000, $1,791,000 and $11,164,000 (primarily to ICL
+Pathway for use in the British Post Office) in 2002, 2001 and 2000,
+respectively. The Company had export sales to its customers from its domestic
+operations of approximately $3,968,000, $6,131,000 and $5,156,000 in 2002, 2001
+and 2000, respectively.
+(E) EXECUTIVE OFFICERS OF THE REGISTRANT AS OF DECEMBER 31, 2002
+Name Age Position
+------------------------------------ ------------- -------------------------------------------------------------
+Bart C. Shuldman 45 Chairman of the Board, President and Chief Executive Officer
+Richard L. Cote 61 Executive Vice President, Chief Financial Officer, Treasurer,
+Secretary and Director
+James B. Stetson 45 Executive Vice President - Sales and Marketing
+Michael S. Kumpf 53 Executive Vice President - Engineering
+Steven A. DeMartino 33 Senior Vice President - Finance and Information Technology
+BART C. SHULDMAN has been Chief Executive Officer, President and a
+Director of the Company since its formation in June 1996. Previously, Mr.
+Shuldman served as President of Magnetec and later the combined operations of
+Magnetec and Ithaca from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+RICHARD L. COTE has been Executive Vice President, Chief Financial
+Officer, Treasurer, Secretary and a Director of the Company since its formation
+in June 1996. Prior thereto, he served as Senior Vice President and Chief
+Financial Officer of Tridex from September 1993 to June 1996.
+JAMES B. STETSON was appointed Executive Vice President, Sales and
+Marketing in November 2001, and served as Senior Vice President of Worldwide
+Sales from February 2000 to November 2001, and Vice President of Sales, Latin
+America from October 1997 to February 2000. Prior to joining TransAct, Mr.
+Stetson served as Vice President and Sales Manager at Gekay Sales and Service
+Company from 1995 until October 1997.
+MICHAEL S. KUMPF, was appointed Executive Vice President of Engineering
+in March 2002. He served as Senior Vice President-Engineering from June 1996 to
+March 2002 and Vice President of Engineering of Ithaca from 1991 until June
+1996.
+STEVEN A. DEMARTINO joined TransAct as Corporate Controller in August
+1996 and was appointed an officer of the Company in January 1998, Vice President
+in December 1999, and Senior Vice President, Finance and Information Technology
+in October 2001. Prior to joining TransAct, Mr. DeMartino was a self-employed
+financial consultant from May 1996 to August 1996. Prior thereto, Mr. DeMartino,
+served as Controller of NER/Copart, Inc. from September 1994 to May 1996.
+5
+ITEM 2. PROPERTIES.
+The Company's operations are currently conducted at the facilities
+described below. In February 2001, the Company announced plans to establish a
+global engineering and manufacturing center at its Ithaca, NY facility. As part
+of this strategic decision, the Company consolidated all manufacturing and
+engineering from its Wallingford, CT facility into its existing Ithaca, NY
+facility. The Company's corporate headquarters are still located in the
+Wallingford, CT facility. Although the Company is actively seeking to sublease
+its Wallingford, CT facility for the remaining term of the lease, and expects to
+do so successfully, there can be no assurance that the Company will be
+successful in doing so, or that it will be able to do so at terms comparable to
+those of its existing lease.
+In connection with the consolidation of facilities into Ithaca, the
+Company added approximately 10,000 square feet of manufacturing space and 3,000
+square feet of office space to its Ithaca facility during 2002.
+Size Owned or Lease Expiration
+Location Operations Conducted (Approx. Sq. Ft.) Leased Date
+---------------------------------- -------------------- ----------------- -------- -----------------
+Wallingford, Connecticut Executive offices 49,000 Leased March 31, 2008
+Ithaca, New York Manufacturing facility 74,000 Leased June 30, 2007
+Doncaster, United Kingdom Sales office and service 2,800 Leased August 1, 2009
+depot
+Georgia (2), Florida, New York and Five (5) regional sales 600 Leased Various
+Texas offices
+The Company believes that its facilities generally are in good
+condition, adequately maintained and suitable for their present and currently
+contemplated uses.
+ITEM 3. LEGAL PROCEEDINGS.
+None.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
+No matters were submitted to a vote of security holders during the last
+quarter of the year covered by this report.
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
+The Company's common stock is traded on the Nasdaq SmallCap Market
+under the symbol TACT. As of March 14, 2003, there were 783 holders of record of
+the common stock. The high and low sales bid quotations of the common stock
+reported during each quarter of the years ended December 31, 2002 and 2001 were
+as follows:
+Year Ended Year Ended
+December 31, 2002 December 31, 2001
+----------------------------------- ------------------------------------
+High Low High Low
+----------------- --------------- ----------------- -----------------
+First Quarter $6.70 $3.90 $7.03 $3.88
+Second Quarter 7.00 4.51 9.65 5.05
+Third Quarter 5.99 3.60 9.85 3.95
+Fourth Quarter 5.12 3.91 6.00 3.88
+No dividends on common stock have been declared, and the Company does
+not anticipate declaring dividends in the foreseeable future. The Company's
+credit agreement with LaSalle Business Credit restricts the payment of cash
+dividends on its common stock for the term of the agreement.
+6
+Information regarding the Company's equity compensation plans as of
+December 31, 2002 is as follows:
+Number of securities to Weighted average
+be issued upon exercise exercise price of Number of securities
+of outstanding options, outstanding options, remaining available
+warrants and rights warrants and rights for future issuance
+-------------------------------------------------------------------
+Equity compensation plans approved
+by security holders:
+1996 Stock Plan 757,816 $5.79 188,550
+1996 Non-Employee Director Plan* 132,500 8.09 7,500
+2000 Employee Stock Purchase Plan - - 33,881
+2000 Preferred stock warrants 54,444 9.00 -
+2001 Employee Stock Plan 101,750 4.92 48,250
+-------------------------------------------------------------------
+Total 1,046,510 $6.17 278,181
+===================================================================
+* The 1996 Non-Employee Director Plan includes 10,000 shares (2,500
+shares to be issued upon exercise and 7,500 shares available for future
+issuance) that have not been approved by security holders as of December 31,
+2002.
+ITEM 6. SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
+Year Ended December 31,
+--------------------------------------------------------------
+2002 2001 2000 1999 1998
+---------- ---------- ---------- ---------- ----------
+Statement of Operations Data:
+Net sales $ 39,461 $ 43,974 $ 53,720 $ 44,889 $ 52,239
+Gross profit 10,216 9,774 14,142 11,754 13,826
+Operating income (loss) (984) (7,286) (154) 35 2,148
+Net income (loss) (692) (4,922) (344) 324 1,206
+Net income (loss) available
+to common shareholders (1,050) (5,280) (664) 324 1,206
+Net income (loss) per share:
+Basic (0.19) (0.95) (0.12) 0.06 0.20
+Diluted (0.19) (0.95) (0.12) 0.06 0.20
+December 31,
+--------------------------------------------------------------
+2002 2001 2000 1999 1998
+---------- ---------- ---------- ---------- ----------
+Balance Sheet Data:
+Total assets $ 22,030 $ 25,791 $ 27,619 $ 25,684 $ 23,788
+Long-term debt 2,791 5,344 5,944 7,100 5,075
+Preferred stock 3,824 3,746 3,668 -- --
+Shareholders' equity:
+Common 6,545 7,315 12,191 12,207 12,177
+7
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS.
+This discussion should be read in conjunction with the Consolidated
+Financial Statements and notes thereto.
+FORWARD LOOKING STATEMENTS
+Certain statements included in this report, including without
+limitation statements in this Management's Discussion and Analysis of Financial
+Condition and Results of Operations, which are not historical facts are
+"forward-looking statements" within the meaning of Section 27A of the Securities
+Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
+as amended. All forward-looking statements involve risks and uncertainties,
+including, but not limited to, customer acceptance and market share gains, both
+domestically and internationally, in the face of substantial competition from
+competitors that have broader lines of products and greater financial resources;
+introduction of new products into the marketplace by competitors; successful
+product development; dependence on significant customers including GTECH
+Corporation; dependence on third parties for sales in Europe and Latin America;
+economic and political conditions in the United States, Europe and Latin
+America; marketplace acceptance of new products; risks associated with foreign
+operations; the Company's ability to successfully sublease its facility in
+Wallingford, CT; availability of third-party components at reasonable prices;
+and the absence of price wars or other significant pricing pressures affecting
+the Company's products in the United States or abroad. Actual results may differ
+materially from those discussed in, or implied by, the forward-looking
+statements. The forward-looking statements speak only as of the date of this
+report and the Company assumes no duty to update them to reflect new, changing
+or unanticipated events or circumstances.
+PLANT CONSOLIDATION DURING 2001
+In February 2001, we announced plans to establish a global engineering
+and manufacturing center at our Ithaca, NY facility. As part of this strategic
+decision, we undertook a plan to consolidate all manufacturing and engineering
+into our existing Ithaca, NY facility and close our Wallingford, CT facility
+(the "Consolidation"). However, our Company headquarters remains in Wallingford,
+CT. Our technology shift to inkjet and thermal printing from dot matrix impact
+printing has dramatically reduced the labor content in our printers, and
+therefore, lowers the required production capacity. As of December 31, 2001, we
+successfully transferred substantially all our Wallingford product lines to
+Ithaca, NY, with the exception of a small component production line and service
+depot that remain in Connecticut. The closing of the Wallingford facility
+resulted in the termination of employment of approximately 70 production,
+administrative and management employees.
+Through December 31, 2002, we have incurred approximately $5.1 million
+of non-recurring costs associated with the Consolidation, including severance
+pay, stay bonuses, employee benefits, moving expenses, non-cancelable lease
+payments, and other costs, of which approximately $1,000,000 and $4,100,000 were
+recognized in 2002 and 2001, respectively. We do not expect to incur any
+additional charges related to the Consolidation during 2003. See the "Liquidity
+and Capital Resources" section for a discussion of the expected impact of the
+Consolidation on our future results of operations and cash flows.
+CRITICAL ACCOUNTING JUDGMENTS AND ESTIMATES
+Our discussion and analysis of our financial condition and results of
+operations are based upon our consolidated financial statements, which have been
+prepared by us in accordance with accounting principles generally accepted in
+the United States of America. The presentation of these financial statements
+requires us to make estimates and judgments that affect the reported amounts of
+assets, liabilities, revenue and expenses, and disclosure of contingent assets
+and liabilities. Our estimates include those related to revenue recognition,
+inventory obsolescence, the valuation of deferred tax assets and liabilities,
+depreciable lives of equipment, warranty obligations, and restructuring
+accruals. We base our estimates on historical experience and on various other
+assumptions that we believe to be reasonable under the circumstances.
+CRITICAL ACCOUNTING POLICIES
+Our consolidated financial statements have been prepared in accordance
+with generally accepted accounting principles in the United States. In preparing
+the financial statements, we are required to make estimation judgments. Such
+judgments are based upon historical experience and certain assumptions that are
+believed to be reasonable in the particular circumstances. Those judgments
+affect both balance sheet items and income statement categories. We evaluate our
+assumptions on an ongoing basis by comparing actual results with our estimates.
+Actual results may differ from the original estimates. The following accounting
+policies are those that we believe to be most critical in the preparation of our
+financial statements.
+Inventory Valuation -- Our inventories are stated at the lower of cost
+or market. We write down our inventory for any material that has become obsolete
+or may become unsaleable based on historical usage and estimates of future
+demand in the market. Assumptions are reviewed at least quarterly and
+adjustments are made, as necessary, to reflect changed conditions. Should
+circumstances change and we determine that additional inventory is subject to
+obsolescence, additional write-downs of inventory could result in a charge to
+income.
+8
+Deferred Tax Assets- We have recorded deferred tax assets, largely as the result
+of temporary differences between the tax basis of certain reserves (including
+restructuring, inventory, warranty and other reserves) and their reported
+amounts in the financial statements. During 2002, we established a valuation
+allowance on a portion of our foreign tax credits, research and development
+credits and certain state net operating loss carryforwards. Based on our
+projection of future taxable income and our ability to carryback current year
+net operating losses, no additional valuation allowance is considered necessary.
+We will need to recognize approximately $7 million in future taxable income in
+order to realize all of our deferred tax assets at December 31, 2002. Should
+circumstances change and we determine that some or all of the deferred taxes
+would not be realized, a valuation allowance would be recorded resulting in a
+charge to income in the period the determination is made.
+Accrued Restructuring Expenses--In connection with the Consolidation
+of manufacturing facilities, we have recorded significant accruals. These
+accruals comprise severance pay, stay bonuses, employee benefits, non-cancelable
+lease costs and certain other expenses. Management has made reasonable estimates
+of such costs and expenses. However, if actual costs differ from the estimates,
+charges or credits to income could result in the period the adjustments are
+determined. Also, because certain moving and relocation costs are not accruable
+under generally accepted accounting principles in the U.S., those expenses are
+recorded as incurred. We do not expect to record any additional charges related
+to the Consolidation during 2003.
+Accrued Warranty Costs--We warranty our products for up to two years
+and record the estimated cost of such product warranties at the time the sale is
+recorded. Estimated warranty costs are based upon actual past experience of
+product returns and the related estimated cost of labor and material to make the
+necessary repairs. If actual future product return rates or the actual costs of
+material and labor differ from the estimates, adjustments to the accrued
+warranty liability would be made.
+(A) Results of Operations
+(i) YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER
+31, 2001
+NET SALES. Net sales by market for the years ended December 31, 2002
+and 2001 were as follows:
+Year ended Year ended
+(In thousands) December 31, 2002 December 31, 2001
+--------------------- ---------------------
+Point of sale $ 16,773 42.5% $ 20,007 45.5%
+Gaming and lottery 20,986 53.2 19,869 45.2
+Other 1,702 4.3 4,098 9.3
+-------------------- ---------------------
+$ 39,461 100.0% 43,974 100.0%
+==================== =====================
+International $ 4,706 11.9% $ 7,922 18.0%
+==================== =============== =====
+Net sales for 2002 decreased $4,513,000, or 10%, from 2001 largely due
+to lower shipments into the Company's point of sale ("POS") and Other markets.
+Overall, international sales decreased by $3,216,000 or 41%, primarily due a
+reduction in (1) revenue related to the British Post Office project
+(approximately $400,000), (2) kiosk printer shipments for use in a Canadian
+government application (approximately $1,500,000), (3) shipments of our thermal
+fiscal printer in Europe (approximately $1,000,000) and (4) POS revenue through
+distribution in Europe and Latin America (approximately $500,000), partially
+offset by an increase in international sales of our gaming and lottery printers
+(approximately $300,000).
+Point of sale: Sales of our POS printers decreased approximately
+$3,234,000, or 16%.
+International POS printer shipments decreased approximately $1,878,000,
+or 30%, to $4,315,000, for several reasons. First, sales to ICL Pathway for the
+British Post Office project, which included printer shipments, spare parts and
+service revenue, declined by approximately $400,000 to $1,800,000 in 2002. We
+completed shipping printers for the British Post Office project during the first
+quarter of 2001, and expect no future sales for this project, other than spare
+parts and service of approximately $300,000 per quarter during 2003. Secondly,
+shipments of our thermal fiscal printer in Europe declined by approximately
+$1,000,000 to $950,000 in 2002. Although we continue to pursue sales of our
+fiscal printer, such sales are principally project-oriented, and we cannot
+predict if and when future sales may occur. Lastly, we experienced a decrease of
+approximately $500,000 in sales through distribution, primarily in Latin
+America, and to a lesser extent, in Europe. We continue to actively seek
+additional distribution partners in both Latin America and Europe in order to
+increase our breadth of coverage and future sales in these regions.
+9
+Domestic POS printer sales totaling $12,458,000 fell by $1,356,000, or
+10%, as we experienced softness in demand from our domestic distributors,
+particularly in the first and third quarters of 2002. However, sales in 2002
+included increasing sales of our POSjet line of inkjet printers, which we expect
+to continue into 2003.
+Due to on-going economic weakness and continued lower capital spending
+by users of our POS products, we expect continued worldwide softness in demand
+for our POS products in 2003. As a result, we expect sales into the POS market
+for the first quarter of 2003 to be consistent with those reported for the
+fourth quarter of 2002.
+Gaming and lottery: Sales into the gaming and lottery market increased
+by $1,117,000, or 6%, from 2001, primarily due to stronger sales of our video
+lottery terminal ("VLT") and slot machine printers, largely offset by lower
+sales of lottery printers to GTECH.
+Shipments to GTECH, which included on-line and in-lane lottery printers
+and spare parts revenue, decreased $3,750,000 to approximately $10,700,000 in
+2002. Sales of impact on-line lottery printers and spare parts totaled
+approximately $10,050,000 in 2002, compared to $14,300,000 in 2001. We have
+approximately $500,000 of orders from GTECH for impact on-line lottery printers
+for delivery in the first quarter of 2003. We do not expect any further
+shipments of impact on-line lottery printers in 2003 beyond the first quarter.
+Shipments of in-lane lottery printers totaled approximately $700,000 in 2002
+compared to $200,000 in 2001. Since sales of in-lane lottery printers are
+project-oriented, we cannot predict if and when future sales may occur. In July
+2002, we entered into a 5-year agreement with GTECH to provide a newly designed
+thermal on-line lottery printer. We have received an initial order from GTECH
+for approximately $4.3 million of our new thermal on-line lottery printers, all
+of which we expect to ship during 2003, with volume shipments beginning in the
+second quarter of 2003. We expect to receive additional thermal printer orders
+from GTECH for delivery in 2003.
+Sales of our gaming printers, which included VLT and slot machine
+printers, and related spare parts and repairs, increased by approximately
+$4,900,000 to $10,300,000. The increase in gaming printer sales resulted from
+two factors; (1) increased installations of our VLT printers in West Virginia
+and other states, including approximately $1,600,000 of sales of a custom
+printer to one customer and (2) increased sales of our casino printers,
+primarily for use in slot machines at casinos throughout North America that
+print receipts instead of issuing coins ("ticket-in, ticket-out"). Based on
+existing orders and sales opportunities, we expect sales of our casino printers
+to continue to increase in 2003, beginning in the second quarter,
+as more regulatory approvals are expected to be obtained and more casinos are
+expected to convert to ticket-in, ticket-out slot machines. We also expect sales
+of our VLT printers to increase in 2003 compared to 2002 due to the VLT
+initiative in the state of New York.
+Other: Sales of our printers into other markets decreased by $2,396,000
+or 58%, to $1,702,000 from 2001. During 2001, we shipped approximately
+$1,500,000 of our thermal kiosk printers for use in a Canadian government
+application. We made no shipments of these printers in 2002. We do not expect to
+make any future shipments for this application. In addition, sales of our other
+kiosk and banking printers and related spare parts declined by approximately
+$900,000. Since printer sales into these markets are principally
+project-oriented, we cannot predict if and when future sales may occur. Due to
+steadily declining sales and low anticipated future sales, we have decided to
+exit these markets. As such, beginning in the first quarter of 2003, we will
+combine any remaining sales from our Other markets into POS market sales, and no
+longer separately report sales in our Other market category.
+GROSS PROFIT. Gross profit increased by $442,000, or 5%, to
+$10,216,000, and the gross margin also increased to 25.9% from 22.2%. Both gross
+profit and gross margin for 2002 benefited from an improved sales mix and cost
+reductions resulting from the Consolidation. We expect gross margin for the
+first quarter of 2003 to be consistent with that of the full-year 2002, and to
+increase in the second quarter of 2003, as we begin volume shipments of our new
+thermal on-line lottery printer to GTECH and anticipate increasing sales of our
+slot machine printers.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses decreased $1,045,000, or 34%, and also decreased as a
+percentage of net sales to 5.1% from 7.0%. This decrease is primarily due to a
+reduction in engineering staff at our Wallingford, CT facility due to the
+Consolidation.
+SELLING AND MARKETING. Selling and marketing expenses decreased
+$543,000, or 12%, and decreased as a percentage of net sales to 10.2% from
+10.4%. Such expenses decreased mostly due to lower planned promotional and
+advertising expenses and staff reductions resulting from the Consolidation.
+10
+GENERAL AND ADMINISTRATIVE. General and administrative expenses
+decreased by $1,909,000, or 31%, and decreased as a percentage of net sales to
+10.6% from 13.9%. The decrease primarily resulted from (1) staff reductions
+resulting from the Consolidation and (2) the inclusion in 2001 of $680,000 of
+accelerated depreciation on certain assets located at the Company's Wallingford,
+CT facility (primarily leasehold improvements and computer equipment) whose
+useful lives were shortened as a result of the Consolidation.
+BUSINESS CONSOLIDATION AND RESTRUCTURING. We incurred $958,000 of
+expenses related to the Consolidation in 2002. These expenses were substantially
+the result of a revision to our estimate for non-cancelable lease payments
+included in the restructuring accrual at September 30, 2002. Based on regional
+softness in demand in the commercial real estate market, we increased our
+restructuring accrual by $900,000 to reflect the longer period of time now
+projected to sublease our Wallingford, CT facility. The accrual now includes
+estimated non-cancelable lease payments and other related costs through
+September 30, 2004. We do not expect to incur any additional charges related to
+the Consolidation during 2003.
+During 2001, we incurred approximately $3,321,000 of Consolidation
+expenses, which primarily included a portion of employee severance and
+termination related expenses and facility closure and consolidation expenses
+(including moving expenses, estimated non-cancelable lease payments and other
+costs). See Note 8 to the Consolidated Financial Statements.
+OPERATING LOSS. During 2002, we reported an operating loss of $984,000,
+or 2.5% of net sales, compared to an operating loss of $7,286,000, or 16.6% of
+net sales, in 2001. The reduction in our operating loss was due to (1)
+significantly reduced operating expenses as a direct result of the
+Consolidation, (2) lower Consolidation expenses and (3) higher gross margin.
+INTEREST. Net interest expense decreased by $205,000 to $192,000 in
+2002, due largely to a significant reduction in our average outstanding
+borrowings under our revolving bank facility resulting from significantly lower
+inventories (approximately $2,200,000), receipt of an advance payment from a
+customer, and to a lesser extent, lower interest rates. We expect revolving
+borrowings to increase to approximately $5 million by the end of the first
+quarter of 2003, as we purchase inventory for anticipated higher sales volume in
+the second quarter of 2003. As a result, we expect interest expense to increase
+in the first quarter of 2003. See "Liquidity and Capital Resources" below.
+OTHER INCOME. Other income for 2002 includes a one-time gain of
+$145,000 resulting from the receipt of 2,146 shares of common stock from our
+health insurance company, Anthem, Inc., upon its demutualization. We sold these
+shares during the third quarter of 2002. This gain was partially offset by
+approximately $50,000 of transaction exchange loss recorded by our UK subsidiary
+during 2002, due to the strengthening of the British pound against the dollar,
+mostly in the second quarter of 2002.
+INCOME TAXES. We recorded an income tax benefit of $390,000 and
+$2,748,000 in 2002 and 2001, respectively, at an effective rate of approximately
+36.0% in each period. We expect to record income taxes at a similar effective
+rate during 2003.
+NET LOSS. We reported a net loss in 2002 of $692,000, or $0.19 per
+share (basic and diluted) after giving effect to $358,000 of dividends and
+accretion charges on preferred stock. This compares to a net loss of $4,922,000,
+or $0.95 per share (basic and diluted) after giving effect to $358,000 of
+dividends and accretion charges on preferred stock in 2001. In future quarters,
+dividends and accretion charges on preferred stock will be approximately
+$90,000, before the effect of any conversion or redemption of the preferred
+stock.
+(ii) YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER
+31, 2000
+NET SALES. Net sales by market for the years ended December 31, 2001
+and 2000 were as follows:
+Year ended Year ended
+(In thousands) December 31, 2001 December 31, 2000
+-------------------- ---------------------
+Point of sale $ 20,007 45.5% $ 29,396 54.7%
+Gaming and lottery 19,869 45.2 19,298 35.9
+Other 4,098 9.3 5,026 9.4
+-------------------- ---------------------
+$ 43,974 100.0% $ 53,720 100.0%
+==================== =====================
+International $ 7,922 18.0% $ 16,320 30.4%
+==================== =====================
+11
+Net sales for 2001 decreased $9,746,000, or 18%, from 2000 largely due
+to significantly lower shipments into the Company's POS market. International
+sales decreased to $7,922,000, or 18.0% of net sales in 2001, from $16,320,000,
+or 30.4% of net sales in 2000.
+Point of sale: Sales of our POS printers decreased approximately
+$9,389,000, or 32%. International POS printer shipments decreased approximately
+$9,438,000, to $6,193,000, largely due to lower printer shipments to ICL Pathway
+for the British Post Office project. Sales for the British Post Office project,
+which included printer shipments and service revenue, were approximately
+$1,900,000 in 2001 compared to $10,900,000 in 2000. We completed shipping
+printers for the British Post Office project during the first quarter of 2001,
+and no future sales, other than spare parts and service, are expected. In
+addition to lower sales to ICL Pathway, we experienced a decrease in sales,
+primarily to Europe, of approximately $1,200,000 through Okidata, our former
+exclusive distribution partner in Europe. As of May 2001, Okidata no longer
+exclusively distributes our printers in Europe. We also experienced a decline of
+approximately $300,000 of sales to Latin America through Okidata, our
+distribution partner in Latin America. The decrease in international POS sales
+to ICL Pathway and Okidata was somewhat offset by an increase of approximately
+$1,200,000 of shipments of our thermal fiscal printer in Europe.
+Despite adverse economic conditions, domestic POS printer sales
+increased slightly by $49,000 to $13,814,000.
+Gaming and lottery: Sales of our gaming and lottery printers increased
+approximately $571,000, or 3%, from the prior year. Sales of our on-line lottery
+printers and spare parts to GTECH increased by approximately $2,400,000, to
+approximately $14,300,000 in 2001, compared to $11,900,000 in 2000. We received
+follow-on orders from GTECH for approximately $9,800,000 of on-line lottery
+printers, of which approximately $9,300,000 was delivered in 2002 and $500,000
+will be delivered in 2003. In addition to the increase of printer sales to
+GTECH, sales of our slot machine printers and other gaming printers increased by
+approximately $900,000. The slot machine printers are primarily for use in
+casinos in California and Nevada.
+Offsetting the increase of on-line lottery printer and spare parts
+sales to GTECH and increased slot machine printer sales was a decrease of
+approximately $2,700,000 in sales of our VLT printers to approximately
+$1,700,000 in 2001. Sales of these VLT printers were unusually high in the last
+half of 2000.
+Other: Sales of our printers into other markets decreased by $928,000,
+or 18%, from the prior year. During 2001, sales of our ATM printer and related
+spare parts decreased by approximately $1,700,000. In addition, sales decreased
+by approximately $800,000 due to sales of kiosk printers to customers for
+projects primarily in the third quarter of 2000 that did not repeat in 2001.
+Offsetting these decreases was an increase of approximately $1,600,000 of our
+thermal kiosk printers for use in a Canadian government application during 2001.
+No shipments of these printers were made in 2000. Since printer sales into the
+kiosk printer market are principally project-oriented, the Company cannot
+predict if and when future sales may occur.
+GROSS PROFIT. Gross profit decreased $4,368,000, or 31%, and the gross
+margin also declined to 22.2% from 26.3%. Both gross profit and gross margin for
+2001 were adversely impacted by lower sales volume, due primarily to the absence
+of printer shipments for the British Post Office project.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses decreased $411,000, or 12%, to $3,070,000 from 2000. This
+decrease was primarily due to a reduction in engineering staff at our
+Wallingford facility resulting from the Consolidation. Engineering and product
+development expense increased as a percentage of net sales to 7.0% from 6.5%,
+due to lower sales volume in 2001 compared to 2000.
+SELLING AND MARKETING. Selling and marketing expenses decreased
+$516,000, or 10%, to $4,570,000 from the prior year. Such expenses decreased
+primarily due to (1) unusually high marketing and promotional expenses incurred
+in 2000 related to the April 2000 launch of our new family of printers utilizing
+inkjet printing technology and (2) a reduction in marketing staff. Selling and
+marketing expenses as a percentage of net sales increased to 10.3% from 9.5%,
+due to lower sales volume in 2001 compared to 2000.
+GENERAL AND ADMINISTRATIVE. General and administrative expenses
+increased by $559,000, or 10%, to $6,099,000 from 2000 and increased as a
+percentage of net sales to 13.9% from 10.3%. The increase in expenses primarily
+resulted from the inclusion of $680,000 of accelerated depreciation on certain
+assets (primarily leasehold improvements and computer equipment) located at our
+Wallingford, CT facility whose useful lives have been shortened as a result of
+the Consolidation. These increases were partially offset by a reduction of staff
+and certain related expenses at our Wallingford, CT facility resulting from the
+Consolidation.
+12
+BUSINESS CONSOLIDATION AND RESTRUCTURING. During 2001, we incurred
+approximately $3,321,000 of business consolidation and restructuring expenses
+related to the Consolidation. These expenses primarily included employee
+severance and termination related expenses, and facility closure and
+consolidation expenses (including moving expenses, estimated non-cancelable
+lease payments and other costs). See Note 8 to the Consolidated Financial
+Statements.
+OPERATING LOSS. We incurred an operating loss of $7,286,000 in 2001
+compared to an operating loss of $154,000 in 2000. The operating loss in 2001
+resulted primarily from lower gross profit on lower sales in 2001 compared to
+2000 as well as expenses related to the Consolidation.
+INTEREST. Net interest expense decreased to $397,000 from $649,000 in
+2000 due to decreased average outstanding borrowings on our line of credit and a
+lower average interest rate on such borrowings. See "Liquidity and Capital
+Resources" below.
+INCOME TAXES. As a result of our loss before income taxes, we recorded
+an income tax benefit of $2,748,000 and $448,000, or an effective rate of 35.8%
+and 56.6%, in 2001 and 2000, respectively. The abnormally high effective tax
+benefit rate in 2000 is primarily due to the recognition of certain tax credits
+and the benefit from our foreign sales corporation on relatively low pre-tax
+amounts.
+NET LOSS. We incurred a net loss during 2001 of $4,922,000, or $0.95
+per share (basic and diluted) after giving effect to $358,000 of dividends and
+accretion charges on preferred stock issued in April 2000. This compares to a
+net loss for 2000 of $344,000, or $0.12 per share (basic and diluted) after
+giving effect to $320,000 of dividends and accretion charges on preferred stock
+issued in April 2000. In future quarters, dividends and accretion charges on
+preferred stock will be approximately $90,000, before the effect of any
+conversion or redemption of the preferred stock.
+(B) LIQUIDITY AND CAPITAL RESOURCES
+CASH FLOW
+We generated cash from operations of $3,679,000 in 2002, compared to
+$1,345,000 in 2001. The significant increase in cash generated from operations
+in 2002 was largely the result of a significantly reduced net loss. During 2002,
+we reported a net loss of $692,000 compared to $4,922,000 in 2001.
+During 2002, depreciation and amortization totaled $2,119,000 compared
+to $3,398,000 in 2001. Such expenses in 2001 included accelerated depreciation
+and depreciation on certain leasehold improvements and other fixed assets that
+were disposed of during 2001 as a result of the Consolidation. Deferred taxes,
+net of an increase in refundable income taxes, decreased by $740,000, due
+primarily to a refund of taxes received in 2002 as a result of a net operating
+loss carryback. In order to utilize all of our deferred tax assets at December
+31, 2002 (approximately $2.4 million), we will need to generate approximately $7
+million of taxable income in future years. Receivables decreased only slightly
+from year-end (approximately $8,000). Inventories were significantly reduced
+during 2002 by approximately $2,198,000 due to improved inventory management and
+changes related to inventory absolescence. Despite our continued focus on
+inventory reduction, we expect inventories to increase in the first quarter of
+2003, as we prepare for volume shipments of our new thermal on-line lottery
+printer for GTECH and anticipated increasing sales of our gaming printers in the
+second quarter of 2003. Accounts payable increased slightly from the prior
+year-end (approximately $80,000), and we expect accounts payable to increase in
+the first quarter of 2003 in proportion to our expected inventory increase.
+Accrued liabilities and other liabilities, excluding accrued restructuring,
+increased by $688,000, primarily due to an increase in deferred revenue on an
+extended warranty contract with a certain customer.
+Offsetting the activities providing cash in the year was a net
+reduction in the restructuring accrual of $1,284,000, representing payouts for
+severance pay and related benefits and lease payments for the Wallingford
+Facility of $2,242,000 offset by an additional accrual of $958,000, primarily
+for lease termination expenses (See "Consolidation Expenses" below).
+Our capital expenditures were approximately $577,000 and $1,382,000 in
+2002 and 2001, respectively. These expenditures for 2002 primarily included new
+product tooling and computer equipment. We expect capital expenditures for 2003
+to be approximately $1,800,000, primarily for tooling for our new thermal
+lottery printer for GTECH and other new products.
+We used $2,703,000 in financing activities, largely due to repayments
+on our revolving credit facility and term loan and payments of cash dividends on
+our preferred stock.
+13
+WORKING CAPITAL
+Our working capital increased to $8,577,000 at December 31, 2002 from
+$8,366,000 at December 31, 2001. The current ratio also increased to 2.13 to 1
+at December 31, 2002 from 1.90 to 1 at December 31, 2001. The increase in both
+working capital and the current ratio was largely due to (1) lower inventories
+($2,198,000) and (2) a decrease in the current portion of accrued restructuring
+expenses of approximately $2,100,000 related to the Consolidation.
+CONTINGENT LIABILITIES
+In November 2002, we were advised that certain POS printers sold by us
+since late 1999 may use technology covered by recently issued patents of a third
+party competitor. We are analyzing the cited patents for validity and
+applicability to our products. In an effort to resolve this matter, we have
+offered to pay approximately $160,000, while the other party seeks payment of up
+to $950,000 (the ''Patent Resolution Payment''). While the outcome of our patent
+analysis and discussions cannot be predicted, we have recognized a charge of
+$160,000 in cost of sales in the fourth quarter of 2002. This charge represents
+what we believe to be a fair and reasonable payment.
+CREDIT FACILITY AND BORROWINGS
+On May 25, 2001, we entered into a three-year, $13.5 million credit
+facility (the "LaSalle Credit Facility") with LaSalle Business Credit, Inc.
+("LaSalle") expiring on May 25, 2004 to replace its prior credit facility with
+Webster Bank. The LaSalle Credit Facility provides a $12 million revolving
+credit line, a $0.5 million term loan and a $1 million equipment loan facility.
+Borrowings under the LaSalle Credit Facility bear a floating rate of interest
+based on LaSalle's prime rate. Under certain circumstances, we may select a
+fixed interest rate for a specified period of time of up to 180 days on
+borrowings based on the current LIBOR rate.
+On October 30, 2001, we amended the LaSalle Credit Facility. Under the
+terms of the amendment ("LaSalle Amendment No. 1"), LaSalle (1) waived
+compliance with the minimum EBITDA financial covenant as of September 30, 2001,
+(2) revised certain other financial covenants through December 31, 2001, (3)
+increased the floating rate of interest on borrowings under the revolving credit
+line to LaSalle's prime rate plus 1.0%, or the current LIBOR rate plus 3.5%, and
+(4) increased the floating rate of interest on borrowings under the term loan
+and equipment loan to LaSalle's prime rate plus 1.5%, or the current LIBOR rate
+plus 4.0%. Upon execution of LaSalle Amendment No. 1, we paid a fee of $20,000
+to LaSalle.
+On December 21, 2001, we amended the LaSalle Credit Facility to reset
+certain financial covenants for 2002 and beyond ("LaSalle Amendment No. 2").
+Upon execution of LaSalle Amendment No. 2, we paid a fee of $5,000 to LaSalle.
+On November 12, 2002, we amended the LaSalle Credit Facility. Under the
+terms of the amendment ("LaSalle Amendment No. 3"), LaSalle (1) waived
+compliance with the minimum EBITDA, minimum tangible net worth and fixed charge
+coverage ratio financial covenants as of September 30, 2002 and (2) revised
+these covenants to exclude the effect of $900,000, of the total $912,000, of
+restructuring charges incurred in the third quarter. Absent the $900,000
+restructuring charge, we would have been in compliance with the above covenants
+at September 30, 2002. Upon execution of LaSalle Amendment No. 3, we paid a fee
+of $20,000 to LaSalle.
+On March 24, 2003, we amended the LaSalle Credit Facility. Under the
+terms of the amendment ("LaSalle Amendment No. 4"), LaSalle (1) waived
+compliance with the minimum EBITDA covenant as of December 31, 2002, (2) revised
+this covenant and certain other financial covenants through May 2004 and (3)
+eliminated the availability of the $1 million equipment loan facility due to
+expire in May 2003. In addition, LaSalle has restricted $1 million of our
+borrowing availability under the revolving credit line pending the outcome of
+the Patent Resolution Payment. Upon execution of LaSalle Amendment No. 4, we
+paid a fee of $25,000 to LaSalle.
+As of December 31, 2002 we had $2,541,000 and $350,000 outstanding on
+the revolving credit line and term loan, respectively, and no borrowings under
+the equipment loan, leaving undrawn commitments under the LaSalle Credit
+Facility of $9,459,000. Annual principal payments on the term loan are $100,000.
+SALE OF PREFERRED STOCK
+On April 7, 2000 we sold 4,000 shares of 7% Series B Cumulative
+Convertible Redeemable Preferred Stock (the "Preferred Stock") to Advance
+Capital Advisors, L.P. and its affiliate in consideration of $1,000 per share
+(the "Stated Value"), for a total of $4,000,000, less issuance costs of
+approximately $200,000. The Preferred Stock is redeemable by the holders on
+April 7, 2005 at $1,000 per share plus any unpaid dividends. We used the net
+proceeds to repay outstanding borrowings under our revolving credit facility. We
+paid $280,000 in 2002 and 2001, and $205,000 in 2000, of cash dividends to
+Advance Capital Advisors, L.P. and expect to pay $280,000 in 2003.
+14
+CAPITAL EXPENDITURES
+Our capital expenditures were approximately $577,000, $1,382,000 and
+$2,415,000 in 2002, 2001 and 2000, respectively. These expenditures primarily
+included new product tooling, and to a lesser extent, computer equipment, and
+factory machinery and equipment. Our capital expenditures for 2003 are expected
+to be approximately $1,800,000, a majority for new product tooling.
+CONSOLIDATION EXPENSES
+During 2001, we incurred approximately $4,096,000 of business
+consolidation, restructuring and related charges as a result of the
+Consolidation. These expenses primarily included employee severance and
+termination related expenses, facility closure and consolidation expenses
+(including moving expenses, estimated non-cancelable lease payments and other
+costs) and accelerated depreciation and asset disposal losses on certain
+leasehold improvements and other fixed assets. Although the Consolidation was
+substantially completed in 2001, we incurred an additional $958,000 of
+non-recurring costs associated with the Consolidation during 2002. During 2002,
+we revised our estimate for non-cancelable lease payments included in the
+restructuring accrual. Based on regional softness in demand in the commercial
+real estate market, we increased the restructuring accrual by $900,000 to
+reflect the longer period of time now projected to sublease our Wallingford, CT
+facility. The accrual now includes estimated non-cancelable lease payments and
+other related costs through approximately September 30, 2004. As a result of the
+Consolidation, we have significantly lowered our cost structure in 2002, with
+annual cost savings of over $4 million compared to 2001. We do not expect to
+incur any additional charges related to the Consolidation during 2003. See Note
+8 to the Consolidated Financial Statements for further detail.
+Of the total of $5,054,000 of Consolidation expenses, approximately
+$4,300,000 requires cash outlays. We paid approximately $2,200,000 and $400,000
+of these costs, in 2002 and 2001, respectively. We expect to pay approximately
+$900,000 of these costs in 2003, and the remaining $800,000 in 2004. As a result
+of the Consolidation, we realized improved gross margins and lower operating
+expenses in 2002, and lowered our operating income breakeven point from $54
+million to $42 million in sales, which we believe will provide us with
+additional operating leverage in 2003.
+RESOURCE SUFFICIENCY
+We believe that cash flows generated from operations and borrowings
+available under the LaSalle Credit Facility, as amended, will provide sufficient
+resources to meet the Company's working capital needs, including costs
+associated with the Consolidation and the Patent Resolution Payment, finance its
+capital expenditures and meet its liquidity requirements through December 31,
+2003. However, we recognize that the level of financial resources available to
+us is an important competitive factor, and we will consider additional financing
+sources as appropriate, including raising additional equity capital on an
+on-going basis as market factors and our needs suggest. We currently expect to
+refinance any outstanding borrowings at the expiration of the LaSalle Credit
+Facility in May 2004.
+(C) IMPACT OF INFLATION
+TransAct believes that its business has not been affected to a
+significant degree by inflationary trends because of the low rate of inflation
+during the past three years, nor does it believe it will be significantly
+affected by inflation during 2003.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
+INTEREST RATE RISK
+The Company's exposure to market risk for changes in interest rates
+relates primarily to borrowings under the LaSalle Credit Facility. These
+borrowings bear interest at variable rates and the fair value of this
+indebtedness is not significantly affected by changes in market interest rates.
+An effective increase or decrease of 10% in the current effective interest rates
+under the LaSalle Credit Facility would not have a material effect on the
+Company's results of operations or cash flow.
+FOREIGN CURRENCY EXCHANGE RISK
+A substantial portion of the Company's sales are denominated in U.S.
+dollars and, as a result, the Company has relatively little exposure to foreign
+currency exchange risk with respect to sales made. This exposure may change over
+time as business practices evolve and could have a material adverse impact on
+the Company's financial results in the future. The Company does not use forward
+exchange contracts to hedge exposures denominated in foreign currencies or any
+other derivative financial instruments for trading or speculative purposes. The
+effect of an immediate 10% change in exchange rates would not have a material
+impact on the Company's future results of operations or cash flow.
+15
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
+Page
+Number
+------
+Report of Independent Accountants 17
+TransAct Technologies Incorporated consolidated financial statements:
+Consolidated balance sheets as of December 31, 2002 and December 31, 2001. 18
+Consolidated statements of operations for the years ended December 31, 2002, 2001 and 2000. 19
+Consolidated statements of cash flows for the years ended December 31, 2002, 2001 and 2000. 20
+Consolidated statement of changes in shareholders' equity for the period from December 31, 21
+1999 through December 31, 2002.
+Notes to consolidated financial statements. 22
+16
+REPORT OF INDEPENDENT ACCOUNTANTS
+To the Board of Directors and Shareholders
+of TransAct Technologies Incorporated:
+In our opinion, the accompanying consolidated balance sheets and the
+related consolidated statements of operations, of cash flows, and of changes in
+shareholders' equity present fairly, in all material respects, the financial
+position of TransAct Technologies Incorporated and its subsidiaries at December
+31, 2002 and 2001, and the results of their operations and their cash flows for
+each of the three years in the period ended December 31, 2002 in conformity with
+accounting principles generally accepted in the United States of America. 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 of these statements in accordance with
+auditing standards generally accepted in the United States of America, which
+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, assessing the accounting principles
+used and significant estimates made by management, and evaluating the overall
+financial statement presentation. We believe that our audits provide a
+reasonable basis for the opinion expressed above.
+As discussed in Note 2 to the consolidated financial statements, the
+Company adopted Statement of Financial Accounting Standards No. 142, "Goodwill
+and Other Intangible Assets" effective January 1, 2002.
+/s/ PricewaterhouseCoopers LLP
+Hartford, Connecticut
+February 27, 2003, except for Note 10
+which is as of March 26, 2003.
+17
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED BALANCE SHEETS
+(In thousands, except share data)
+December 31, December 31,
+2002 2001
+------------ ------------
+ASSETS:
+Current assets:
+Cash and cash equivalents $ 902 $ 417
+Receivables, net (Note 3) 4,039 4,047
+Inventories (Note 4) 8,435 10,633
+Refundable income taxes (Note 14) 228 -
+Deferred tax assets (Note 14) 2,221 2,382
+Other current assets 327 212
+------------ -----------
+Total current assets 16,152 17,691
+------------ -----------
+Fixed assets, net (Note 5) 3,924 5,190
+Goodwill, net (Note 1) 1,469 1,469
+Deferred tax assets (Note 14) 193 1,120
+Other assets 292 321
+------------ -----------
+5,878 8,100
+------------ -----------
+Total assets $ 22,030 $ 25,791
+============ ===========
+LIABILITIES AND SHAREHOLDERS' EQUITY:
+Current liabilities:
+Current portion of term loan $ 100 $ 100
+Accounts payable 2,983 2,903
+Accrued liabilities (Notes 6 and 7) 3,592 3,320
+Accrued restructuring expenses (Note 8) 900 3,002
+------------ -----------
+Total current liabilities 7,575 9,325
+------------ -----------
+Revolving bank loan payable (Note 10) 2,541 4,994
+Long-term portion of term loan 250 350
+Accrued restructuring expenses (Note 8) 818 -
+Other liabilities 477 61
+------------ -----------
+4,086 5,405
+------------ -----------
+Total liabilities 11,661 14,730
+------------ -----------
+Commitments and contingencies (Note 11)
+Mandatorily redeemable preferred stock, Series B, 7%
+cumulative convertible, $0.01 par value, 8,000 shares
+authorized, 4,000 shares issued and outstanding (Note 16) 3,824 3,746
+------------ -----------
+Shareholders' equity (Notes 12 and 13):
+Preferred stock, $0.01 par value, 4,792,000
+authorized, none issued and outstanding - -
+Preferred stock, Series A, $0.01 par value, 200,000
+authorized, none issued and outstanding - -
+Common stock, $0.01 par value, 20,000,000 authorized,
+5,715,119 and 5,684,770 shares issued and outstanding 57 57
+Additional paid-in capital 6,308 6,303
+Retained earnings 599 1,649
+Unamortized restricted stock compensation (97) (286)
+Loan receivable from officer (Note16) (330) (330)
+Accumulated other comprehensive income 8 (78)
+------------ -----------
+Total shareholders' equity 6,545 7,315
+------------ -----------
+Total liabilities and equity $ 22,030 $ 25,791
+============ ===========
+See accompanying notes to consolidated financial statements.
+18
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF OPERATIONS
+(In thousands, except per share data)
+Year Ended December 31,
+2002 2001 2000
+--------- --------- ---------
+Net sales $ 39,461 $ 43,974 $ 53,720
+Cost of sales 29,245 34,200 39,578
+--------- --------- ---------
+Gross profit 10,216 9,774 14,142
+--------- --------- ---------
+Operating expenses:
+Engineering, design and product
+development expenses 2,025 3,070 3,481
+Selling and marketing expenses 4,027 4,570 5,086
+General and administrative expenses
+(Note 8) 4,190 6,099 5,540
+Business consolidation and restructuring
+expenses (Note 8) 958 3,321 189
+--------- --------- ---------
+11,200 17,060 14,296
+--------- --------- ---------
+Operating loss (984) (7,286) (154)
+--------- --------- ---------
+Other income (expense):
+Interest, net (192) (397) (649)
+Other, net (Note 16) 94 13 11
+--------- --------- ---------
+(98) (384) (638)
+--------- --------- ---------
+Loss before income taxes (1,082) (7,670) (792)
+Income tax benefit (Note 14) (390) (2,748) (448)
+--------- --------- ---------
+Net loss (692) (4,922) (344)
+Dividends and accretion charges on preferred
+stock (Note 16) (358) (358) (320)
+--------- --------- ---------
+Net loss available to common
+shareholders $ (1,050) $ (5,280) $ (664)
+========= ========= =========
+Net loss per share:
+Basic and diluted $ (0.19) $ (0.95) $ (0.12)
+========= ========= =========
+Shares used in per share calculation:
+Basic and diluted 5,636 5,551 5,504
+========= ========= =========
+See accompanying notes to consolidated financial statements.
+19
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+Year Ended December 31,
+2002 2001 2000
+--------- --------- ---------
+Cash flows from operating activities:
+Net loss $ (692) $ (4,922) $ (344)
+Adjustments to reconcile net loss to net cash
+provided by operating activities:
+Depreciation and amortization 2,119 3,398 2,750
+Deferred income taxes 968 (2,743) (78)
+Loss on disposal of fixed assets - 209 -
+Changes in operating assets and liabilities:
+Receivables 8 2,090 (1,274)
+Inventories 2,198 (776) 400
+Refundable income taxes (228) - -
+Other current assets (115) 599 (415)
+Other assets (63) (326) (162)
+Accounts payable 80 213 (366)
+Accrued liabilities and other liabilities 688 706 (283)
+Accrued restructuring expenses (1,284) 2,897 105
+--------- --------- ---------
+Net cash provided by operating activities 3,679 1,345 333
+--------- --------- ---------
+Cash flows from investing activities:
+Purchases of fixed assets (577) (1,382) (2,415)
+Loans to officers - - 15
+Proceeds from sale of assets - 2 217
+--------- --------- ---------
+Net cash used in investing activities (577) (1,380) (2,183)
+--------- --------- ---------
+Cash flows from financing activities:
+Revolving bank loan repayments, net (2,453) (950) (1,156)
+Term loan borrowings (repayments), net (100) 450 -
+Proceeds from option exercises 130 262 175
+Net proceeds from issuance of preferred stock - - 3,785
+Payments of cash dividends on preferred stock (280) (280) (205)
+--------- --------- ---------
+Net cash provided by (used in) financing
+activities (2,703) (518) 2,599
+--------- --------- ---------
+Effect of exchange rate changes on cash 86 (22) (36)
+--------- --------- ---------
+Increase (decrease) in cash and cash equivalents 485 (575) 713
+Cash and cash equivalents at beginning of period 417 992 279
+--------- --------- ---------
+Cash and cash equivalents at end of period $ 902 $ 417 $ 992
+========= ========= =========
+Supplemental cash flow information:
+Interest paid $ 252 $ 403 $ 696
+Income taxes paid (refunded), net (975) (637) 74
+See accompanying notes to consolidated financial statements.
+20
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
+(In thousands, except share data)
+Unamortized Loan Accumulated
+Common Stock Additional Restricted Receivable Other
+--------------------- Paid-in Retained Stock from Comprehensive
+Shares Amount Capital Earnings Compensation Officer Income
+---------- -------- ---------- -------- ------------ ---------- -------------
+Balance, December 31, 1999 5,576,800 56 5,656 7,592 (747) (330) (20)
+Issuance of restricted stock 5,000 - 44 - (44) - -
+Cancellation of restricted stock (3,800) - (36) - 36 - -
+Issuance of shares from exercise of
+stock options 25,000 - 150 - - - -
+Issuance of shares from employee
+stock purchase plan 4,827 - 24 - - - -
+Amortization of restricted stock
+compensation - - - - 278 - -
+Issuance of preferred stock warrants - - 175 - - - -
+Deemed dividend on beneficial
+conversion of preferred stock - - 56 (56) - - -
+Dividends paid on preferred stock - - - (205) - - -
+Accretion of preferred stock
+warrants and issuance costs - - - (58) - - -
+Comprehensive income (loss):
+Foreign currency translation
+adjustment - - - - - - (36)
+Net loss - - - (344) - - -
+---------- -------- ---------- -------- ------------ ---------- ------------
+Balance, December 31, 2000 5,607,827 56 6,069 6,929 (477) (330) (56)
+Issuance of restricted stock 20,000 - 95 - (95) - -
+Cancellation of restricted stock (3,000) - (22) - 22 - -
+Issuance of shares from exercise of
+stock options 53,500 1 233 - - - -
+Issuance of shares from employee
+stock purchase plan 6,443 - 28 - - - -
+Amortization of restricted stock
+compensation - - - - 264 - -
+Tax charge related to restricted
+stock vested - - (100) - - - -
+Dividends paid on preferred stock - - - (280) - - -
+Accretion of preferred stock warrants
+and issuance costs - - - (78) - - -
+Comprehensive income (loss):
+Foreign currency translation
+adjustment - - - - - - (22)
+Net loss - - - (4,922) - - -
+---------- -------- ---------- -------- ------------ ---------- ------------
+Balance, December 31, 2001 5,684,770 57 6,303 1,649 (286) (330) (78)
+Cancellation of restricted stock (600) - (5) - 5 - -
+Issuance of shares from exercise of
+stock options 26,100 - 111 - - - -
+Issuance of shares from employee
+stock purchase plan 4,849 - 19 - - - -
+Amortization of restricted stock
+compensation - - - - 184 - -
+Tax charge related to restricted
+stock vested - - (120) - - - -
+Dividends paid on preferred stock - - - (280) - - -
+Accretion of preferred stock
+warrants and issuance costs - - - (78) - - -
+Comprehensive income (loss):
+Foreign currency translation
+adjustment - - - - - - 86
+Net loss - - - (692) - - -
+---------- -------- ---------- -------- ------------ ---------- ------------
+Balance, December 31, 2002 5,715,119 $ 57 $ 6,308 $ 599 $ (97) $ (330) $ 8
+========== ======== ========== ======== ============ ========== ============
+See accompanying notes to consolidated financial statements
+21
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+1. BASIS OF PRESENTATION
+TransAct Technologies Incorporated ("TransAct" or the "Company") was
+incorporated in June 1996 and began operating as a stand-alone,
+publicly-held company in August 1996 to conduct the printer business that
+was formerly operated by certain subsidiaries of Tridex Corporation
+("Tridex").
+Certain prior year amounts have been reclassified to conform to the
+current year's presentation.
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+BUSINESS AND PRODUCTS: TransAct, through its primary operating facility
+in Ithaca, NY, operates in one industry segment, transaction-based printers
+and related products. TransAct designs, develops, manufactures and markets
+transaction-based printers under the Ithaca(R) and Magnetec(R) brand names.
+In addition, the Company markets related consumables, spare parts and
+service. The Company's printers are used worldwide to provide transaction
+records such as receipts, tickets, coupons, register journals and other
+documents. The Company focuses on two core markets: point-of-sale ("POS")
+and gaming and lottery. The Company sells its products to original
+equipment manufacturers ("OEM"), value-added resellers, selected
+distributors and directly to end-users. The Company's product distribution
+spans across the Americas, Europe, the Middle East, Africa, the Caribbean
+Islands and the South Pacific.
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing inkjet, thermal and impact printing
+technology for applications requiring up to 60 character columns in each of
+its vertical markets. The Company's printers are configurable, which offer
+customers the ability to choose from a variety of features and functions.
+Options typically include printed circuit board configuration, paper
+cutting devices, paper handling capacities and cabinetry color. In addition
+to its configurable printers, TransAct manufactures custom printers for
+certain OEM customers. In collaboration with these customers, the Company
+provides engineering and manufacturing expertise for the design and
+development of specialized printers.
+USE OF ESTIMATES: The preparation of financial statements in conformity
+with generally accepted accounting principles requires management to make
+estimates and assumptions that affect the reported amounts of assets and
+liabilities and disclosure of contingent liabilities at the date of the
+financial statements and the reported amounts of revenues and expenses
+during the reporting period. Estimates have been made in areas including
+inventory valuation, estimated lives of fixed assets and goodwill, deferred
+tax assets, accrued liabilities, restructuring reserves related to the
+Consolidation, allowance for doubtful accounts and tax provisions
+(benefits). Actual results could differ from those estimates.
+PRINCIPLES OF CONSOLIDATION: The accompanying consolidated financial
+statements include the accounts of the Company and its wholly-owned
+subsidiaries, after elimination of all material intercompany accounts and
+transactions.
+CASH AND CASH EQUIVALENTS: The Company considers all highly liquid
+investments with a maturity date of three months or less at date of
+purchase to be cash equivalents.
+INVENTORIES: Inventories are stated at the lower of cost (principally
+standard cost which approximates actual cost on a first-in, first-out
+basis) or market.
+FIXED ASSETS: Fixed assets are stated at cost. Depreciation is provided
+for primarily by the straight-line method over the estimated useful lives.
+The estimated useful life of tooling is five years; machinery and equipment
+is ten years; furniture and office equipment is five to ten years; and
+computer equipment is three years. Leasehold improvements are amortized
+over the shorter of the term of the lease or the useful life of the asset.
+Depreciation was $1,843,000, $2,858,000 and $2,176,000 in 2002, 2001
+and 2000, respectively. Depreciation for 2001 included $680,000 of
+accelerated depreciation on certain leasehold improvements and other fixed
+assets due to the closing of the Company's Wallingford, CT facility. As
+part of the facility closing, the Company disposed of $2,114,000 and
+$895,000 of fixed assets at cost, net of accumulated depreciation of
+$2,114,000 and $800,000 during 2002 and 2001, respectively. This resulted
+in a loss on disposal of $0 and $95,000 in 2002 and 2001, respectively.
+22
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+GOODWILL: The Company has adopted the provisions of Statement of
+Financial Accounting Standard No. 142, "Goodwill and Other Intangible
+Assets" ("FAS 142") on January 1, 2002. Under FAS 142, goodwill will no
+longer be amortized and will be tested for impairment at least annually at
+the reporting unit level.
+Prior to the adoption of FAS 142 on January 1, 2002, the Company had
+been amortizing goodwill related to the acquisition of (1) Ithaca
+Peripherals, Inc. ("Ithaca") in 1991 and (2) the ribbon business formerly
+conducted by Tridex ("Tridex Ribbon Business") in 1999. The original amount
+applicable to the Ithaca acquisition totaled $3,536,000 and was being
+amortized on the straight-line method over twenty years. The original
+amount applicable to the Tridex Ribbon Business acquisition totaled
+$180,000 and was being amortized on the straight-line method over five
+years. The Company recorded amortization of goodwill of approximately
+$134,000 and $91,000, net of taxes, during 2001 and 2000, respectively.
+FAS 142 requires that goodwill be tested annually for impairment. The
+Company has performed an impairment test as of January 1, 2003 and
+determined that no impairment has occurred.
+ACCRUED WARRANTY COSTS: The Company warranties its products for up to
+two years and records the estimated cost of such product warranties at the
+time the sale is recorded. Estimated warranty costs are based upon actual
+past experience of product returns and the related estimated cost of labor
+and material to make the necessary repairs.
+REVENUE RECOGNITION: Sales are recognized when evidence of an
+arrangement exists, delivery (based on shipping terms) has occurred, the
+selling price is fixed and determinable, and collectibility is reasonably
+assured. Revenue from extended warranty and maintenance agreements is
+recognized over the term of such agreements as services are performed.
+Sales to GTECH Corporation ("GTECH") (for lottery printers) accounted for
+approximately 27%, 33% and 22% of net sales during 2002, 2001 and 2000,
+respectively. Sales to ICL Pathway (for the British Post Office project)
+accounted for approximately 20% of net sales during 2000.
+FOREIGN CURRENCY: The financial position and results of operations of
+the Company's foreign subsidiaries are measured using local currency as the
+functional currency. Assets and liabilities of such subsidiaries have been
+translated at end of period exchange rates, and related revenues and
+expenses have been translated at weighted average exchange rates.
+Transaction gains (losses) are included in other income and amounted to
+$(52,000), $17,000, and $(26,000) in 2002, 2001 and 2000, respectively.
+INCOME TAXES: The income tax amounts reflected in the accompanying
+financial statements are accounted for under the liability method in
+accordance with FAS 109 "Accounting for Income Taxes." Deferred tax assets
+and liabilities are recognized for the estimated future tax consequences
+attributable to differences between the financial statement carrying
+amounts of existing assets and liabilities and their respective tax bases
+and operating loss and tax credit carryforwards. Deferred tax assets and
+liabilities are measured using enacted tax rates in effect for the year in
+which those temporary differences are expected to be recovered or settled.
+RESEARCH AND DEVELOPMENT EXPENSES: Research and development expenses
+include engineering, design and product development expenses incurred in
+connection with specialized engineering and design to introduce new
+products and to customize existing products, and are expensed as a
+component of operating expenses as incurred. The Company spent
+approximately $2,025,000, $3,070,000 and $3,481,000 on research and
+development expenses in 2002, 2001 and 2000, respectively.
+STOCK-BASED COMPENSATION: The Company has elected to follow Accounting
+Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
+("APB 25"), and related interpretations in accounting for its stock
+options. Since the exercise price of employee stock options granted by the
+Company generally equals the market price of the underlying stock on the
+date of grant, no compensation expense is recorded. The Company has adopted
+the disclosure-only provisions of Statement of Financial Accounting
+Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123").
+See Note 12.
+23
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+SEGMENT REPORTING: FASB Statement of Financial Accounting Standards No.
+131, "Disclosures about Segments of an Enterprise and Related Information"
+("FAS 131") requires that a public business enterprise report financial and
+descriptive information about its reportable operating segments. Generally,
+financial information is required to be reported on the basis that it is
+used internally for evaluating segment performance and allocating
+resources. The Company has assessed its operating and reportable segments
+and determined that it operates in one reportable segment as defined in FAS
+131.
+COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES: In September 2002,
+the FASB issued Statement of Financial Standard No. 146, "Accounting for
+Costs Associated with Exit or Disposal Activities" ("FAS 146"). This
+statement provides guidance on the recognition and measurement of
+liabilities associated with exit or disposal activities and requires that
+such liabilities be recognized when incurred. This statement is effective
+for exit or disposal activities initiated on or after January 1, 2003 and
+does not impact the recognition of costs under the Company's existing
+programs. The Company does not expect FAS 146 to impact the timing or
+recognition of costs associated with future exit or disposal activities.
+GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS FOR GUARANTEES: In
+November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
+Accounting and Disclosure Requirements for Guarantees, Including Indirect
+Guarantees of Indebtedness of Others" ("FIN 45"). The interpretation
+provides guidance on the guarantor's accounting and disclosure requirements
+for guarantees, including indirect guarantees of indebtedness. The
+accounting guidelines are applicable to guarantees issued after December
+31, 2002, irrespective of the guarantor's fiscal year-end. However, the
+disclosure requirements are effective for financial statements that end
+after December 15, 2002. The Company has adopted the disclosure provisions
+of FIN 45 during the fourth quarter of 2002.
+ACCOUNTING FOR STOCK-BASED COMPENSATION - TRANSITION AND DISCLOSURE: In
+December 2002, the FASB issued Statement of Financial Standards No. 148,
+"Accounting for Stock-Based Compensation - Transition and Disclosure - an
+amendment of FAS 123" ("FAS 148"). FAS 148 provides additional transition
+guidance for those entities that elect to voluntarily adopt the accounting
+provisions of FAS 123, Accounting for Stock-Based Compensation. FAS 148
+also mandates certain new disclosures that are incremental to those
+required by FAS 123. The provisions of FAS 148 are effective for fiscal
+years ending after December 15, 2002. The Company adopted the disclosure
+provisions of FAS 148 during the fourth quarter of 2002.
+The following table illustrates the effect on net loss, compensation
+expense and loss per share as if the Black-Scholes fair value method
+described in FAS 123, "Accounting for Stock-Based Compensation" had been
+applied to the Company's stock plans.
+Year Ended December 31,
+(In thousands, except per share data) 2002 2001 2000
+-------- -------- --------
+Net loss available to common shareholders:
+Net loss available to common shareholders, as reported $ (1,050) $ (5,280) $ (664)
+Add: Stock-based compensation expense included in reported
+net loss, net of tax 118 169 120
+Deduct: Stock-based compensation expense determined under
+fair value based method for all awards, net of tax (616) (870) (627)
+-------- -------- --------
+Pro forma net loss available to common shareholders $ (1,548) $ (5,981) $ (1,171)
+======== ======== ========
+Net loss per share:
+Basic and diluted:
+As report $ (0.19) $ (0.95) $ (0.12)
+Pro Forma $ (0.28) $ (1.08) $ (0.21)
+24
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+3. RECEIVABLES
+Receivables are net of the allowance for doubtful accounts. The
+reconciliation of the allowance for doubtful accounts is as follows:
+Year Ended December 31,
+2002 2001 2000
+------ ------ ------
+(In thousands)
+Balance at beginning of period $ 84 $ 107 $ 132
+Doubtful accounts provision (reversal) (2) 45 (24)
+Accounts written off, net of recoveries (4) (68) (1)
+------ ------ ------
+Balance at end of period $ 78 $ 84 $ 107
+====== ====== ======
+4. INVENTORIES
+The components of inventories are:
+December 31,
+(In thousands) 2002 2001
+-------- --------
+Raw materials and component parts $ 8,339 $ 10,299
+Work-in-process 1 25
+Finished goods 95 309
+-------- --------
+$ 8,435 $ 10,633
+======== ========
+5. FIXED ASSETS
+The components of fixed assets are:
+December 31,
+(In thousands) 2002 2001
+-------- --------
+Tooling, machinery and equipment $ 10,841 $ 11,295
+Furniture, office and computer equipment 3,291 4,107
+Leasehold improvements 465 794
+-------- --------
+14,597 16,196
+Less: accumulated depreciation and amortization (10,673) (11,006)
+-------- --------
+$ 3,924 $ 5,190
+======== ========
+6. ACCRUED LIABILITIES
+The components of accrued liabilities are:
+December 31,
+(In thousands) 2002 2001
+-------- --------
+Payroll and fringe benefits $ 505 $ 533
+Income taxes 455 604
+Warranty 644 710
+Deferred revenue 967 551
+Rent and occupancy 326 290
+Other 695 632
+-------- --------
+$ 3,592 $ 3,320
+======== ========
+25
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+7. ACCRUED PRODUCT WARRANTY LIABILITY
+The following table summarizes the activity recorded in the accrued
+product warranty liability during 2002 and 2001:
+Year ended December 31,
+(In thousands) 2002 2001
+------- -------
+Balance, beginning of year $ 710 $ 603
+Additions related to warranties issued 394 609
+Warranty costs incurred (460) (502)
+------- -------
+Balance, end of year $ 644 $ 710
+======= =======
+8. ACCRUED BUSINESS CONSOLIDATION AND RESTRUCTURING EXPENSES
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of
+this strategic decision, the Company undertook a plan to consolidate all
+manufacturing and engineering into its existing Ithaca, NY facility and
+close its Wallingford, CT facility (the "Consolidation"). As of December
+31, 2001, substantially all Wallingford product lines were successfully
+transferred to Ithaca, NY. The Company currently maintains a small
+component production line and service depot in Wallingford. The closing of
+the Wallingford facility resulted in the termination of employment of
+approximately 70 production, administrative and management employees. The
+Company has applied the consensus set forth in EITF 94-3, "Liability
+Recognition for Certain Employee Termination Benefits and Other Costs to
+Exit an Activity (Including Certain Costs Incurred in a Restructuring)" in
+recognizing the accrued restructuring expenses.
+During 2002, the Company incurred $958,000 of Consolidation expenses.
+Approximately $900,000 of these expenses was the result of a revision to
+the Company's estimate for non-cancelable lease payments included in the
+restructuring accrual. Based on regional softness in demand in the
+commercial real estate market, the Company increased its restructuring
+accrual by approximately $900,000 to reflect the longer period of time now
+projected to sublease its Wallingford, CT facility. The accrual now
+includes estimated non-cancelable lease payments and other related costs
+through September 30, 2004.
+The following table summarizes the activity recorded in the
+restructuring accrual during 2002 and 2001.
+Year ended December 31,
+(In thousands) 2002 2001
+--------- -------
+Accrual balance, beginning of year $ 3,002 $ 105
+--------- -------
+Business consolidation and restructuring expenses:
+Employee severance and termination expenses (1) 75 2,070
+Facility closure and consolidation expenses (2) 883 1,251
+--------- -------
+958 3,321
+--------- -------
+Cash payments (2,242) (424)
+--------- -------
+Accrual balance, end of year $ 1,718 $ 3,002
+========= =======
+(1) Employee severance and termination related expenses are the estimated
+termination salaries, benefits, outplacement, counseling services and other
+related costs expected to be paid to employees who are involuntarily
+terminated.
+(2) Facility closure and consolidation expenses are the estimated costs to close
+the Wallingford, CT facility including lease termination costs and other
+related costs, in accordance with the restructuring plan. The Wallingford
+facility closure was substantially completed by December 31, 2001.
+26
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+8. ACCRUED BUSINESS CONSOLIDATION AND RESTRUCTURING EXPENSES (CONTINUED)
+At December 31, 2002, $818,000 of the restructuring accrual was
+classified as a long-term liability. This represents the portion of
+non-cancelable lease termination costs and other costs expected to be paid
+beyond one year.
+The following table summarizes the components of all charges related to
+the Consolidation.
+Year ended December 31,
+(In thousands) 2002 2001
+------- -------
+Business consolidation and restructuring expenses $ 958 $ 3,321
+Accelerated depreciation and asset disposal losses (1) - 775
+------- -------
+Total business consolidation, restructuring and
+related charges $ 958 $ 4,096
+======= =======
+(1) Represents accelerated depreciation ($680) and asset disposal losses ($95)
+on certain leasehold improvements and other fixed assets incurred during
+2001, due to the closing of the Wallingford facility. These charges are
+included in general and administrative expenses.
+9. EMPLOYEE BENEFIT PLANS
+RETIREMENT SAVINGS PLAN: On April 1, 1997, the Company established the
+TransAct Technologies Retirement Savings Plan (the "401(k) Plan"), a
+defined contribution plan under Section 401(k) of the Internal Revenue
+Code. All full-time employees are eligible to participate in the 401(k)
+Plan at the beginning of the calendar quarter immediately following their
+date of hire. The Company matches employees' contributions at a rate of 50%
+of employees' contributions up to the first 6% of the employees'
+compensation contributed to the 401(k) Plan. The Company's matching
+contributions were $158,000, $204,000 and $203,000 in 2002, 2001 and 2000,
+respectively.
+EMPLOYEE STOCK PURCHASE PLAN: In May 2000, the Company's shareholders
+approved the Employee Stock Purchase Plan (the "ESPP"), under which 50,000
+shares of the Company's common stock are available for issuance to
+employees beginning June 1, 2000. All full-time employees are eligible to
+participate in the ESPP at the beginning of each six-month period (the
+"Offering Period"), which begins on June 1 and December 1. Eligible
+employees may elect to withhold up to 5% of their salary to purchase shares
+of the Company's common stock at a price equal to 85% of the fair market
+value of the stock on the first or last day of each Offering Period,
+whichever is lower. The ESPP will terminate at the earlier of May 31, 2005
+or the date on which all 50,000 shares available for issuance under the
+ESPP have been sold. The Company sold 4,849, 6,443 and 4,827 shares of
+common stock under the ESPP during 2002, 2001 and 2000, respectively. At
+December 31, 2002, 33,881 shares remained available for sale. Compensation
+costs related to the ESPP are immaterial.
+27
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+10. BORROWINGS
+On May 25, 2001, the Company entered into a new, three-year, $13.5
+million credit facility (the "LaSalle Credit Facility") with LaSalle
+Business Credit, Inc. ("LaSalle") expiring on May 25, 2004. The LaSalle
+Credit Facility replaced the Company's prior credit facility with Webster
+Bank. The LaSalle Credit Facility provides a $12 million revolving credit
+line, a $0.5 million term loan and a $1 million equipment loan facility.
+Borrowings under the revolving credit line bear a floating rate of interest
+at LaSalle's prime rate. Borrowings under both the term loan and equipment
+loan bear a floating rate of interest at LaSalle's prime rate plus 0.50%.
+Under certain circumstances, the Company may select a fixed interest rate
+for a specified period of time of up to 180 days on borrowings based on the
+current LIBOR rate plus 2.50% and 3.0% under the revolving credit line
+facility, and the term and equipment loan facilities, respectively. The
+Company also pays a fee of 0.25% on unused borrowings under the revolving
+credit line and equipment loan facilities. Borrowings under the LaSalle
+Credit Facility are secured by a lien on all the personal property assets
+of the Company. The LaSalle Credit Facility also imposes certain financial
+covenants on the Company and restricts the payment of dividends on its
+common stock and the creation of other liens. Concurrent with the signing
+of the LaSalle Credit Facility, the Company borrowed $500,000 under the
+term loan. Principal installment payments for the term loan of $8,333, plus
+accrued interest, are due on the first day of each month beginning July 1,
+2001, with the unpaid principal balance due on May 25, 2004. The Company
+had no borrowings under the equipment loan during 2002 or 2001.
+On October 30, 2001, the Company amended the LaSalle Credit Facility.
+Under the terms of the amendment ("LaSalle Amendment No. 1"), LaSalle (1)
+waived compliance with the minimum EBITDA financial covenant as of
+September 30, 2001, (2) revised certain other financial covenants through
+December 31, 2001, (3) increased the floating rate of interest on
+borrowings under the revolving credit line to LaSalle's prime rate plus
+1.0% (5.25% at December 31, 2002), or the current LIBOR rate plus 3.5%, and
+(4) increased the floating rate of interest on borrowings under the term
+loan and equipment loan to LaSalle's prime rate plus 1.5% (5.75% at
+December 31, 2002), or the current LIBOR rate plus 4.0%. Upon execution of
+LaSalle Amendment No. 1, the Company paid a fee of $20,000 to LaSalle.
+On December 21, 2001, the Company amended the LaSalle Credit Facility
+to reset certain financial covenants for 2002 and beyond ("LaSalle
+Amendment No. 2"). Upon execution of LaSalle Amendment No. 2, the Company
+paid a fee of $5,000 to LaSalle.
+On November 12, 2002, the Company amended the LaSalle Credit Facility.
+Under the terms of the amendment ("LaSalle Amendment No. 3"), LaSalle (1)
+waived compliance with the minimum EBITDA covenant, minimum tangible net
+worth and fixed charge coverage ratio financial covenants as of September
+30, 2002 and (2) revised these covenants to exclude the effect of $900,000,
+of the total $912,000, of restructuring charges incurred in the third
+quarter. Absent the $900,000 restructuring charge, the Company would have
+been in compliance with the above covenants at September 30, 2002. Upon
+execution of LaSalle Amendment No. 3, the Company paid a fee of $20,000 to
+LaSalle.
+On March 24, 2003, the Company amended the LaSalle Credit Facility.
+Under the terms of the amendment ("LaSalle Amendment No. 4"), LaSalle (1)
+waived compliance with the minimum EBITDA covenant as of December 31, 2002,
+(2) revised this covenant and certain other financial covenants through May
+2004 and (3) eliminated the availability of the $1 million equipment loan
+facility due to expire in May 2003. In addition, LaSalle has restricted $1
+million of our borrowing availability under the revolving credit line
+pending the outcome of the Company's patent analysis and discusssions
+regarding the possible use of technology covered by recently issued
+patents of a third party competitor (See Note 11). Upon execution of
+LaSalle Amendment No. 4, the Company paid a fee of $25,000 to LaSalle.
+As of December 31, 2002, the Company had $2,541,000 and $350,000
+outstanding on the revolving credit line and term loan, respectively, and
+no borrowings outstanding on the equipment loan, leaving undrawn
+commitments under the LaSalle Credit Facility of $9,459,000.
+28
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+11. COMMITMENTS AND CONTINGENCIES
+In November 2002, the Company was advised that certain POS printers
+sold by the Company since late 1999 may use technology covered by recently
+issued patents of a third party competitor. The Company is analyzing the
+cited patents for validity and applicability to the Company's products. In
+an effort to resolve this matter, the Company has offered to pay
+approximately $160,000, while the other party seeks payment of up to
+$950,000. While the outcome of the Company's patent analysis and
+discussions cannot be predicted, the Company has recognized a charge of
+$160,000 in cost of sales in the fourth quarter of 2002. This charge
+represents what the Company believes to be a fair and reasonable payment.
+At December 31, 2002, the Company was lessee on operating leases for
+equipment and real property. The terms of certain leases provide for
+escalating rent payments in later years of the lease as well as payment of
+minimum rent and real estate taxes. Rent expense was approximately
+$975,000, $983,000 and $991,000 in 2002, 2001 and 2000, respectively.
+Minimum aggregate rental payments required under operating leases that have
+initial or remaining non-cancelable lease terms in excess of one year as of
+December 31, 2002 are as follows: $945,000 in 2003; $945,000 in 2004;
+$954,000 in 2005; $945,000 in 2006; $965,000 in 2007 and $2,626,000
+thereafter.
+12. STOCK INCENTIVE PLANS AND WARRANTS
+STOCK INCENTIVE PLANS. The Company currently has three primary stock
+incentive plans: the 1996 Stock Plan which provides for the grant of awards
+to officers and other key employees of the Company, the 1996 Directors'
+Stock Plan which provides for non-discretionary awards to non-employee
+directors, and the 2001 Employee Stock Plan which provides for the grant of
+awards to key employees of the Company and other non-employees who may
+provide services to the Company. The plans generally provide for awards in
+the form of: (i) incentive stock options, (ii) non-qualified stock options,
+(iii) shares of restricted stock, (iv) restricted units, (v) stock
+appreciation rights or (vi) limited stock appreciation rights. However, the
+2001 Employee Stock Plan does not provide for incentive stock option
+awards. Options granted under these plans are at prices equal to 100% of
+the fair market value of the common stock at the date of grant. Options
+granted have a ten-year term and generally vest over a three- to five-year
+period, unless automatically accelerated for certain defined events. At
+December 31, 2002, the Company has reserved 1,150,000, 140,000 and 150,000
+shares of common stock for issuance under the 1996 Stock Plan, the 1996
+Directors' Stock Plan, and the 2001 Employees Stock Plan, respectively.
+OPTION EXCHANGE OFFER. In November 2001, the Company announced an offer
+to certain officers to exchange outstanding employee stock options having
+an exercise price of $9.00 or more per share in return for new stock
+options to be granted by the Company (the "Exchange Offer"). Pursuant to
+the Exchange Offer, the option holder received a commitment for the grant
+of one new option for each option tendered and accepted for exchange, no
+sooner than six months and one day from November 16, 2001. A total of
+215,000 options were accepted for exchange under the Exchange Offer and
+were canceled in November 2001 (and treated as canceled in 2001 in the
+table below). The new options were granted on May 17, 2002, and vested 25%
+immediately upon grant with the remainder vesting 25% annually over the
+next three years. The new options have an exercise price equal to the fair
+market value of the Company's common stock on the date of grant.
+29
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+12. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+The 1996 Stock Plan, 1996 Directors' Stock Plan and 2001 Employee Stock
+Plan option activity is summarized below:
+Year Ended December 31,
+2002 2001 2000
+------------------------- ------------------------ ---------------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+------- -------- -------- --------- ------- --------
+Outstanding at beginning of
+period: 742,750 $ 6.95 919,000 $ 8.34 818,100 $ 7.89
+Granted 366,750 5.47 189,500 5.67 190,500 9.86
+Exercised (26,100) 4.24 (53,500) 4.37 (25,000) 6.05
+Canceled (138,000) 7.97 (312,250) 10.71 (64,600) 7.53
+-------- ------ -------- ------- ------- ------
+Outstanding at end of period 945,400 $ 6.30 742,750 $ 6.95 919,000 $ 8.34
+======== ====== ======== ======= ======= ======
+Options exercisable at end of
+period 429,845 $ 6.81 383,350 $ 7.34 436,580 $ 8.19
+======== ====== ======== ======= ======= ======
+Options Outstanding Options Exercisable
+---------------------------------------------- --------------------------
+Weighted- Weighted- Weighted-
+Outstanding at Average Average Exercisable at Average
+December 31, Exercise Remaining December 31, Exercise
+Range of Exercise Prices 2002 Price Contractual Life 2002 Price
+-------------- ---------- ---------------- -------------- ---------
+(In years)
+$ 2.50 - $ 5.00 225,850 $ 4.49 6.9 118,995 $ 4.37
+5.01 - 7.50 456,000 5.61 8.8 116,450 5.74
+7.51 - 10.00 210,800 8.65 4.9 165,800 8.57
+10.01 - 12.50 47,750 10.38 6.8 23,600 10.64
+12.51 - 15.00 5,000 13.75 4.1 5,000 13.75
+The Company applies APB 25 and related interpretations in accounting
+for its long-term incentive stock plans. Accordingly, no compensation cost
+has been recognized for its stock options.
+The fair value of each option grant is estimated on the date of grant
+using the Black-Scholes option pricing model with the following assumptions
+used for the grants made during the years ended December 31, 2002, 2001 and
+2000.
+Year Ended December 31,
+2002 2001 2000
+----------- ----------- -----------
+Risk-free interest rate 4.5% 4.6% 6.3%
+Dividend yield 0% 0% 0%
+Expected volatility factor 83.3% 85.5% 83.1%
+Expected option term 6.4 years 6.1 years 7.1 years
+Weighted average fair value of options granted during period $ 4.12 $ 4.25 $ 7.78
+30
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+12. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+RESTRICTED STOCK: Under the 1996 Stock Plan, the Company has granted
+shares of restricted common stock, for no consideration, to its officers,
+one outside director and certain key employees. The 1996 Stock Plan
+restricted stock activity is summarized below:
+Year Ended December 31,
+2002 2001 2000
+------- ------- -------
+Outstanding shares at beginning of period 89,360 83,320 95,080
+Granted - 20,000 5,000
+Vested (42,094) (10,960) (12,960)
+Canceled (600) (3,000) (3,800)
+------- ------- -------
+Outstanding shares at end of period 46,666 89,360 83,320
+======= ======= =======
+The weighted average fair value of restricted stock granted was $4.75
+and $8.75 for 2001 and 2000, respectively. No restricted stock was granted
+during 2002. Of the 46,666 shares of restricted stock outstanding at
+December 31, 2002, 25,000 shares vest at the end of a five-year period,
+5,000 shares vest over a five-year period, 6,666 shares vest over a
+three-year period and 10,000 shares vest over a two-year period. Under
+certain conditions, vesting may be automatically accelerated. Upon issuance
+of the restricted stock, unearned compensation equivalent to the market
+value at the date of grant is charged to a separate component of
+shareholders' equity and subsequently amortized over the vesting period.
+Amortization expense of $184,000, $264,000 and $277,000 was recorded during
+2002, 2001 and 2000, respectively.
+WARRANTS: On April 7, 2000, in connection with the sale of the
+Preferred Stock, the Company issued to its investment advisors, McFarland
+Dewey & Co., warrants to purchase from the Company up to 10,000 shares of
+common stock at an exercise price of $9.00 per share. The warrants are
+exercisable through April 7, 2005.
+13. STOCKHOLDER RIGHTS PLAN
+In December 1997, the Board of Directors adopted a Stockholder Rights
+Plan declaring a distribution of one right (the "Rights") for each
+outstanding share of the Company's common stock to shareholders of record
+at December 15, 1997. Initially, each of the Rights will entitle the
+registered holder to purchase from the Company one one-thousandth of a
+share of Series A Preferred Stock, $0.01 par value, at a price of $69 per
+one one-thousandth of a share. The Rights, however, will not become
+exercisable unless and until, among other things, any person or group of
+affiliated persons acquires beneficial ownership of 15 percent or more of
+the then outstanding shares of the Company's Common Stock. If a person, or
+group of persons, acquires 15 percent or more of the outstanding Common
+Stock of the Company (subject to certain conditions and exceptions more
+fully described in the Rights Agreement), each Right will entitle the
+holder (other than the person, or group of persons, who acquired 15 percent
+or more of the outstanding Common Stock) to purchase Preferred Stock of the
+Company having a market value equal to twice the exercise price of the
+Right. The Rights are redeemable, under certain circumstances, for $0.0001
+per Right and will expire, unless earlier redeemed, on December 2, 2007.
+On February 16, 1999, the Company amended its Stockholder Rights Plan
+to remove the provision in the plan that stipulated that the plan may be
+modified or redeemed only by those members of the Board of Directors who
+are defined as continuing directors.
+31
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+14. INCOME TAXES
+The components of the income tax benefit are as follows:
+Year Ended December 31,
+(In thousands) 2002 2001 2000
+--------- --------- --------
+Current:
+Federal $ (1,493) $ (62) $ (561)
+State 25 - 43
+Foreign 110 56 194
+--------- --------- --------
+(1,358) (6) (324)
+--------- --------- --------
+Deferred:
+Federal 987 (2,523) (94)
+State (19) (219) (34)
+Foreign - - 4
+--------- --------- --------
+968 (2,742) (124)
+--------- --------- --------
+Total income tax benefit $ (390) $ (2,748) $ (448)
+========= ========= ========
+At December 31, 2002, the Company has $3,593,000 of state net operating
+loss carryforwards that begin to expire in 2005. The Company also has
+approximately $373,000 in federal research and development tax credit
+carryforwards that expire in 2020. The Company had foreign income before
+taxes of $386,000, $232,000 and $665,000 in 2002, 2001 and 2000,
+respectively.
+Deferred income taxes arise from temporary differences between the tax
+basis of assets and liabilities and their reported amounts in the financial
+statements. The Company's gross deferred tax assets and liabilities were
+comprised of the following:
+December 31,
+(In thousands) 2002 2001
+--------- --------
+Gross deferred tax assets:
+Net operating losses $ 188 $ 700
+Accrued restructuring expenses 635 1,109
+Inventory reserves 749 371
+Warranty reserves 238 262
+Deferred revenue 533 226
+Foreign tax credits 252 -
+Other liabilities and reserves 849 834
+-------- --------
+3,444 3,502
+Valuation allowance (439) -
+-------- --------
+Net deferred tax assets $ 3,005 $ 3,502
+======== ========
+Gross deferred tax liabilities:
+Depreciation $ 558 $ -
+Other 33 -
+-------- --------
+Net deferred tax liabilities $ 591 $ -
+======== ========
+32
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+14. INCOME TAXES (CONTINUED)
+Based on current year tax law changes, the Company carried back its
+federal net operating losses to prior years and received a tax refund of
+approximately $1,061,000 in 2002. The Company expects to carry back its
+2002 federal net operating losses to prior years, and expects to receive a
+refund of approximately $228,000 in 2003. During 2002, the Company
+established a valuation allowance of $439,000 on a portion of its foreign
+tax credits, research and development credits and certain state net
+operating loss carryforwards. Based on future financial projections and the
+ability to carry back current year net operating losses, the Company has
+determined that it is more likely than not that the existing net deferred
+tax asset will be realized, and no additional valuation allowance is
+considered necessary.
+Differences between the U.S. statutory federal income tax rate and the
+Company's effective income tax rate are analyzed below:
+Year Ended December 31,
+2002 2001 2000
+----------- ----------- -----------
+Federal statutory tax rate (34.0)% (34.0)% (34.0)%
+State income taxes, net of federal income taxes (0.3) (0.9) (0.3)
+Non-deductible purchase accounting adjustments - 1.6 9.9
+Tax benefit from foreign sales corporation - - (3.1)
+Tax benefit from tax credits, net of valuation allowance (10.6) (1.7) (22.9)
+Foreign rate differential 9.5 - (3.5)
+Other (0.6) (0.8) (2.7)
+----- ----- -----
+Effective tax rate (36.0)% (35.8)% (56.6)%
+===== ===== =====
+15. DISCLOSURE REGARDING FAIR VALUE OF FINANCIAL INSTRUMENTS
+The carrying amount for cash and cash equivalents approximates fair
+value because of the short maturity of these instruments. The carrying
+amount of receivables, other current assets, other assets, accounts payable
+and accrued liabilities is a reasonable estimate of fair value because of
+the short nature of the transactions. The carrying value of long-term debt
+approximates the fair value based upon the variable rate on that debt.
+33
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+16. SIGNIFICANT TRANSACTIONS
+OTHER INCOME: In June 2002, the Company received 2,146 shares of common
+stock from its health insurance company, Anthem, Inc., upon its
+demutualization. The Company sold these shares in August 2002 for
+approximately $145,000, and included this amount in Other Income.
+PREFERRED STOCK SALE: On April 7, 2000 the Company sold 4,000 shares of
+7% Series B Cumulative Convertible Redeemable Preferred Stock (the
+"Preferred Stock") to Advance Capital Advisors, L.P. and its affiliate in
+consideration of $1,000 per share (the "Stated Value"), for a total of
+$4,000,000, less issuance costs. The Preferred Stock is convertible at any
+time by the holders at a conversion price of $9.00 per common share. In
+addition, the Company issued warrants pro-rata to the Preferred Stock
+holders to purchase an aggregate of 44,444 shares of the Company's common
+stock at an exercise price of $9.00 per common share. The warrants, valued
+at $175,000, are exercisable at any time until April 7, 2005, and will be
+accreted to preferred stock ratably over 60 months. The Preferred Stock is
+subject to mandatory conversion into shares of the Company's common stock
+when such stock has traded at $35 per share or more for a 30-day period
+ending on or after April 7, 2003, or for a 60-day period beginning on or
+after April 7, 2002. The Preferred Stock is redeemable at the option of the
+holders on or after April 7, 2005 at $1,000 per share plus any unpaid
+dividends. On April 7, 2007, the Company has the right to require (1)
+redemption of the Preferred Stock at $1,000 per share plus any unpaid
+dividends or (2) conversion of the Preferred Stock at $9.00 per common
+share. Upon a change of control (which the Company does not believe
+probable), holders have the right to require the Company to redeem the
+Preferred Stock for 200% of the Stated Value plus any unpaid dividends. The
+holders of the Preferred Stock have certain voting rights and are entitled
+to receive a cumulative annual dividend of $70 per share, payable quarterly
+and have preference to any other dividends, if any, paid by the Company.
+Concurrent with the issuance of the Preferred Stock, the Company
+recorded a beneficial conversion charge. The beneficial conversion charge
+was calculated as the difference between the assigned fair value of the
+Preferred Stock and the fair value of the related common stock, as of April
+7, 2000, into which the Preferred Stock was immediately convertible.
+Accordingly, a deemed preferred dividend of approximately $56,000 as of the
+issuance date has been recognized as a charge to retained earnings and net
+loss attributable to common shareholders, and as an increase to additional
+paid-in capital.
+LOAN TO OFFICER: On February 23, 1999, with the Board of Directors'
+approval, the Company provided a $330,000 loan to an officer of the
+Company. The loan proceeds were used to purchase 104,000 shares of the
+Company's common stock on the open market during January and February 1999.
+The loan is payable on February 23, 2004, and is a full recourse obligation
+to the officer collateralized by 154,000 shares of the Company's common
+stock, which includes 50,000 shares of restricted stock. The loan currently
+bears interest at a rate equivalent to the Company's average borrowing rate
+under its current credit facility. Interest payments through December 31,
+2001 were added to the principal amount of the loan. During 2002, interest
+was compounded and added to principal monthly and is payable at maturity.
+Thereafter, interest will accrue monthly and be payable at maturity. The
+principal amount of the loan is deducted from shareholders' equity. The
+total amount of the loan including accrued interest is approximately
+$434,000 at December 31, 2002.
+17. INTERNATIONAL OPERATIONS
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary, which had sales to its customers of
+$738,000, $1,791,000 and $11,164,000 in 2002, 2001 and 2000, respectively.
+The Company had export sales to its foreign customers from the United
+States of approximately $3,968,000, $6,131,000 and $5,156,000 in 2002, 2001
+and 2000, respectively.
+34
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+18. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
+The Company's quarterly results of operations for the years ended
+December 31, 2002, 2001 and 2000 (unaudited) are as follows:
+Quarter Ended
+-----------------------------------------------------------
+(In thousands, except per share amounts) March 31 June 30 September 30 December 31
+--------- --------- ------------ -----------
+2002:
+Net sales $ 10,525 $ 10,921 $ 8,852 $ 9,163
+Gross profit 2,626 3,112 2,302 2,176
+Net income (loss) (129) 289 (709) (143)
+Net income (loss) available to common Shareholders (219) 200 (799) (232)
+Net income (loss) per share:
+Basic and diluted (0.04) 0.04 (0.14) (0.04)
+March 31 June 30 September 30 December 31
+--------- --------- ------------ -----------
+2001:
+Net sales $ 9,773 $ 10,796 $ 13,234 $ 10,171
+Gross profit 1,803 2,413 3,570 1,988
+Net loss (1,757) (1,220) (162) (1,783)
+Net loss available to common shareholders (1,847) (1,309) (252) (1,872)
+Net loss per share:
+Basic and diluted (0.33) (0.24) (0.05) (0.34)
+March 25 June 24 September 23 December 31
+--------- --------- ------------ -----------
+2000:
+Net sales $ 11,238 $ 13,740 $ 14,604 $ 14,138
+Gross profit 3,013 3,665 3,867 3,597
+Net income (loss) (300) (186) 290 (148)
+Net income (loss) available to common Shareholders (300) (326) 200 (238)
+Net income (loss) per share:
+Basic and diluted (0.05) (0.06) 0.04 (0.04)
+35
+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.
+Information contained in "Election of Directors" and "Section 16(a)
+Beneficial Ownership Reporting Compliance" of the Company's Proxy Statement (the
+"Proxy Statement") for its Annual Meeting of Shareholders which is scheduled to
+be held on May 20, 2003 is hereby incorporated herein by reference. Also, see
+information under "Executive Officers of Registrant" in Item 1.
+ITEM 11. EXECUTIVE COMPENSATION.
+The information contained in "Executive Compensation" other than the
+"Compensation Committee Report on Executive Compensation" of the Proxy Statement
+is hereby incorporated herein by reference.
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
+RELATED STOCKHOLDER MATTERS.
+The information contained in "Security Ownership of Certain
+Beneficial Owners and Management" of the Proxy Statement is hereby incorporated
+herein by reference.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
+ITEM 14. CONTROLS AND PROCEDURES
+Within 90 days of the filing of this report, an evaluation of the
+effectiveness of the design and operation of the Company's disclosure controls
+and procedures was conducted under the supervision and with the participation of
+the Chief Executive Officer and Chief Financial Officer. Based on this
+evaluation, the Chief Executive Officer and Chief Financial Officer have
+concluded that the Company's disclosure controls and procedures were adequate
+and designed to ensure that information required to be disclosed by the Company
+in this report is recorded, processed, summarized and reported in a timely
+manner, including that such information is accumulated and communicated to
+management, including the Chief Executive Officer and Chief Financial Officer,
+as appropriate to allow timely decisions regarding required disclosure.
+There were no significant changes in internal controls or in other
+factors that could significantly affect internal controls, including any
+corrective actions with regard to significant deficiencies and material
+weaknesses in internal controls, subsequent to the evaluation described above.
+Reference is made to the Certifications of the Chief Executive
+Officer and Chief Financial Officer about these and other matters following the
+signature page of this report.
+36
+PART IV
+ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
+(A) THE FOLLOWING FINANCIAL STATEMENTS AND EXHIBITS ARE FILED AS
+PART OF THIS REPORT:
+Financial statements
+(i) See Item 8.
+(ii) Financial statement schedules
+All schedules are omitted since the required information is
+either (a) not present or not present in amounts sufficient to
+require submission of the schedule or (b) included in the
+financial statements or notes thereto.
+37
+(iii) List of exhibits
+3.1(a) Certificate of Incorporation of the Company, filed with the (2)
+Secretary of State of Delaware on June 17, 1996.
+3.1(b) Certificate of Amendment of Certificate of Incorporation of (4)
+the Company, filed with the Secretary of State of Delaware on
+June 4, 1997.
+3.1(c) Certificate of Designation, Series A Preferred Stock, filed (5)
+with the Secretary of State of Delaware on December 2, 1997.
+3.1(d) Certificate of Designation, Series B Preferred Stock, filed (8)
+with the Secretary of State of Delaware on April 6, 2000.
+3.2 Amended and Restated By-laws of the Company. (6)
+4.1 Specimen Common Stock Certificate. (2)
+4.2 Amended and Restated Rights Agreement between TransAct and (5)
+American Stock Transfer & Trust Company dated February
+16, 1998.
+10.1 Tax Sharing Agreement dated as of July 31, 1996 between Tridex (3)
+and TransAct.
+10.2(x) 1996 Stock Plan, effective July 30, 1996. (3)
+10.3(x) Non-Employee Directors' Stock Plan, effective August 22, 1996. (3)
+10.4(x) 2000 Employee Stock Purchase Plan (9)
+10.5(x) 2001 Employee Stock Plan (11)
+10.6 Lease Agreement by and between Bomax Properties and Ithaca, (2)
+dated as of March 23, 1992.
+10.7 Second Amendment to Lease Agreement by and between Bomax (4)
+Properties and Ithaca, dated December 2, 1996.
+10.8 Agreement regarding the Continuation and Renewal of Lease by (14)
+and between Bomax Properties, LLC and TransAct, dated
+July 18, 2001.
+10.9 Lease Agreement by and between Pyramid Construction Company (4)
+and Magnetec, dated July 30, 1997.
+10.10(x) Employment Agreement, dated July 31, 1996, by and between the (2)
+Company and Bart C.Shuldman.
+10.11(x) Employment Agreement, dated July 31, 1996, by and between the (2)
+Company and Richard L. Cote.
+10.12(x) Severance Agreement by and between TransAct and Lucy H.Staley, (3)
+dated September 4, 1996.
+10.13(x) Release and Settlement Agreement by and between TransAct and (14)
+Lucy H. Staley, dated December 4, 2001
+10.14(x) Severance Agreement by and between TransAct and Michael (3)
+S. Kumpf, dated September 4, 1996.
+10.15(x) Severance Agreement by and between TransAct and Steven (6)
+A. DeMartino, dated January 21, 1998.
+10.16(x) Severance Agreement by and between TransAct and Mark Goebel, (10)
+dated July 31, 1996.
+10.17(x) Release and Settlement Agreement by and between TransAct and (14)
+Mark Goebel, dated March 1, 2002
+10.18(x) Severance Agreement by and between TransAct and James B. (10)
+Stetson, dated January 24, 2001.
+10.19 Loan Agreement by and between the Company and Bart C. (14)
+Shuldman, dated July 1, 2001
+10.20 Loan Agreement by and between the Company and Bart C. (15)
+Shuldman, dated January, 2002
+38
+10.21 OEM Purchase Agreement by and between GTECH Corporation, (7)
+TransAct Technologies and Magnetec Corporation commencing July
+14, 1999. (Pursuant to Rule 24-b-2 under the Exchange Act, the
+Company has requested confidential treatment of portions of
+this exhibit deleted from the filed copy.)
+10.22 OEM Purchase Agreement by and between GTECH Corporation and (16)
+TransAct Technologies Incorporated commencing July 2, 2002.
+(Pursuant to Rule 24-b-2 under the Exchange Act, the Company
+has requested confidential treatment of portions of this
+exhibit deleted from the filed copy.)
+10.23 OEM Purchase Agreement by and between Okidata Americas, Inc. (14)
+and TransAct, dated June 8, 2001. (Pursuant to Rule 24b-2
+under the Exchange Act, the Company has requested confidential
+treatment of portions of this exhibit deleted from the filed
+copy.)
+10.24 Preferred Stock Purchase Agreement and Certificate of (8)
+Designation dated as of March 20, 2000 between TransAct
+Technologies Incorporated and Advance Capital Partners, L.P.
+and affiliate
+10.25 Loan and Security Agreement dated as of May 25, 2001 among (12)
+TransAct, LaSalle Business Credit, Inc. ("LaSalle") and the
+institutions from time to time a party thereto.
+10.26 Waiver and Amendment No. 1 to Loan and Security Agreement (13)
+dated as of October 30, 2001 among TransAct, LaSalle and the
+institutions from time to time a party thereto.
+10.27 Amendment No. 2 to Loan and Security Agreement dated as of (14)
+December 21, 2001 among TransAct, LaSalle and the institutions
+from time to time a party thereto.
+10.28 Waiver and Amendment No. 3 to Loan and Security Agreement (17)
+dated as of November 12, 2002 among TransAct, LaSalle and the
+institutions from time to time a party thereto.
+10.29 Waiver and Amendment No. 4 to Loan and Security Agreement (1)
+dated as of March 24, 2003 among TransAct, LaSalle and the
+institutions from time to time a party thereto.
+11.1 Computation of earnings per share. (1)
+21.1 Subsidiaries of the Company. (1)
+23.1 Consent of PricewaterhouseCoopers LLP. (1)
+99.1 Certification pursuant to 18 U.S.C. Section 1350 as adopted (1)
+pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
+(1) These exhibits are filed herewith.
+(2) These exhibits, which were previously filed with the Company's
+Registration Statement on Form S-1 (No. 333-06895), are
+incorporated by reference.
+(3) These exhibits, which were previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended September
+30, 1996, are incorporated by reference.
+(4) These exhibits, which were previously filed with the Company's
+Annual Report on Form 10-K for the year ended December 31,
+1997, are incorporated by reference.
+(5) This exhibit, which was previously filed with the Company's
+Current Report on Form 8-K filed February 18, 1999, is
+incorporated by reference.
+(6) These exhibits, which were previously filed with the Company's
+Annual Report on Form 10-K for the year ended December 31,
+1998, are incorporated by reference.
+(7) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended September
+25, 1999, is incorporated by reference.
+(8) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended March 25,
+2000, is incorporated by reference.
+(9) This exhibit, which was previously filed with the Company's
+Registration Statement on Form S-8 (No. 333-49540), is
+incorporated by reference.
+(10) These exhibits, which were previously filed with the Company's
+Annual Report on Form 10-K for the year ended December 31,
+2000, are incorporated by reference.
+39
+(11) This exhibit, which was previously filed with the Company's
+Registration Statement on Form S-8 (No. 333-59570), is
+incorporated by reference.
+(12) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended June 30,
+2001, is incorporated by reference.
+(13) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended September
+30, 2001, is incorporated by reference.
+(14) These exhibits, which were previously filed with the Company's
+Annual Report on Form 10-K for the year ended December 31,
+2001, are incorporated by reference.
+(15) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended March 31,
+2002, is incorporated by reference.
+(16) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended June 30,
+2002, is incorporated by reference.
+(17) This exhibit, which was previously filed with the Company's
+Quarterly Report on Form 10-Q for the period ended September
+30, 2002, is incorporated by reference.
+(x) Management contract or compensatory plan or arrangement
+required to be filed pursuant to Item 14(c).
+(B) REPORTS ON FORM 8-K.
+None.
+40
+SIGNATURES
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of
+1934, the registrant has duly caused this report to be signed on its behalf by
+the undersigned, thereunto duly authorized.
+TRANSACT TECHNOLOGIES INCORPORATED
+By: /s/ Bart C. Shuldman
+-------------------------------------
+Bart C. Shuldman
+Chairman of the Board, President and
+Chief Executive Officer
+Date: March 31, 2003
+Pursuant to the requirements of the Securities 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/ Bart C. Shuldman Chairman of the Board, President and March 31, 2003
+------------------------- Chief Executive Officer
+Bart C. Shuldman (Principal Executive Officer)
+/s/ Richard L. Cote Executive Vice President, Chief Financial March 31, 2003
+------------------------- Officer, Treasurer, Secretary and Director
+Richard L. Cote (Principal Financial Officer)
+/s/ Steven A. DeMartino Senior Vice President, Finance March 31, 2003
+------------------------- and Information Technology
+Steven A. DeMartino (Principal Accounting Officer)
+/s/ Charles A. Dill Director March 31, 2003
+-------------------------
+Charles A. Dill
+/s/ Jeffrey T. Leeds Director March 31, 2003
+-------------------------
+Jeffrey T. Leeds
+/s/ Thomas R. Schwarz Director March 31, 2003
+-------------------------
+Thomas R. Schwarz
+/s/ Graham Y. Tanaka Director March 31, 2003
+-------------------------
+Graham Y. Tanaka
+41
+CERTIFICATION
+I, Bart C. Shuldman, certify that:
+1. I have reviewed this annual report on Form 10-K of TransAct Technologies
+Incorporated;
+2. Based on my knowledge, this annual report does not contain any untrue
+statement of a material fact or omit to state a material fact necessary to make
+the statements made, in light of the circumstances under which such statements
+were made, not misleading with respect to the period covered by this annual
+report;
+3. Based on my knowledge, the financial statements, and other financial
+information included in this annual report, fairly present in all material
+respects the financial condition, results of operations and cash flows of the
+registrant as of, and for, the periods presented in this annual report;
+4. The registrant's other certifying officers and I are responsible for
+establishing and maintaining disclosure controls and procedures (as defined in
+Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
+a) designed such disclosure controls and procedures to ensure that material
+information relating to the registrant, including its consolidated subsidiaries,
+is made known to us by others within those entities, particularly during the
+period in which this annual report is being prepared;
+b) evaluated the effectiveness of the registrant's disclosure controls and
+procedures as of a date within 90 days prior to the filing date of this annual
+report (the "Evaluation Date"); and
+c) presented in this annual report our conclusions about the effectiveness of
+the disclosure controls and procedures based on our evaluation as of the
+Evaluation Date;
+5. The registrant's other certifying officers and I have disclosed, based on our
+most recent evaluation, to the registrant's auditors and the audit committee of
+registrant's board of directors (or persons performing the equivalent
+functions):
+a) all significant deficiencies in the design or operation of internal controls
+which could adversely affect the registrant's ability to record, process,
+summarize and report financial data and have identified for the registrant's
+auditors any material weaknesses in internal controls; and
+b) any fraud, whether or not material, that involves management or other
+employees who have a significant role in the registrant's internal controls; and
+6) The registrant's other certifying officers and I have indicated in this
+annual report whether or not there were significant changes in internal controls
+or in other factors that could significantly affect internal controls subsequent
+to the date of our most recent evaluation, including any corrective actions with
+regard to significant deficiencies and material weaknesses.
+Date: March 31, 2003
+/s/ Bart C. Shuldman
+--------------------
+Bart C. Shuldman
+Chairman, President and Chief Executive Officer
+42
+CERTIFICATION
+I, Richard L. Cote, certify that:
+1. I have reviewed this annual report on Form 10-K of TransAct Technologies
+Incorporated;
+2. Based on my knowledge, this annual report does not contain any untrue
+statement of a material fact or omit to state a material fact necessary to make
+the statements made, in light of the circumstances under which such statements
+were made, not misleading with respect to the period covered by this annual
+report;
+3. Based on my knowledge, the financial statements, and other financial
+information included in this annual report, fairly present in all material
+respects the financial condition, results of operations and cash flows of the
+registrant as of, and for, the periods presented in this annual report;
+4. The registrant's other certifying officers and I are responsible for
+establishing and maintaining disclosure controls and procedures (as defined in
+Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
+a) designed such disclosure controls and procedures to ensure that material
+information relating to the registrant, including its consolidated subsidiaries,
+is made known to us by others within those entities, particularly during the
+period in which this annual report is being prepared;
+b) evaluated the effectiveness of the registrant's disclosure controls and
+procedures as of a date within 90 days prior to the filing date of this annual
+report (the "Evaluation Date"); and
+c) presented in this annual report our conclusions about the effectiveness of
+the disclosure controls and procedures based on our evaluation as of the
+Evaluation Date;
+5. The registrant's other certifying officers and I have disclosed, based on our
+most recent evaluation, to the registrant's auditors and the audit committee of
+registrant's board of directors (or persons performing the equivalent
+functions):
+a) all significant deficiencies in the design or operation of internal controls
+which could adversely affect the registrant's ability to record, process,
+summarize and report financial data and have identified for the registrant's
+auditors any material weaknesses in internal controls; and
+b) any fraud, whether or not material, that involves management or other
+employees who have a significant role in the registrant's internal controls; and
+6) The registrant's other certifying officers and I have indicated in this
+annual report whether or not there were significant changes in internal controls
+or in other factors that could significantly affect internal controls subsequent
+to the date of our most recent evaluation, including any corrective actions with
+regard to significant deficiencies and material weaknesses.
+Date: March 31, 2003
+/s/ Richard L. Cote
+-------------------
+Richard L. Cote
+Executive Vice President, Secretary,
+Treasurer and Chief Financial Officer
+43
+EXHIBIT LIST
+The following exhibits are filed herewith.
+Exhibit
+10.29 Waiver and Amendment No. 4 to Loan and Security Agreement dated as of
+March 24, 2003 among TransAct, LaSalle and the institutions from time
+to time a party thereto.
+11.1 Computation of earnings per share.
+21.1 Subsidiaries of the Company.
+23.1 Consent of PricewaterhouseCoopers LLP.
+99.1 Certification pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
+section 906 of the Sarbanes-Oxley Act of 2002
+44
\ No newline at end of file
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/filing_metadata.csv b/raw/filings/0001017303/2002/0000950123-03-003629/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..3f5dbd8a150f984ab3a1653932f3e1252202f30f
--- /dev/null
+++ b/raw/filings/0001017303/2002/0000950123-03-003629/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
+0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2003-03-31,2002-12-31,2003-03-31T19:13:45.000Z,0000950123-03-003629,y84806e10vk.txt,FORM 10-K,213390,0,0,https://www.sec.gov/Archives/edgar/data/1017303/000095012303003629/y84806e10vk.txt,https://www.sec.gov/Archives/edgar/data/1017303/000095012303003629/,2002,2002,1
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/item1.txt b/raw/filings/0001017303/2002/0000950123-03-003629/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5fe8f4565d07f663909b2c85d87d7913a39b73b0
--- /dev/null
+++ b/raw/filings/0001017303/2002/0000950123-03-003629/item1.txt
@@ -0,0 +1,261 @@
+ITEM 1. BUSINESS.
+(A) GENERAL DEVELOPMENT OF BUSINESS
+TransAct was incorporated in June 1996 and began operating as a
+stand-alone business in August 1996 to operate the printer business that was
+formerly conducted by certain subsidiaries of Tridex Corporation. TransAct
+completed an initial public offering on August 22, 1996.
+In February 2001, the Company announced plans to establish a global
+engineering and manufacturing center at its Ithaca, NY facility. As part of this
+strategic decision, the Company undertook a plan to consolidate all
+manufacturing and engineering into its existing Ithaca, NY facility and close
+its Wallingford, CT facility (the "Consolidation"). The Company's technology
+shift to inkjet and thermal printing from dot matrix impact printing has
+dramatically reduced the labor content in its printers, and therefore, lowers
+the required production capacity. As of December 31, 2001, substantially all
+Wallingford product lines were successfully transferred to Ithaca, NY. The
+Company maintains a small component production line and service depot in
+Wallingford. The closing of the Wallingford facility resulted in the termination
+of employment of approximately 70 production, administrative and management
+employees.
+As a result of the Consolidation, the Company improved its gross margin
+and significantly reduced its operating expenses in 2002 compared to 2001, and
+lowered its operating income breakeven point from $54 million to $42 million in
+revenues. Management believes this will provide additional operating leverage in
+2003.
+(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
+TransAct has assessed its operating and reportable segments and has
+determined that it operates in one reportable segment, the design, development,
+manufacture and marketing of transaction-based printers and printer-related
+products.
+(C) NARRATIVE DESCRIPTION OF BUSINESS
+(i) PRINCIPAL PRODUCTS AND SERVICES
+TransAct designs, develops, manufactures and markets a broad array of
+transaction-based printers utilizing inkjet, thermal and impact printing
+technology for applications requiring up to 60 character columns, primarily in
+the POS and gaming and lottery markets. The Company's printers are configurable
+and offer customers the ability to choose from a variety of features and
+functions. Options typically include PC board configuration, paper cutting
+devices, paper handling capacities and cabinetry color. In addition to its
+configurable printers, TransAct manufactures custom printers for certain OEM
+customers. In collaboration with these customers, the Company provides
+engineering and manufacturing expertise for the design and development of
+specialized printers. In addition, the Company offers inkjet cartridges, printer
+ribbons, paper and replacement parts for all of its products.
+The Company provides customers with telephone sales and technical
+support, a personal account representative for orders, shipping and general
+information and expedited shipping for orders of its configurable and custom
+products. Technical and sales support personnel receive training in all of the
+Company's products and services manufactured at their facility. The Company's
+printers generally carry a one- or two-year limited warranty; extended
+warranties are available for purchase on selected printers to supplement the
+original warranty. Service contracts for the repair and maintenance of printers
+beyond the original warranty period are also available for purchase.
+(ii) STATUS OF PRODUCT REQUIRING MATERIAL INVESTMENT
+None.
+2
+(iii) SOURCES AND AVAILABILITY OF RAW MATERIALS
+The principal materials used in manufacturing are inkjet, thermal and
+impact printheads, injection molded plastic parts, formed/stamped metal parts
+and electronic components. Although the Company could experience temporary
+disruption if certain suppliers ceased doing business with the Company, the
+Company's requirements generally are available from a number of sources, except
+as described below.
+Okidata Americas, Inc. ("Okidata"), is the sole supplier for a printer
+component kit consisting of a printhead, control board and carriage (the "Oki
+Kit"), which is used in all of the Company's Ithaca(R) brand impact printers.
+The loss of the supply of Oki Kits would have a material adverse effect on the
+Company. TransAct has a supply agreement with Okidata to provide Oki Kits until
+June 2003. Although prices under this agreement were fixed until March 2002, the
+Company continues to purchase supplies at these prices. The Company and Okidata
+are currently negotiating for future supplies and pricing.
+Additionally, Hewlett-Packard Company ("HP") is the sole supplier of
+inkjet cartridges that are used in all of the Company's inkjet printers. The
+loss of the supply of HP inkjet cartridges would have a material adverse effect
+on the sale of the Company's inkjet printers. TransAct has a supply agreement
+with HP to purchase inkjet cartridges until February 1, 2004 at fixed prices.
+TransAct believes its relations with Okidata and HP are good and has
+received no indication that either of the supply agreements will not be renewed
+beyond the respective expiration dates of the current contracts. TransAct cannot
+be certain, however, that either of the supply agreements will be renewed, or if
+renewed, that the terms will be as favorable as those under the current
+contracts.
+(iv) PATENTS AND PROPRIETARY INFORMATION
+The Company has significantly expanded its patent portfolio over the
+past two years, and expects to continue to do so in the future. The Company also
+believes its patent portfolio will provide additional opportunities to license
+its intellectual property in the future. The Company currently owns eight
+patents, four of which it considers material. The earliest expiration date of
+these eight patents is in 2008 with the latest expiration date in 2020. Of the
+material patents, one patent covers methods and apparatus for allowing a
+two-color printer to print images using single pass technology by printing
+during both forward and reverse movement of the print mechanism; another patent
+relates to TransAct's proprietary void and reprint receipt printing method which
+is used in certain of the Company's slot machine printers; and two other patents
+cover a method for converting a full color image into a two-color image, plus a
+background color. The Company also has sought patent protection for certain
+design features of 1) printers using inkjet technology, 2) POS printers using
+thermal technology, and 3) thermal printers for use in casino slot machines. The
+Company regards certain manufacturing processes and designs to be proprietary
+and attempts to protect them through employee and third-party nondisclosure
+agreements and similar means. It may be possible for unauthorized third parties
+to copy certain portions of the Company's products or to reverse engineer or
+otherwise obtain and use, to the Company's detriment, information that the
+Company regards as proprietary. Moreover, the laws of some foreign countries do
+not afford the same protection to the Company's proprietary rights as do United
+States laws. There can be no assurance that legal protections relied upon by the
+Company to protect its proprietary position will be adequate or that the
+Company's competitors will not independently develop technologies that are
+substantially equivalent or superior to the Company's technologies.
+(v), (vi)SEASONALITY AND PRACTICES RELATING TO WORKING CAPITAL ITEMS
+Retailers typically reduce purchases of new POS equipment in the fourth
+quarter, due to the increased volume of consumer transactions in that period,
+and the Company's sales of printers in the POS market historically have
+increased in the third quarter and decreased in the fourth quarter. However, the
+Company has not experienced material seasonality in its total net sales, due to
+offsetting sales in other markets.
+(vii) CERTAIN CUSTOMERS
+The Company has two OEM purchase agreements with GTECH Corporation
+("GTECH"). The first OEM purchase agreement ("GTECH Impact Printer Agreement")
+provides for the sale of impact on-line lottery printers and spare parts, at
+prices to be negotiated, through December 31, 2004. The second OEM purchase
+agreement ("GTECH Thermal Printer Agreement") provides for the sale of thermal
+on-line lottery printers and spares parts, at a fixed prices, through June 28,
+2007. Firm purchase orders for printers under either agreement may be placed
+annually by GTECH. Pursuant to orders placed under the GTECH Impact Printer
+Agreement during 2002, the Company has approximately $500,000 of impact printers
+remaining to be shipped during the first quarter of 2003. The Company does not
+expect any further shipments of impact on-line lottery printers in 2003 beyond
+the first quarter. Additionally, pursuant to the GTECH Thermal Printer
+Agreement, the Company has received an initial order for approximately
+$4,300,000 worth of thermal printers for delivery in 2003, beginning in the
+second quarter. The Company also sells printers to GTECH for use in lottery
+terminals at grocery store check-out lanes ("in-lane lottery printers"). Sales
+of in-lane lottery printes are project-oriented, and, as such, the Company
+cannot predict if
+3
+and when future sales may occur. Sales to GTECH accounted for approximately 27%,
+33% and 22% of net sales in 2002, 2001 and 2000, respectively.
+The Company also provides printers to ICL Pathway for use in the
+British Post Office. During 2000, sales to ICL Pathway accounted for
+approximately 20% of net sales. The Company completed shipping printers to ICL
+Pathway for use in the British Post Office in February 2001, and no further
+shipments are expected.
+(viii) BACKLOG
+The Company's backlog of firm orders was approximately $7,628,000 as of
+March 14, 2003 and $8,700,000 as of March 25, 2002, including approximately
+$4,300,000 and $6,600,000 to GTECH, respectively. Based on customers' current
+delivery requirements, TransAct expects to fill its entire current backlog
+during 2003.
+(ix) MATERIAL PORTION OF BUSINESS SUBJECT TO RENEGOTIATION OF
+PROFITS
+None.
+(x) COMPETITION
+The market for transaction-based printers is extremely competitive, and
+the Company expects such competition to intensify in the future. The Company
+competes with a number of companies, many of which have greater financial,
+technical and marketing resources than the Company. TransAct believes its
+ability to compete successfully depends on a number of factors both within and
+outside its control, including durability, reliability, quality, design
+capability, product customization, price, customer support, success in
+developing new products, manufacturing expertise and capacity, supply of
+component parts and materials, strategic relationships with suppliers, the
+timing of new product introductions by the Company and its competitors, general
+market, economic and political conditions and, in some cases, the uniqueness of
+its products.
+In the POS market, the Company's major competitors are, Epson America,
+Inc., Axiohm Transaction Solutions, Star Micronics America, Inc., Citizen -- CBM
+America Corporation, and Korean Printer Solutions (a spin-off company from
+Samsung). Together, these competitors comprise approximately 80% of the POS
+market segments into which the Company sells. Certain competitors of the Company
+have greater financial resources, lower costs attributable to higher volume
+production and off-shore manufacturing locations, and offer lower prices than
+the Company from time to time.
+In the lottery market (consisting principally of on-line lottery
+transaction printing), the Company holds a leading position, based largely on
+its long-term purchase agreements with GTECH, which controls approximately 70%
+of the worldwide on-line lottery market. The Company competes in this market
+based solely on its ability to provide specialized, custom-engineered products
+to GTECH.
+In the gaming market (consisting principally of video lottery terminals
+and slot machine transaction printing), the Company and its major competitor,
+Seiko Instruments Inc. (an affiliate of Seiko Epson Corporation), comprise a
+substantial portion of the market. The Company also competes, to a lesser
+extent, with JCM American Corporation and Money Controls, a division of Coin
+Acceptors, Inc. (Coinco). Certain of the Company's products sold for gaming
+applications compete based upon the Company's ability to provide highly
+specialized products, custom engineering and ongoing technical support.
+The Company's strategy for competing in its markets is to continue to
+develop new products and product line extensions, to increase its geographic
+market penetration, take advantage of strategic relationships, and to lower
+product costs by sourcing certain products overseas. The Company expects to
+particularly focus on (1) promoting its new line of slot machine printers into
+the gaming market, (2) increasing sales of its family of printers utilizing
+Hewlett Packard's inkjet printing technology, and (3) expanding its consumables,
+spare parts and service business. Although the Company believes that its
+products, operations and relationships provide a competitive foundation, there
+can be no assurance that the Company will compete successfully in the future.
+(xi) RESEARCH AND DEVELOPMENT ACTIVITIES
+The Company spent approximately $2,025,000, $3,070,000 and $3,481,000
+in 2002, 2001 and 2000, respectively, on engineering, design and product
+development efforts in connection with specialized engineering and design to
+introduce new products and to customize existing products. During 2003, the
+Company expects to focus the majority of its research and development activities
+on the development of a new thermal on-line lottery printer for GTECH, and on
+the continuing development and enhancement of (1) its family of printers for the
+POS market utilizing inkjet and thermal printing technology and (2) its
+ticket-issuing printers for use in the casino market.
+4
+(xii) ENVIRONMENT
+The Company is not aware of any material noncompliance with federal,
+state and local provisions that have been enacted or adopted regulating the
+discharge of materials into the environment, or otherwise relating to the
+protection of the environment.
+(xiii) EMPLOYEES
+As of March 14, 2003, TransAct Technologies and its subsidiaries
+employed 158 persons, of whom 136 were full-time and 22 were temporary
+employees. None of the Company's employees is unionized, and the Company
+considers its relationships with its employees to be good.
+(D) FINANCIAL INFORMATION ABOUT FOREIGN AND DOMESTIC OPERATIONS AND EXPORT
+SALES
+The Company has foreign operations primarily from TransAct Technologies
+Ltd., a wholly-owned subsidiary located in the United Kingdom, which had sales
+to its customers of $738,000, $1,791,000 and $11,164,000 (primarily to ICL
+Pathway for use in the British Post Office) in 2002, 2001 and 2000,
+respectively. The Company had export sales to its customers from its domestic
+operations of approximately $3,968,000, $6,131,000 and $5,156,000 in 2002, 2001
+and 2000, respectively.
+(E) EXECUTIVE OFFICERS OF THE REGISTRANT AS OF DECEMBER 31, 2002
+Name Age Position
+------------------------------------ ------------- -------------------------------------------------------------
+Bart C. Shuldman 45 Chairman of the Board, President and Chief Executive Officer
+Richard L. Cote 61 Executive Vice President, Chief Financial Officer, Treasurer,
+Secretary and Director
+James B. Stetson 45 Executive Vice President - Sales and Marketing
+Michael S. Kumpf 53 Executive Vice President - Engineering
+Steven A. DeMartino 33 Senior Vice President - Finance and Information Technology
+BART C. SHULDMAN has been Chief Executive Officer, President and a
+Director of the Company since its formation in June 1996. Previously, Mr.
+Shuldman served as President of Magnetec and later the combined operations of
+Magnetec and Ithaca from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+RICHARD L. COTE has been Executive Vice President, Chief Financial
+Officer, Treasurer, Secretary and a Director of the Company since its formation
+in June 1996. Prior thereto, he served as Senior Vice President and Chief
+Financial Officer of Tridex from September 1993 to June 1996.
+JAMES B. STETSON was appointed Executive Vice President, Sales and
+Marketing in November 2001, and served as Senior Vice President of Worldwide
+Sales from February 2000 to November 2001, and Vice President of Sales, Latin
+America from October 1997 to February 2000. Prior to joining TransAct, Mr.
+Stetson served as Vice President and Sales Manager at Gekay Sales and Service
+Company from 1995 until October 1997.
+MICHAEL S. KUMPF, was appointed Executive Vice President of Engineering
+in March 2002. He served as Senior Vice President-Engineering from June 1996 to
+March 2002 and Vice President of Engineering of Ithaca from 1991 until June
+1996.
+STEVEN A. DEMARTINO joined TransAct as Corporate Controller in August
+1996 and was appointed an officer of the Company in January 1998, Vice President
+in December 1999, and Senior Vice President, Finance and Information Technology
+in October 2001. Prior to joining TransAct, Mr. DeMartino was a self-employed
+financial consultant from May 1996 to August 1996. Prior thereto, Mr. DeMartino,
+served as Controller of NER/Copart, Inc. from September 1994 to May 1996.
+5
\ No newline at end of file
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/item13.txt b/raw/filings/0001017303/2002/0000950123-03-003629/item13.txt
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index 0000000000000000000000000000000000000000..6aaf28f561750415b42aaeebfc2caed4df64ff04
--- /dev/null
+++ b/raw/filings/0001017303/2002/0000950123-03-003629/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/item9a.txt b/raw/filings/0001017303/2002/0000950123-03-003629/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/rp_note.txt b/raw/filings/0001017303/2002/0000950123-03-003629/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2002/0000950123-03-003629/rpt_disclosure.txt b/raw/filings/0001017303/2002/0000950123-03-003629/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f02bbe376be9d80a9cba0f591a52c534d9f4f5ed
--- /dev/null
+++ b/raw/filings/0001017303/2002/0000950123-03-003629/rpt_disclosure.txt
@@ -0,0 +1,20 @@
+- Review all related party transactions and potential conflict of interest
+situations.
+- Receive, and act upon as appropriate, the disclosures made by the Chief
+Executive Officer and the Chief Financial Officer concerning internal
+controls and fraud required by Rule 13a-14 of the Securities Exchange Act
+of 1934.
+A-1
+b. Financial Reporting
+Annually
+- Review the Company's annual financial statements included in Form 10-K
+and the Annual Report to Stockholders with the Company's financial
+management and independent accountants.
+- Discuss any significant financial judgments made in connection with the
+preparation of the Company's financial statements.
+- Obtain assurances from financial management that the financial statements
+contain no material misstatements, and obtain assurances from the
+independent accountants that, in the course of their audit, they learned
+of no material misstatement.
+- Consider prior to their adoption any material change in accounting
+principles by the Company, and report and make recommendations to the
\ No newline at end of file
diff --git a/raw/filings/0001017303/2006/0000950123-07-003917/filing.txt b/raw/filings/0001017303/2006/0000950123-07-003917/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..cbe7dd916a19f5b8ddaec4f039cf1178c4578e17
--- /dev/null
+++ b/raw/filings/0001017303/2006/0000950123-07-003917/filing.txt
@@ -0,0 +1,3663 @@
+10-K
+1
+y31948e10vk.txt
+FORM 10-K
+UNITED STATES
+SECURITIES AND EXCHANGE COMMISSION
+Washington, DC. 20549
+FORM 10-K
+FOR ANNUAL AND TRANSITION REPORTS
+PURSUANT TO SECTIONS 13 OR 15(d) OF THE
+SECURITIES AND EXCHANGE ACT OF 1934
+(Mark One)
+[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
+ACT OF 1934
+For the fiscal year ended December 31, 2006 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: 0-21121
+TRANSACT TECHNOLOGIES INCORPORATED
+(Exact name of registrant as specified in its charter)
+DELAWARE 06-1456680
+(State or other jurisdiction of (I.R.S. Employer
+incorporation or organization) Identification No.)
+7 LASER LANE, WALLINGFORD, CT 06492
+(Address of principal executive offices) (Zip Code)
+Registrant's telephone number, including area code 203-859-6800
+Securities registered pursuant to Section 12(b) of the Act:
+TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
+------------------- ------------------------------------
+Common Stock, par value $.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 Securities 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 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 other amendment
+to this Form 10-K. [ ]
+Indicate by check mark whether the registrant is a large accelerated filer, an
+accelerated filer, or a non-accelerated filer. See definition of "accelerated
+filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (check
+one):
+Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]
+Indicate by check mark whether the registrant is a shell company (as defined in
+Rule 12b-2 of the Exchange Act).
+Yes [ ] No [X]
+As of June 30, 2006 the aggregate market value of the registrant's issued and
+outstanding voting stock held by non-affiliates of the registrant was
+$93,200,000.
+As of February 28, 2007, the registrant had outstanding 9,574,777 shares of
+common stock, $0.01 par value.
+DOCUMENTS INCORPORATED BY REFERENCE
+Proxy Statement for the Annual Meeting of Shareholders to be held on May 15,
+2007 - Part III (Items 10-14).
+1
+TRANSACT TECHNOLOGIES INCORPORATED
+INDEX
+Page No.
+--------
+PART I.
+Item 1. Business 3 - 7
+Item 1A. Risk Factors 7 - 10
+Item 1B. Unresolved Staff Comments 10
+Item 2. Properties 10 - 11
+Item 3. Legal Proceedings 11
+Item 4. Submission of Matters to a Vote of Security Holders 11
+PART II.
+Item 5. Market for Registrant's Common Equity, Related
+Stockholder Matters and Issuer Purchases of Equity
+Securities 12 - 13
+Item 6. Selected Consolidated Financial Data 14
+Item 7. Management's Discussion and Analysis of Financial
+Condition and Results of Operations 15 - 27
+Item 7A. Quantitative and Qualitative Disclosures About Market
+Risk 27
+Item 8. Financial Statements and Supplementary Data 28 - 51
+Item 9. Changes in and Disagreements with Accountants on
+Accounting and Financial Disclosure 52
+Item 9A. Controls and Procedures 52 - 53
+PART III.
+Item 10. Directors and Executive Officers of the Registrant 53
+Item 11. Executive Compensation 53
+Item 12. Security Ownership of Certain Beneficial Owners and
+Management and Related Stockholder Matters 53 - 54
+Item 13. Certain Relationships and Related Transactions 54
+Item 14. Principal Accountant Fees and Services 54
+PART IV.
+Item 15. Exhibits and Financial Statement Schedules 55 - 57
+Signatures 58
+PART I
+2
+ITEM 1. BUSINESS.
+THE COMPANY
+TransAct was incorporated in June 1996 and began operating as a stand-alone
+business in August 1996 as a spin-off of the printer business that was formerly
+conducted by certain subsidiaries of Tridex Corporation. We completed an initial
+public offering on August 22, 1996.
+TransAct Technologies Incorporated ("TransAct" or the "Company") designs,
+develops, assembles, markets and services world-class transaction printers under
+the Epic(TM) and Ithaca(R) brand names. Known and respected worldwide for
+innovative designs and real-world service reliability, our impact, thermal and
+inkjet printers generate top-quality transaction records such as receipts,
+tickets, coupons, register journals and other documents. We focus on two core
+markets: (1) point-of-sale ("POS") and banking and (2) gaming and lottery. We
+sell our products to original equipment manufacturers ("OEMs"), value-added
+resellers ("VARs"), selected distributors, as well as directly to end-users. Our
+product distribution spans across the Americas, Europe, the Middle East, Africa,
+Asia, Australia, the Caribbean Islands and the South Pacific. In addition, we
+have a strong focus on the after-market side of the business, with a growing
+commitment to printer service, supplies and spare parts. We have one primary
+operating facility located in Ithaca, NY, five sales offices located in the
+United States (including our global gaming and lottery headquarters and western
+region service center in Las Vegas, NV), and a European sales and service center
+in the United Kingdom. Our executive offices and eastern region service center
+are located at 7 Laser Lane, Wallingford, CT 06492, with a telephone number of
+(203) 859-6800.
+FINANCIAL INFORMATION ABOUT SEGMENTS
+We have determined that we operate in one reportable segment, the design,
+development, assembly and marketing of transaction printers and printer-related
+service, supplies and spare parts.
+PRODUCTS AND SERVICES
+Printers
+TransAct designs, develops, assembles and markets a broad array of
+transaction-based printers utilizing inkjet, thermal and impact printing
+technology for applications requiring up to 60 character columns, primarily in
+the POS and banking, and gaming and lottery markets. Our printers are
+configurable and offer customers the ability to choose from a variety of
+features and functions. Options typically include interface configuration, paper
+cutting devices, paper handling capacities and cabinetry color. In addition to
+our configurable printers, we design and assemble custom printers for certain
+OEM customers. In collaboration with these customers, we provide engineering and
+manufacturing expertise for the design and development of specialized printers.
+POS and banking: Our POS and banking printers include hundreds of optional
+configurations that can be selected to meet particular customer needs. We
+believe that this is a significant competitive strength, as it allows us to
+satisfy a wide variety of printing applications that our customers request. In
+the POS market, we sell several models of printers utilizing inkjet, thermal and
+impact printing technology. Our printers are used primarily by retailers in the
+hospitality, restaurant (including fine dining, casual dining, and fast food)
+and specialty retail industries to print receipts for consumers, validate
+checks, or print on other inserted media. We also sell printers that are used by
+banks, credit unions and other financial institutions to print and/or validate
+receipts at bank teller stations.
+Gaming and lottery: In the lottery portion of our gaming and lottery
+market, we supply lottery printers to GTECH, our largest customer and the
+world's largest provider of lottery terminals, with an approximate 70% market
+share. These printers are designed for high-volume, high-speed printing of
+lottery tickets for various lottery applications.
+In the gaming portion of our gaming and lottery market, we sell several
+models of printers used in slot machines and video lottery terminals that print
+tickets instead of issuing coins at casinos, racetracks and other gaming
+establishments worldwide. These printers utilize thermal printing technology and
+can print tickets in monochrome or two-color (depending upon the model), and
+offer various other features such as jam resistant bezels and a dual port
+interface that will allow casinos to print coupons/promotions. In addition, we
+sell printers using thermal and impact printing technology for use in non-casino
+gaming establishments, including game types such as Amusements with Prizes
+("AWP"), Skills with Prizes ("SWP"), Video lottery terminals ("VLT"), Fixed Odds
+Betting Terminals ("FOBT") and other off-premise gaming type machines around the
+world.
+TransAct Services Group
+Through our TransAct Services Group, we proactively market the sale of
+consumable products (including inkjet cartridges, ribbons and receipt paper),
+replacement parts and maintenance services for all of our products. Our
+maintenance services include the sale of extended warranties, multi-year
+maintenance contracts, 24-hour guaranteed replacement product service TransAct
+Xpress(SM), and other repair services for our printers. Within the United
+States, we provide repair services
+3
+through our eastern region service center in Wallingford, CT and our western
+region service center in Las Vegas, NV. Internationally, we provide repair
+services through our European service center located in Doncaster, United
+Kingdom, and through partners strategically located around the world.
+We also provide customers with telephone sales and technical support, and a
+personal account representative to handle orders, shipping and general
+information. Technical and sales support personnel receive training on all of
+our manufactured products and our services.
+Product Warranty
+Our printers generally carry up to a two-year limited warranty against
+defects in material and workmanship. Defective equipment may be returned to any
+of our service centers, or our manufacturing facility in Ithaca, NY for
+newly-released printers only, for repair or replacement during the applicable
+warranty period.
+PRODUCTION, MANUFACTURING AND SOURCES AND AVAILABILITY OF RAW MATERIALS
+We design our products to optimize product performance, quality,
+reliability and durability. These designs combine cost efficient materials,
+sourcing and assembly methods with high standards of workmanship. We finalize
+assembly of our products in our Ithaca, NY facility largely on a
+configure-to-order basis using components that have been sourced from around the
+world. Our manufacturing engineers work closely with our new product engineers
+and vendors during the development of new products. As a result, this
+collaboration increases manufacturing efficiency by specifying materials and
+designing manufacturing processes in conjunction with new product design.
+We procure component parts and subassemblies for use in the manufacture and
+assembly of our products. Critical component parts and subassemblies include
+inkjet, thermal and impact printheads, printing/cutting mechanisms, power
+supplies, motors, injection molded plastic parts, circuit boards and electronic
+components, which are obtained from domestic and foreign suppliers at
+competitive prices. In addition, we have begun to procure fully assembled
+printers from a foreign supplier. We typically strive to maintain more than one
+source for our component parts, subassemblies and fully assembled printers to
+reduce the risk of parts shortages or unavailability. However, we could
+experience temporary disruption if certain suppliers ceased doing business with
+us, as described below.
+Okidata Americas, Inc. ("Okidata"), is the sole supplier for an impact
+printer component kit consisting of a printhead, control board and carriage (the
+"Oki Kit"), that is used in all of our Ithaca(R) brand impact printers. The loss
+of the supply of Oki Kits would have a material adverse effect on TransAct.
+However, sales of impact printers continue to decline as sales of these printers
+are replaced by sales of thermal and inkjet printers. As such, we believe that
+any possible loss of supply of Oki Kits will have less of an impact on TransAct
+in 2007 and beyond. Although we do not have a supply agreement with Okidata, our
+relationship with Okidata remains strong and we have no reason to believe that
+Okidata will discontinue its supply of Oki Kits to us or that their terms to us
+will be any less favorable than they have been historically.
+Hewlett-Packard Company ("HP") is the sole supplier of inkjet cartridges
+that are used in all of our inkjet printers. The loss of the supply of HP inkjet
+cartridges would have a material adverse effect on the sale of our inkjet
+printers. Prior to February 2006, we had a supply agreement with HP to purchase
+inkjet cartridges at fixed prices. This agreement expired on February 1, 2006
+and was not renewed, as HP informed us that they no longer maintain supply
+agreements for these inkjet cartridges; however, we continue to purchase inkjet
+cartridges from HP. Although we no longer have a supply agreement with HP, our
+relationship with HP remains strong and we have no reason to believe that HP
+will discontinue its supply of inkjet cartridges to us. The inkjet cartridges we
+purchase from HP are used not only in our inkjet printers for the POS and
+banking market, but also in other manufacturer's printing devices across several
+other markets.
+We currently buy substantially all of our thermal print mechanisms, an
+important component of our thermal printers, from one supplier. Although we
+believe that other suppliers could provide similar thermal print mechanisms on
+comparable terms, a change in suppliers could cause a delay in manufacturing and
+possible loss of sales which may have a material adverse effect on our operating
+results.
+4
+PATENTS AND PROPRIETARY INFORMATION
+We have significantly expanded our patent portfolio over the past six
+years, and expect to continue to do so in the future. We also believe our patent
+portfolio could provide additional opportunities to license our intellectual
+property in the future. We hold 21 United States and nine foreign patents and
+have nine United States and 19 foreign patent applications pending pertaining to
+our products. The duration of these patents range from 11 to 18 years. The
+expiration of any individual patent would not have a significant negative impact
+on our business. We regard certain manufacturing processes and designs to be
+proprietary and attempt to protect them through employee and third-party
+nondisclosure agreements and similar means. It may be possible for unauthorized
+third parties to copy certain portions of our products or to reverse engineer or
+otherwise obtain and use, to our detriment, information that we regard as
+proprietary. Moreover, the laws of some foreign countries do not afford the same
+protection to our proprietary rights as do United States laws. There can be no
+assurance that legal protections relied upon by the Company to protect our
+proprietary position will be adequate or that our competitors will not
+independently develop technologies that are substantially equivalent or superior
+to our technologies.
+During 2004, we signed a cross licensing agreement with Seiko Epson. Under
+the agreement, Seiko Epson received a license to three of our patents, and we
+received a license to eighteen of Seiko Epson's patents relating to printing
+applications for the point of sale and banking markets. In addition, we agreed
+to pay $900,000 as a royalty for the usage of certain Seiko Epson technology
+prior to January 1, 2003, which was paid in full by January 2005. Under the
+agreement, we continue to pay royalties on a quarterly basis related to the
+sales of licensed printers, which is reflected in cost of sales.
+SEASONALITY
+Retailers typically reduce purchases of new POS equipment in the fourth
+quarter, due to the increased volume of consumer transactions in that holiday
+period, and our sales of printers in the POS market historically have increased
+in the third quarter and decreased in the fourth quarter. Similarly,
+installations of lottery terminals are typically reduced in the fourth quarter,
+resulting in decreased sales of lottery printers.
+CERTAIN CUSTOMERS
+We currently have an ongoing OEM purchase agreement, as amended in February
+2006, (the "GTECH Thermal Printer Agreement") with GTECH Corporation ("GTECH")
+that provides for the sale of thermal on-line lottery printers and spare parts,
+at fixed prices, through June 28, 2012. Firm purchase orders for printers under
+the GTECH Thermal Printer Agreement may be placed as required by GTECH. Prior to
+this agreement, we had a purchase agreement with GTECH that provided for the
+sale of impact on-line lottery printers and spare parts through December 31,
+2004. Because our new thermal on-line lottery printer is a replacement for our
+impact on-line printer, we do not expect any further shipments of impact on-line
+lottery printers. However, we do expect to continue to sell spare parts to GTECH
+for the remaining installed base of impact on-line lottery printers, although we
+expect such sales to decline as the installed base of impact on-line lottery
+printers are replaced with our thermal printer.
+BACKLOG
+Our backlog of firm orders was approximately $4,300,000 as of February 28,
+2007, compared to $8,300,000 as of February 28, 2006. Based on customers'
+current delivery requirements, we expect to ship our entire current backlog
+during 2007.
+COMPETITION
+The market for transaction-based printers is extremely competitive, and we
+expect such competition to continue in the future. We compete with a number of
+companies, many of which have greater financial, technical and marketing
+resources than us. We believe our ability to compete successfully depends on a
+number of factors both within and outside our control, including durability,
+reliability, quality, design capability, product customization, price, customer
+support, success in developing new products, manufacturing expertise and
+capacity, supply of component parts and materials, strategic relationships with
+suppliers, the timing of new product introductions by us and our competitors,
+general market, economic and political conditions and, in some cases, the
+uniqueness of our products.
+In the POS and banking market, our major competitor is Epson America, Inc.,
+which holds a dominant market position of the POS markets into which we sell. We
+also compete, to a much lesser extent, with Transaction Printer Group, Star
+Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources,
+Inc. and Samsung/Bixolon. Certain competitors of ours have greater financial
+resources, lower costs attributable to higher volume production and sometimes
+offer lower prices than us.
+In the lottery market (consisting principally of on-line lottery
+transaction printing), we hold a leading position, based largely on our
+long-term purchase agreement with GTECH, which holds approximately 70% market
+share of the worldwide on-line lottery market. We compete in this market based
+solely on our ability to provide specialized, custom-engineered products to
+GTECH.
+5
+In the gaming market (consisting principally of slot machine and video
+lottery terminal transaction printing), we compete with several companies
+including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others.
+Certain of our products sold for gaming applications compete based upon our
+ability to provide highly specialized products, custom engineering and ongoing
+technical support.
+The TransAct Services Group business is highly fragmented, and we compete
+with numerous competitors of various sizes depending on the geographic area.
+Our strategy for competing in our markets is to continue to develop new
+products and product line extensions, to increase our geographic market
+penetration, to take advantage of strategic relationships, and to lower product
+costs by sourcing certain products overseas. Although we believe that our
+products, operations and relationships provide a competitive foundation, there
+can be no assurance that we will compete successfully in the future. In
+addition, our products utilize certain inkjet, thermal and impact printing
+technology. If other technologies, or variations to existing technologies were
+to evolve or become available to us, it is possible that we would incorporate
+these technologies into our products. Alternatively, if such technologies were
+to evolve or become available to our competitors, our products could become
+obsolete, which would have a significant negative impact on our business.
+RESEARCH AND DEVELOPMENT ACTIVITIES
+We spent approximately $2,824,000, $2,726,000 and $2,715,000 in 2006, 2005
+and 2004, respectively, on engineering, design and product development efforts
+in connection with specialized engineering and design to introduce new products
+and to customize existing products.
+ENVIRONMENT
+We are not aware of any material noncompliance with federal, state and
+local provisions that have been enacted or adopted regulating the discharge of
+materials into the environment, or otherwise relating to the protection of the
+environment.
+EMPLOYEES
+As of February 28, 2007, TransAct and our subsidiaries employed 185
+persons, of whom 172 were full-time and 13 were temporary employees. None of our
+employees are unionized, and we consider our relationships with our employees to
+be good.
+FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
+We have foreign operations primarily from TransAct Technologies Ltd., a
+wholly-owned subsidiary located in the United Kingdom, which had sales to its
+customers of $2,722,000, $2,181,000, and $1,000,000, (primarily for the service
+of printers used in the British Post Office) in 2006, 2005 and 2004,
+respectively. We had export sales from our domestic operations of approximately
+$11,416,000, $10,137,000 and $5,423,000 in 2006, 2005 and 2004, respectively.
+Total international sales, which include sales from our foreign subsidiary and
+export sales from our domestic operations, were approximately $14,138,000,
+$12,318,000 and $6,423,000 in 2006, 2005 and 2004, respectively.
+ADDITIONAL INFORMATION
+We make available free of charge through our internet website,
+WWW.TRANSACT-TECH.COM, 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 as soon
+as reasonably practicable after such material is electronically filed with or
+furnished to the SEC.
+We maintain a Code of Business Conduct that includes our code of ethics
+that is applicable to all employees, including our Chief Executive Officer,
+Chief Financial Officer and Controller. This Code, which requires continued
+observance of high ethical standards such as honesty, integrity and compliance
+with the law in the conduct of our business, is available for public access on
+our internet website. Any person may request a copy of our Code of Business
+Conduct free of charge by calling (203) 859-6800.
+EXECUTIVE OFFICERS OF THE REGISTRANT
+The following list is included as an unnumbered item in Part I of this
+Report in lieu of being included in the Proxy Statement for the Annual Meeting
+of Stockholders to be held on May 15, 2007.
+6
+The following is a list of the names and ages of all executive officers of the
+registrant, indicating all positions and offices with the registrant held by
+each such person and each person's principal occupations and employment during
+at least the past five years.
+Name Age Position
+---- --- ----------------------------------------------------------------
+Bart C. Shuldman 49 Chairman of the Board, President and Chief Executive Officer
+Steven A. DeMartino 37 Executive Vice President, Chief Financial Officer, Treasurer and
+Secretary
+Michael S. Kumpf 57 Executive Vice President - Engineering
+BART C. SHULDMAN has been Chief Executive Officer, President and a Director
+of the Company since its formation in June 1996. Previously, Mr. Shuldman served
+as President of Magnetec and later the combined operations of Magnetec and
+Ithaca Peripherals from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+STEVEN A. DEMARTINO was named as TransAct's Executive Vice President, Chief
+Financial Officer, Treasurer and Secretary on June 1, 2004. Previously, Mr.
+DeMartino served as Senior Vice President, Finance and Information Technology
+from October 2001 to May 2004, Vice President and Corporate Controller from
+January 1998 to October 2001, and Corporate Controller from August 1996 to
+December 1997. Prior to joining TransAct, Mr. DeMartino was a self-employed
+financial consultant from May 1996 to August 1996. Prior to that, Mr. DeMartino
+served as Controller of Copart, Inc. from September 1994 to May 1996. Mr.
+DeMartino is a certified public accountant.
+MICHAEL S. KUMPF was appointed Executive Vice President of Engineering in
+March 2002. He served as Senior Vice President, Engineering from June 1996 to
+March 2002 and Vice President, Engineering of Ithaca Peripherals from 1991 until
+June 1996.
+ITEM 1A. RISK FACTORS
+Investors should carefully consider the risks, uncertainties and other factors
+described below, as well as other disclosures in Management's Discussion and
+Analysis of Financial Condition and Results of Operations, because they could
+have a material adverse effect on our business, financial condition, operating
+results, and growth prospects. The risks described below and incorporated by
+reference are not the only ones facing our Company. Additional risks not known
+to us now or that we currently deem immaterial may also impair our business
+operations.
+Our success will depend on our ability to sustain and manage growth.
+As part of our business strategy, we intend to pursue an aggressive growth
+strategy. Assuming this growth occurs, it will require the expansion of
+distribution relationships in international markets, the successful development
+and marketing of new products, expanded customer service and support, an
+increased number of personnel throughout the Company and the continued
+implementation and improvement of our operational, financial and management
+information systems.
+To the extent that we seek growth through acquisitions, our ability to manage
+our growth will also depend on our ability to integrate businesses that have
+previously operated independently. We may not be able to achieve this
+integration without encountering difficulties or experiencing the loss of key
+employees, customers or suppliers. It may be difficult to design and implement
+effective financial controls for combined operations and differences in existing
+controls for each business may result in weaknesses that require remediation
+when the financial controls and reporting functions are combined.
+There can be no assurance that we will be able to successfully implement our
+growth strategy, or that we can successfully manage expanded operations. As the
+Company expands, we may from time to time experience constraints that will
+adversely affect our ability to satisfy customer demand in a timely fashion.
+Failure to manage growth effectively could adversely affect our results of
+operations and financial condition.
+We compete in a highly competitive market, which is likely to become more
+competitive. Competitors may be able to respond more quickly to new or emerging
+technology and changes in customer requirements.
+We face significant competition in developing and selling our printers and
+services. Principal competitors have substantial marketing, financial,
+development and personnel resources. To remain competitive, we believe we must
+continue to provide:
+- Technologically advanced printers that satisfy the user demands,
+- Superior customer service,
+- High levels of quality and reliability, and
+- Dependable and efficient distribution networks.
+7
+We cannot ensure we will be able to compete successfully against current or
+future competitors. Increased competition in printers or supplies may result in
+price reductions, lower gross profit margins and loss of market share, and could
+require increased spending on research and development, sales and marketing and
+customer support. Some competitors may make strategic acquisitions or establish
+cooperative relationships with suppliers or companies that produce complementary
+products. Any of these factors could reduce our earnings.
+We have been dependent on sales to one large customer; the loss of this customer
+or reduction in orders from this customer could materially affect our sales.
+We expect that sales to one large customer will continue to represent a
+significant percentage of our net sales for the foreseeable future. A reduction
+or delay in orders from this customer, including reductions or delays due to
+market, economic, or competitive conditions in the industries in which we serve,
+could have a material adverse effect upon our results of operations.
+We rely on resellers to sell our products and services.
+We use a variety of distribution channels, including OEMs and distributors, to
+market our products. We may be adversely impacted by any conflicts that could
+arise between and among our various sales channels.
+Our dependence upon resellers exposes us to numerous risks, including:
+- loss of channel and the ability to bring new products to market;
+- concentration of credit risk, including disruption in distribution
+should the resellers' financial condition deteriorate;
+- reduced visibility to end user demand and pricing issues which makes
+forecasting more difficult;
+- resellers leveraging their buying power to change the terms of
+pricing, payment and product delivery schedules; and
+- direct competition should a reseller decide to manufacture printers
+internally or source printers from a competitor.
+We cannot guarantee that resellers will not reduce, delay or eliminate purchases
+from us, which could have a material adverse effect upon the business,
+consolidated results of operations and financial condition.
+Our operating results and financial condition may fluctuate.
+Our operating results and financial condition may fluctuate from quarter to
+quarter and year to year and are likely to continue to vary due to a number of
+factors, many of which are not within our control. If our operating results do
+not meet the expectations of securities analysts or investors, who may derive
+their expectations by extrapolating data from recent historical operating
+results, the market price of our common stock will likely decline. Fluctuations
+in our operating results and financial condition may be due to a number of
+factors, including, but not limited to, those identified throughout this "Risk
+Factors" section:
+- changes in accounting rules
+- changes in the amount that we spend to develop, acquire or license new
+products, consumables, technologies or businesses;
+- changes in the amount we spend to promote our products and services;
+- changes in the cost of satisfying our warranty obligations and
+servicing our installed base of printers;
+- delays between our expenditures to develop and market new or enhanced
+printers and consumables and the generation of sales from those
+products;
+- development of new competitive printers by others;
+- the geographic distribution of our sales;
+- our responses to price competition;
+- the outcome of lawsuits between TransAct and FutureLogic, Inc.
+- market acceptance of our products, both domestically and
+internationally;
+- availability of third-party components at reasonable prices;
+- general economic and industry conditions, including changes in
+interest rates affecting returns on cash balances and investments,
+that affect customer demand;
+- severe weather events (such as hurricanes) that can disrupt or
+interrupt the operation of our customers facilities; and
+- our level of research and development activities.
+Due to all of the foregoing factors, and the other risks discussed in this
+report, quarter-to-quarter comparisons of our operating results may not be an
+indicator of future performance.
+Our stock price may fluctuate significantly.
+8
+The market price of our common stock could fluctuate significantly in response
+to variations in quarterly operating results and other factors, such as:
+- changes in our business, operations or prospects;
+- developments in our relationships with our customers;
+- announcements of new products or services by us or by our competitors;
+- announcement or completion of acquisitions by us or by our
+competitors;
+- changes in existing or adoption of additional government regulations;
+- unfavorable or reduced analyst coverage; and
+- prevailing domestic and international market and economic conditions.
+In addition, the stock market has experienced significant price fluctuations in
+recent years. Broad market fluctuations, general economic conditions and
+specific conditions in the industry in which we operate may adversely affect the
+market price of our common stock.
+Limited trading volume of our capital stock may contribute to its price
+volatility.
+Our common stock is traded on the NASDAQ National Market. During the twelve
+months ended December 31, 2006, the average daily trading volume for our common
+stock as reported by the NASDAQ National Market was approximately 53,900 shares.
+We are uncertain whether a more active trading market in our common stock will
+develop. In addition, many investment banks no longer find it profitable to
+provide securities research on micro-cap and small-cap companies. If analysts
+were to discontinue coverage of our common stock, our trading volume may be
+further reduced. As a result, relatively small trades may have a significant
+impact on the market price of our common stock, which could increase the
+volatility and depress the price of our common stock.
+Future sales of our common stock may cause our stock price to decline.
+In the future, we may sell additional shares of our common stock in public or
+private offerings, and we may also issue additional shares of our common stock
+to finance future acquisitions. Shares of our common stock are also available
+for future sale pursuant to stock options that we have granted to our employees,
+and in the future we may grant additional stock options and other forms of
+equity compensation to our employees. Sales of our common stock or the
+perception that such sales could occur may adversely affect prevailing market
+prices for shares of our common stock and could impair our ability to raise
+capital through future offerings.
+We depend on key personnel, the loss of which could materially impact our
+business.
+Our future success will depend in significant part upon the continued service of
+certain key management and other personnel and our continuing ability to attract
+and retain highly qualified managerial, technical and sales and marketing
+personnel. There can be no assurance that we will be able to recruit and retain
+such personnel. The loss of Bart C. Shuldman, the Company's Chairman of the
+Board, President and Chief Executive Officer, or the loss of certain groups of
+key employees, could have a material adverse effect on our results of
+operations.
+We source some of our component parts from sole source suppliers; any
+disruptions may impact our ability to manufacture and sell our products.
+A disruption in the supply of such component parts could have a material adverse
+effect on our operations and financial results.
+The inability to protect intellectual property could harm our reputation, and
+our competitive position may be materially damaged.
+Our intellectual property is valuable and provides us with certain competitive
+advantages. Copyrights, patents, trade secrets and contracts are used to protect
+these proprietary rights. Despite these precautions, it may be possible for
+third parties to copy aspects of our products or, without authorization, to
+obtain and use information which we regard as trade secrets.
+Infringement on the proprietary rights of others could put us at a competitive
+disadvantage, and any related litigation could be time consuming and costly.
+Third parties may claim that we violated their intellectual property rights. To
+the extent of a violation of a third party's patent or other intellectual
+property right, we may be prevented from operating our business as planned and
+may be required to pay damages, to obtain a license, if available, or to use a
+non-infringing method, if possible, to accomplish our objectives. Any of these
+claims, with or without merit, could result in costly litigation and divert the
+attention of key personnel. If such claims are successful, they could result in
+costly judgments or settlements.
+We sell a significant portion of our products internationally and purchase
+important components from foreign suppliers. These circumstances create a number
+of risks.
+9
+We sell a significant amount of our products to customers outside the United
+States. Shipments to international customers are expected to continue to account
+for a material portion of net sales. Risks associated with sales and purchases
+outside the United States include:
+- Fluctuating foreign currency rates could restrict sales, or increase
+costs of purchasing, in foreign countries.
+- Foreign governments may impose burdensome tariffs, quotas, taxes,
+trade barriers or capital flow restrictions.
+- Political and economic instability may reduce demand for our products
+or put our foreign assets at risk.
+- Restrictions on the export or import of technology may reduce or
+eliminate the ability to sell in or purchase from certain markets.
+- Potentially limited intellectual property protection in certain
+countries, such as China, may limit recourse against infringing
+products or cause us to refrain from selling in certain geographic
+territories.
+We cannot provide any assurance that current laws, or any laws enacted in the
+future, will not have a material adverse effect on our business.
+Our operations are subject to laws, rules, regulations, including environmental
+regulations, government policies and other requirements in each of the
+jurisdictions in which we conduct business. Changes in laws, rules, regulations,
+policies or requirements could result in the need to modify our products and
+could affect the demand for our products, which may have an adverse impact on
+our future operating results. In addition, we must comply with new regulations
+restricting our ability to include lead and certain other substances in our
+products. If we do not comply with applicable laws, rules and regulations we
+could be subject to costs and liabilities and our business may be adversely
+impacted.
+Our business could be adversely affected by actual or threatened terrorist
+attacks or the related heightened security measures, military actions and other
+efforts to combat terrorism.
+Our business could be adversely affected by actual or threatened terrorist
+attacks or the related heightened security measures, military actions and other
+efforts to combat terrorism. It is possible that terrorist attacks could be
+directed at important locations for the gaming industry. Heightened security
+measures and other efforts to combat terrorism may also have an adverse effect
+on the gaming industry by reducing tourism. Any of these developments could also
+negatively affect the general economy and consumer confidence. Any downturn in
+the economy or in the gaming industry in particular could reduce demand for our
+products and adversely affect our business and results of operations. In
+addition, heightened security measures may cause certain governments to restrict
+the import/export of goods, which may have an adverse effect on our ability to
+buy/sell goods.
+Additional risks and uncertainties not presently known to us or that we
+currently believe to be immaterial also may adversely impact our business.
+Should any risks or uncertainties develop into actual events, these developments
+could have material adverse effects on our business, financial condition, and
+results of operations.
+We assume no obligation (and specifically disclaim any such obligation) to
+update these Risk Factors or any other forward-looking statements contained in
+this Annual Report to reflect actual results, changes in assumptions or other
+factors affecting such forward-looking statements, except as required by law.
+ITEM 1B. UNRESOLVED STAFF COMMENTS
+Not applicable.
+ITEM 2. PROPERTIES.
+Our corporate headquarters is currently located in Wallingford, CT.
+However, in November 2006, we entered into a ten-year lease for office space for
+a new, approximately 11,000 square feet corporate headquarters located in
+Hamden, CT. We expect to move into our corporate headquarters on approximately
+May 1, 2007. Concurrent with the signing of this new lease, we executed an
+agreement effective May 1, 2007 to terminate the lease agreement for our
+existing corporate headquarters and eastern region service center located in
+Wallingford, CT (the "Release Agreement"). Our global engineering and
+manufacturing center is located in Ithaca, NY. We also maintain a facility in
+Las Vegas, NV that serves as our global gaming and lottery headquarters and
+western region service center. Our eastern region service center is currently
+located in our Wallingford, CT facility, however, we are currently in
+negotiations for a new facility location.
+Our principal facilities as of December 31, 2006 are listed below:
+Size Owned or Lease Expiration
+Location Operations Conducted (Approx. Sq. Ft.) Leased Date
+-------- -------------------- ----------------- -------- ----------------
+Wallingford, Connecticut Executive offices and service center 49,000 Leased May 1, 2007
+10
+Hamden, Connecticut Executive offices 11,000 Leased April 23, 2017
+Ithaca, New York Manufacturing facility 74,000 Leased June 30, 2012
+Las Vegas, Nevada Service center and gaming and lottery 13,700 Leased January 31, 2010
+sales headquarters
+Doncaster, United Kingdom Sales office and service center 2,800 Leased August 1, 2009
+Georgia (2), New York and
+Texas Four regional sales offices 600 Leased Various
+We believe that our facilities generally are in good condition, adequately
+maintained and suitable for their present and currently contemplated uses.
+ITEM 3. LEGAL PROCEEDINGS.
+On April 28, 2005, we announced that we filed a complaint in Connecticut
+Superior Court against FutureLogic, Inc. ("FutureLogic") of Glendale,
+California. The complaint charges FutureLogic with disseminating false and
+misleading statements, which impugn our business reputation with the intent of
+damaging our business. We assert claims of defamation, tortious interference
+with contractual relations, tortious interference with business expectancy, and
+violation of the Connecticut Unfair Trade Practices Act, and seek an award of
+compensatory and punitive damages, attorneys' fees and costs. FutureLogic
+removed this action to the United States District Court for the District of
+Connecticut and, on June 7, 2005, filed a motion to dismiss the claims for lack
+of jurisdiction. On December 7, 2005, we amended our complaint in the action
+pending in the District of Connecticut to add claims that FutureLogic's conduct
+violated the Lanham Act's bar on false and deceptive advertising.
+On May 20, 2005, FutureLogic filed a complaint in the United States
+District Court for the Central District of California against us. The complaint
+charges us with false advertising, defamation, trade libel, intentional
+interference with prospective economic advantage, common law unfair competition
+and statutory unfair competition and seeks an award of compensatory and punitive
+damages, attorneys' fees and costs. On August 3, 2005, FutureLogic amended its
+complaint in California to seek a declaratory judgment that Patent No. 6,924,903
+issued to us by the United States Patent and Trademark Office ("PTO") on August
+2, 2005, for our dual-port printer technology, is invalid, and that FutureLogic
+is not infringing our patent. We moved to dismiss FutureLogic's action in
+California, on the grounds that any claims raised in that action should have
+been brought as part of the case filed by us in the District of Connecticut. In
+the alternative, we moved to stay the California action pending the resolution
+of jurisdictional motions in the Connecticut court.
+On January 20, 2006, the California District Court filed an order granting
+our motion to stay the California proceeding pending the resolution of
+jurisdictional motions in the Connecticut case. Under the California court's
+order, should the Connecticut court find that it has jurisdiction over
+FutureLogic, FutureLogic's case will be transferred to the District of
+Connecticut for consolidation with the action pending in that forum. On
+September 1, 2006, the District of Connecticut dismissed our case because of a
+lack of jurisdiction. The decision was not on the merits of our claims, but on
+the jurisdiction of the court in which the suit was brought. The California
+District Court has been notified of this development. We intend to vigorously
+defend TransAct against FutureLogic's claims, which we believe to be without
+merit. At this stage in the proceedings we are unable to estimate any potential
+or probable liability.
+ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
+No matters were submitted to a vote of security holders during the last
+quarter of the year covered by this report.
+11
+PART II
+ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
+ISSUER PURCHASES OF EQUITY SECURITIES.
+Our common stock is traded on the NASDAQ Global Market under the symbol
+TACT. As of February 28, 2007, there were 624 holders of record of the common
+stock. The high and low sales prices of the common stock reported during each
+quarter of the years ended December 31, 2006 and 2005 were as follows:
+Year Ended Year Ended
+December 31, 2006 December 31, 2005
+----------------- -----------------
+High Low High Low
+------ ----- ------ -----
+First Quarter $ 9.90 $7.80 $22.19 $9.90
+Second Quarter 14.87 8.95 10.65 6.71
+Third Quarter 11.23 8.49 10.35 6.95
+Fourth Quarter 9.38 7.47 8.70 6.09
+No dividends on common stock have been declared except for a cash dividend
+paid in lieu of fractional shares resulting from our three-for-two stock split
+in April 2004, and we do not anticipate declaring dividends in the foreseeable
+future. Our new credit agreement with TD Banknorth, N.A. restricts the payment
+of cash dividends on our common stock for the term of the agreement.
+ISSUER PURCHASES OF EQUITY SECURITIES
+On March 25, 2005, the Board of Directors approved a stock repurchase program
+("the Stock Repurchase Program"). Under the Stock Repurchase Program, we are
+authorized to repurchase up to $10 million of our outstanding shares of common
+stock from time to time in the open market over a three year period ending on
+March 25, 2008, depending on market conditions, share price and other factors.
+The following table summarizes repurchases of our common stock in the quarter
+ended December 31, 2006:
+Total Number of
+Shares
+Purchased as Approximate Dollar
+Part of Value of
+Total Average Publicly Shares that May Yet
+Number of Price Announced Be
+Shares Paid per Plans or Purchased under the
+Period Purchased Share Programs Plans or Programs
+------ --------- -------- --------------- -------------------
+October 1, 2006 - October 31, 2006 -- $ -- -- $5,281,000
+November 1, 2006 - November 30, 2006 126,000 $8.81 126,000 $4,170,000
+December 1, 2006 - December 31, 2006 78,000 $8.49 78,000 $3,508,000
+------- -------
+Total 204,000 $8.69 204,000
+======= =======
+12
+CORPORATE PERFORMANCE GRAPH
+The following graph compares the cumulative total return on the Company's Common
+Stock from December 31, 2001 through December 31, 2006, with the CRSP Total
+Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer
+Manufacturer Stocks Index. The graph assumes that $100 was invested on December
+31, 2001 in each of the Company's common stock, the CRSP Total Return Index for
+the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks
+Index, and that all dividends were reinvested.
+COMPARISON OF CUMULATIVE TOTAL RETURN AMONG
+TRANSACT TECHNOLOGIES INCORPORATED COMMON STOCK,
+THE CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.),
+AND THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX
+(PERFORMANCE GRAPH)
+12/31/01 12/31/02 12/31/03 12/31/04 12/31/05 12/31/06
+-------- -------- -------- -------- -------- --------
+TransAct Technologies Incorporated
+Common Stock $100.00 $86.18 $442.73 $582.55 $215.45 $226.36
+CRSP Total Return Index for the
+Nasdaq Stock Market (U.S.) $100.00 $69.13 $103.36 $112.49 $114.88 $126.23
+Nasdaq Computer Manufacturer
+Stocks Index $100.00 $66.27 $ 92.18 $120.53 $123.33 $126.30
+13
+ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE
+AMOUNTS)
+The following is summarized from our audited financial statements of the past
+five years:
+Year Ended December 31,
+-----------------------------------------------
+2006 2005 2004 2003(1) 2002(1)
+------- ------- ------- ------- -------
+Consolidated Statement of
+Operations Data:
+Net sales $64,328 $51,091 $59,847 $52,098 $39,461
+Gross profit 22,365 15,590 22,042 15,543 10,216
+Operating expenses 16,277 15,366 13,591 12,855 11,200
+Operating income (loss) 6,088 224 8,451 2,688 (984)
+Net income (loss) 3,916 377 5,458 1,528 (692)
+Net income (loss) available
+to common shareholders 3,916 377 5,236 1,087 (1,050)
+Net income (loss) per share:
+Basic 0.41 0.04 0.55 0.13 (0.12)
+Diluted 0.40 0.04 0.51 0.12 (0.12)
+December 31,
+-----------------------------------------------
+2006 2005 2004 2003 2002
+------- ------- ------- ------- -------
+Balance Sheet Data:
+Total assets $33,706 $29,332 $34,099 $26,361 $22,030
+Working capital 16,438 15,375 20,511 11,787 8,798
+Long-term debt, excluding
+current portion -- -- -- 330 2,791
+Redeemable convertible
+preferred stock -- -- -- 3,902 3,824
+Shareholders' equity 24,290 21,257 23,715 10,347 6,545
+(1) Net income (loss) per share amounts have been restated to reflect a
+three-for-two stock split effected in the form of a stock dividend in April
+2004.
+14
+ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
+OF OPERATIONS.
+This discussion should be read in conjunction with the Consolidated
+Financial Statements and notes thereto.
+FORWARD LOOKING STATEMENTS
+Certain statements included in this report, including without limitation
+statements in this Management's Discussion and Analysis of Financial Condition
+and Results of Operations, which are not historical facts are "forward-looking
+statements" within the meaning of Section 27A of the Securities Act of 1933, as
+amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
+Forward-looking statements generally can be identified by the use of
+forward-looking terminology, such as "may", "will", "expect", "intend",
+"estimate", "anticipate", "believe", "project" or "continue" or the negative
+thereof or other similar words. All forward-looking statements involve risks and
+uncertainties, including, but not limited to those listed in Item 1A of this
+Annual Report. Actual results may differ materially from those discussed in, or
+implied by, the forward-looking statements. The forward-looking statements speak
+only as of the date of this report and we assume no duty to update them to
+reflect new, changing or unanticipated events or circumstances.
+OVERVIEW
+The year 2006 was a successful and much improved year for TransAct as
+compared to 2005. During 2006, we marked our tenth year as a publicly traded
+company by achieving a record level of sales. We also shipped a record 186,000
+printers during 2006, led by our top-selling Epic 950(R) casino printer. In
+addition to our financial success, some of our other key accomplishments for
+2006 include the following:
+- Extending our sales contract through 2012 with GTECH for the purchase
+of our lottery printers
+- Extending our strategic sales alliance through 2009 with Eurocoin, one
+of Europe's leading suppliers of products for the amusement and gaming
+industries, to sell our gaming and casino printers in Europe and
+Africa
+- Receiving three new patents, including another key patent in
+connection with dual port technology
+- Partnering with Merley Paper Converters Ltd., the U.K.'s largest
+independent manufacturer of receipt paper rolls, for exclusive U.S.
+distribution rights for thermal receipt paper that has true full color
+images printed on the front or back under our newly-created
+POWEROLL(TM) brand
+- Signing an agreement with a leading national office supply chain to
+supply inkjet cartridges with an expected annual sales value of $1.4
+million
+We continue to focus on sales growth in our two core markets, POS and
+banking and gaming and lottery, and in our TransAct Services Group, to drive
+increased profitability. During 2006, our total net sales increased by 26% to
+approximately $64,328,000. See the table below for a breakdown of our sales by
+market.
+Change
+Year ended Year ended --------------
+(In thousands) December 31, 2006 December 31, 2005 $ %
+----------------- ----------------- ------- ----
+POS and banking $16,858 26.2% $16,410 32.1% $ 448 2.7%
+Gaming and lottery 34,677 53.9% 23,634 46.3% 11,043 46.7%
+TransAct Services Group 12,793 19.9% 11,047 21.6% 1,746 15.8%
+------- ----- ------- ----- -------
+Total net sales $64,328 100.0% $51,091 100.0% $13,237 25.9%
+======= ===== ======= ===== =======
+We experienced an increase of approximately 3% in sales of POS and banking
+printers in 2006. Although we experienced increases in sales of our line of
+thermal printers and our Bankjet(R) printers to existing banking customers,
+these increases were largely offset by lower sales of our legacy line of POS
+impact printers, as these printers are being replaced by our newer thermal and
+inkjet printers. Our sales into the POS and banking market over the last several
+years have been impacted by a market shift in technology from impact printing to
+thermal and inkjet printing. This change in technology has resulted in declining
+sales of our impact printers that were at higher average selling prices and
+increasing sales of our thermal and inkjet printers that are at lower average
+selling prices. Although our unit sales volume has increased over the last
+several years, the revenue generated from those sales have not increased to the
+same extent due to lower average selling prices of thermal and inkjet printers
+as compared to impact printers. In fact, since 1996, unit sales of all of our
+printers, including POS and banking printers, have more than doubled, while
+average selling prices of these printers have declined by approximately 38%. We
+expect sales of legacy impact printers to continue to decline. In 2007, we plan
+to focus a substantial portion of our engineering and product development
+resources on continuing to expand our portfolio of POS printers. With the global
+POS printer market of approximately $800 million, we have many opportunities for
+market share gains, primarily through increasing and enhancing our product
+portfolio, increasing geographic coverage, and growing our customer base.
+Our focus in the gaming and lottery market is two-fold. On the lottery
+side, we continue to hold a leading position based on our long-term purchase
+agreement with GTECH Corporation ("GTECH"), our largest customer and the world's
+15
+largest provider of lottery terminals, with approximately a 70% market share.
+GTECH has been our customer since 1995, and we continue to maintain a good
+relationship with them. In fact, during 2006, we extended our contract with
+GTECH through 2012. Currently, we fulfill substantially all of GTECH's printer
+requirements for lottery terminal installations and upgrades worldwide. During
+2006, we experienced solid sales growth from GTECH, with total printer sales
+increasing by approximately $4,499,000, or 65%, compared to 2005. However, our
+sales to GTECH each year are directly dependent on the timing and number of new
+and upgraded lottery terminal installations GTECH performs. Our sales to GTECH
+are not indicative of GTECH's overall business or revenue.
+On the gaming side, our focus lies primarily in supplying printers for use
+in slot machines at casinos and racetracks, as well as in other gaming devices
+that print tickets, primarily in the United States, Europe and Australia, as
+well as in the emerging Asian market, including Macau. During 2006, our domestic
+gaming printer sales increased by 42% from 2005, as we gained market share in
+the U.S. casino market due to (1) our strategic alliance agreement with JCM
+American Corporation, the worldwide leading bill acceptor company, to sell our
+casino printers, (2) increased sales to IGT, the world's largest slot machine
+manufacturer, and (3) expanded acceptance of our new Epic 950(R) thermal casino
+printer. With the success of our Epic 950(R) thermal casino printer, and our
+expanding portfolio of patented technology on this printer, including dual port
+technology, we believe we are well positioned to continue to expand our market
+share in the North American slot machine market, which now stands at over
+850,000 slot machines. In the international gaming market, we experienced our
+third consecutive record sales year in 2006, as our international gaming sales
+increased by 34% to $8.4 million, largely due to sales growth from the
+Australian market. We expect continued strength from gaming sales
+internationally during 2007, as markets such as Europe, Australia and Asia
+(including Macau) continue to adopt and/or expand ticket printing for slot
+machines and other gaming machines, and as our new line of Epic printers
+launched in 2005 for the off-premise gaming market begin to take hold.
+Our TransAct Services Group ("TSG"), which sells service, replacement parts
+and consumable products, including receipt paper, ribbons and inkjet cartridges,
+continues to offer a substantial growth opportunity and recurring revenue stream
+for TransAct. Even with declining sales of replacement parts for legacy impact
+printers as the installed base of these printers in the market declines, TSG
+revenue reached a record $12,793,000 or 20% of net sales in 2006, representing
+an increase of 16% from 2005. During 2006, our sales benefited from increased
+sales from our maintenance services, including extended warranty contracts and
+our innovative 24-hour guaranteed replacement product service called TransAct
+Xpress(SM). In addition, our sales benefited from higher inkjet cartridge sales
+including incremental sales resulting from the signing of an agreement with a
+leading national office supply chain to supply inkjet cartridges. During 2006,
+we also partnered with Merley Paper Converters Ltd., the U.K.'s largest
+independent manufacturer of receipt paper rolls, to distribute exclusively in
+the U.S. specialized thermal receipt paper that will have true full color images
+printed on the front or back. This receipt paper, that we will market under our
+newly-created POWEROLL(TM) brand, will allow users the ability to leverage the
+receipt for branding and marketing purposes, while also helping to reduce copied
+receipt fraud. We remain focused on continuing to grow the lucrative TSG in 2007
+and expect these initiatives to contribute to our growth.
+Operationally, our gross margin and operating margin showed marked
+improvement during 2006, reflecting the investment we made in the growth
+elements of our business during 2005. During 2006, our gross margin improved to
+34.8% compared to 30.5% in 2005, and our operating margin also improved to 9.5%
+compared to just 0.4% in 2005.
+Overall, we reported net income of $3.9 million and earnings per share
+(diluted) of $0.40 per share for 2006. We also generated sufficient cash during
+2006 to fund $2.9 million of capital expenditures, repurchase $2.6 million of
+our common stock (approximately 3% of our common stock outstanding) and finish
+the year with $3.4 million of cash and no debt on our balance sheet as of
+December 31, 2006.
+CRITICAL ACCOUNTING POLICIES AND ESTIMATES
+Our discussion and analysis of our financial condition and results of
+operations are based upon our consolidated financial statements, which have been
+prepared by us in accordance with accounting principles generally accepted in
+the United States of America. These principles require the use of estimates,
+judgments and assumptions. Such estimates and judgments are based upon
+historical experience and certain assumptions that are believed to be reasonable
+in the particular circumstances. Those judgments affect both balance sheet items
+and income statement categories. Our estimates include those related to revenue
+recognition, allowance for doubtful accounts, inventory obsolescence, the
+valuation of deferred tax assets and liabilities, goodwill impairment, warranty
+obligations, restructuring accruals, share-based compensation and contingent
+liabilities. We evaluate our assumptions on an ongoing basis by comparing actual
+results with our estimates. Actual results may differ from the original
+estimates. The following accounting policies are those that we believe to be
+most critical in the preparation of our financial statements.
+16
+REVENUE RECOGNITION - Our typical contracts include the sale of printers,
+which are sometimes accompanied by separately-priced extended warranty
+contracts. We also sell spare parts, consumables, and other repair services
+(sometimes pursuant to multi-year product maintenance contracts), which are not
+included in the original printer sale and are ordered by the customer as needed.
+We recognize revenue pursuant to the guidance within SAB 104, "Revenue
+Recognition." Specifically, revenue is recognized when evidence of an
+arrangement exists, delivery (based on shipping terms which are generally FOB
+shipping point) has occurred, the selling price is fixed and determinable, and
+collectibility is reasonably assured. We provide for an estimate of product
+returns and price protection based on historical experience at the time of
+revenue recognition.
+Revenue related to extended warranty and product maintenance contracts is
+recognized pursuant to FASB Technical Bulletin 90-1 ("FTB 90-1"), "Accounting
+for Separately Priced Extended Warranty and Product Maintenance Contracts."
+Pursuant to FTB 90-1, revenue related to separately priced product maintenance
+contracts is deferred and recognized over the term of the maintenance period. We
+record deferred revenue for amounts received from customers for maintenance
+contracts prior to the maintenance period.
+Our customers have the right to return products that do not function
+properly within a limited time after delivery. We monitor and track product
+returns and record a provision for the estimated future returns based on
+historical experience. Returns have historically been within expectations and
+the provisions established, but we cannot guarantee that we will continue to
+experience return rates consistent with historical patterns.
+We offer some of our customer's price protection as an incentive to carry
+inventory of our product. These price protection plans provide that if we lower
+prices, we will credit them for the price decrease on inventory they hold. Our
+customers typically carry limited amounts of inventory, and we infrequently
+lower prices on current products. As a result, the amounts paid under these
+plans have not been material. However, we cannot guarantee that this minimal
+level will continue.
+We charge our customers for shipping and handling services. The amounts
+billed to customers are recorded as revenue when the product ships. Any costs
+incurred related to these services are included in cost of sales.
+ACCOUNTS RECEIVABLE - We have standardized credit granting and review
+policies and procedures for all customer accounts, including: credit reviews of
+all new customer accounts; ongoing credit evaluations of current customers;
+credit limits and payment terms based on available credit information; and
+adjustments to credit limits based upon payment history and the customer's
+current creditworthiness. We also provide an estimate of doubtful accounts based
+on historical experience and specific customer collection issues. Our allowance
+for doubtful accounts as of December 31, 2006 was $204,000, or 1.8% of
+outstanding accounts receivable, which we feel is appropriate considering the
+overall quality of our accounts receivable. While credit losses have
+historically been within expectations and the reserves established, we cannot
+guarantee that our credit loss experience will continue to be consistent with
+historical experience. As of December 31, 2006, we had accounts receivable
+balances due from three customers of approximately 14%, 14% and 10%,
+respectively, of the total balance due, and no other customer accounts
+receivable balance exceeded 10%. As of December 31, 2005, we had accounts
+receivable balances due from one customer of 19% of the total balance due, and
+no other customer accounts receivable balance exceeded 10%.
+INVENTORY - Our inventories are valued at the lower of cost or market. We
+assess market value based on historical usage and estimates of future demand.
+Assumptions are reviewed at least quarterly and adjustments are made, as
+necessary, to reflect changing market conditions. Should circumstances change
+and we determine that additional inventory is subject to obsolescence,
+additional write-downs of inventory could result in a charge to income. As of
+December 31, 2006, our net inventory included a reserve of $1,900,000, or 20.1%
+of gross inventory, to write inventory down to lower of cost or market.
+GOODWILL - We test the impairment of goodwill each year or more frequently
+if events or changes in circumstances indicate that the carrying value may not
+be recoverable. We completed our last assessment as of December 31, 2006.
+Factors considered that may trigger an impairment review are: significant
+underperformance relative to expected historical or projected future operating
+results; significant changes in the manner of use of acquired assets or the
+strategy for the overall business; significant negative industry or economic
+trends; and significant decline in market capitalization relative to net book
+value. Goodwill amounted to $1,469,000 at December 31, 2006 and we have
+determined that no goodwill impairment has occurred.
+INCOME TAXES - In preparing our consolidated financial statements, we are
+required to estimate income taxes in each of the jurisdictions in which we
+operate. This involves estimating the actual current tax exposure together with
+assessing temporary differences between the tax basis of certain assets and
+liabilities and their reported amounts in the financial statements, as well as
+net operating losses, tax credits and other carryforwards. These differences
+result in deferred tax assets
+17
+and liabilities, which are included within our consolidated balance sheets. We
+then assess the likelihood that the deferred tax assets will be realized from
+future taxable income, and to the extent that we believe that realization is not
+likely, we establish a valuation allowance.
+Significant judgment is required in determining the provision for income
+taxes and, in particular, any valuation allowance or tax reserves with respect
+to our deferred tax assets and uncertain tax positions. On a quarterly basis, we
+evaluate the recoverability of our deferred tax assets based upon historical
+results and forecasted taxable income over future years, and match this forecast
+against the basis differences, deductions available in future years and the
+limitations allowed for net operating loss and tax credit carryforwards to
+ensure that there is adequate support for the realization of the deferred tax
+assets. While we have considered future taxable income and ongoing prudent and
+feasible tax planning strategies in assessing the need for a valuation allowance
+or tax reserve, in the event we were to determine that we would not be able to
+realize all or part of our deferred tax assets in the future, an adjustment to
+the valuation allowance or tax reserves would be charged as a reduction to
+income in the period such determination was made. Likewise, should we determine
+that we would be able to realize future deferred tax assets in excess of its net
+recorded amount, an adjustment to the valuation allowance or tax reserves would
+increase net income in the period such determination was made.
+In July 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income
+Taxes", which will be effective the first quarter of 2007. Based on the
+"more-likely-than-not" standard under FIN 48, we expect that this guidance may
+impact the Company's recognition of tax benefits related to uncertain tax
+positions. However, the Company has not yet finalized its assessment of FIN 48.
+As of December 31, 2006, we recorded a net deferred tax asset of
+approximately $2,709,000, net of a valuation allowance of $64,000, and a tax
+reserve of $333,000, primarily on portions of certain tax credits. We will need
+to recognize approximately $6.8 million in future taxable income in order to
+realize all of our deferred tax assets at December 31, 2006. Based on our
+projection of future taxable income, no additional valuation allowance is
+considered necessary. Should circumstances change and we determine that some or
+all of the deferred taxes would not be realized, a valuation allowance would be
+recorded, resulting in a charge to income in the period such determination is
+made.
+RESTRUCTURING - In February 2001, we announced plans to establish a global
+engineering and manufacturing center at our Ithaca, NY facility. As part of this
+strategic decision, we undertook a plan to consolidate all manufacturing and
+engineering into our existing Ithaca, NY facility and close our Wallingford, CT
+manufacturing facility (the "Consolidation"). As of December 31, 2001, we
+successfully transferred substantially all our Wallingford operations to Ithaca,
+NY, with the exception of our Corporate headquarters and a service center that
+remains in Connecticut. The closing of the Wallingford manufacturing facility
+resulted in the related termination of employment of approximately 70
+production, administrative and management employees.
+In connection with the Consolidation of manufacturing facilities in 2001,
+we recorded significant accruals. Through December 31, 2006, we have recognized
+approximately $5.5 million of expenses associated with the Consolidation,
+including severance pay, stay bonuses, employee benefits, moving expenses,
+non-cancelable lease payments, and other costs. Management has made reasonable
+estimates of such costs and expenses. During November 2006, we executed an
+agreement, effective May 1, 2007, to terminate the lease agreement for our
+Wallingford, CT facility. As a result, we changed our estimate of the
+restructuring accrual and reversed approximately $479,000 of restructuring
+expenses in 2006. We do not expect to incur any additional restructuring
+expenses related to the Consolidation.
+WARRANTY - We generally warrant our products for up to 24 months and record
+the estimated cost of such product warranties at the time the sale is recorded.
+Estimated warranty costs are based upon actual past experience of product
+repairs and the related estimated cost of labor and material to make the
+necessary repairs. If actual future product repair rates or the actual costs of
+material and labor differ from the estimates, adjustments to the accrued
+warranty liability and related warranty expense would be made.
+CONTINGENCIES - We record an estimated liability related to contingencies
+based on our estimates of the probable outcomes pursuant to FAS 5. On a
+quarterly basis, we assess the potential liability related to pending
+litigation, audits and other contingencies and confirm or revise estimates and
+reserves as appropriate. If the actual liabilities are settled in an amount
+greater than those recorded on the balance sheet, a change to income would be
+recorded.
+SHARE-BASED COMPENSATION - We calculate share-based compensation expense in
+accordance with SFAS 123(R), "Share-Based Payment (as amended)" using the
+Black-Scholes option-pricing model to calculate the fair value of share-based
+awards. The key assumptions for this valuation method include the expected term
+of an option grant, and the stock price volatility, risk-free interest rate,
+dividend yield, and forfeiture rate. The determination of these assumptions is
+based on
+18
+past history and future expectations, and is subject to a high level of
+judgment. To the extent any of the assumptions were to change from year to year,
+the fair value of new option grants may vary significantly.
+(A) RESULTS OF OPERATIONS
+(I) YEAR ENDED DECEMBER 31, 2006 COMPARED TO YEAR ENDED DECEMBER 31, 2005
+NET SALES. Net sales, which include printer sales and sales of spare parts,
+consumables and repair services, by market for the years ended December 31, 2006
+and 2005 were as follows:
+Change
+Year ended Year ended --------------
+(In thousands) December 31, 2006 December 31, 2005 $ %
+----------------- ----------------- ------- ----
+Point of sale and banking $16,858 26.2% $16,410 32.1% $ 448 2.7%
+Gaming and lottery 34,677 53.9% 23,634 46.3% 11,043 46.7%
+TransAct Services Group 12,793 19.9% 11,047 21.6% 1,746 15.8%
+------- ----- ------- ----- -------
+$64,328 100.0% $51,091 100.0% $13,237 25.9%
+======= ===== ======= ===== =======
+International* $14,138 22.0% $12,318 24.1% $ 1,820 14.8%
+======= ===== ======= ===== =======
+* International sales do not include sales of printers made to domestic
+distributors or other domestic customers who in turn ship those printers to
+international destinations.
+Net sales for 2006 increased $13,237,000, or 26%, from 2005 due to
+significantly higher printer shipments into our gaming and lottery market, as
+well as increased sales from our TransAct Services Group and a slight increase
+in printer shipments into our POS and banking market. Overall, international
+sales increased by $1,820,000, or 15%, due largely to higher international
+shipments of our gaming printers, primarily to Australia, somewhat offset by
+lower POS printer shipments through our international distributors.
+Point of sale and banking: Revenue from the POS and banking market includes
+sales of inkjet, thermal and impact printers used primarily by retailers in the
+hospitality, restaurant (including fine dining, casual dining and fast food) and
+specialty retail industries to print receipts for consumers, validate checks, or
+print on other inserted media. Revenue from this market also includes sales of
+printers used by banks, credit unions and other financial institutions to print
+and/or validate receipts at bank teller stations. Sales of our POS and banking
+printers worldwide increased approximately $448,000, or 3%, from 2005.
+Change
+Year ended Year ended --------------
+(In thousands) December 31, 2006 December 31, 2005 $ %
+-------------- ----------------- ----------------- ------ -----
+Domestic $15,410 91.4% $14,188 86.5% $1,222 8.6%
+International 1,448 8.6% 2,222 13.5% (774) (34.8%)
+------- ----- ------- ----- ------
+$16,858 100.0% $16,410 100.0% $ 448 2.7%
+======= ===== ======= ===== ======
+Domestic POS and banking printer sales increased to $15,410,000, representing a
+$1,222,000, or 9%, increase from 2005, due primarily to higher sales of (1) our
+line of thermal printers including our new thermal printer launched in 2005
+exclusively for POS distributors and (2) our Bankjet(R) line of inkjet printers
+to existing banking customers. Although we are currently pursuing additional
+banking opportunities, due to the project-oriented nature of these sales, we
+cannot predict if and when future sales may occur. These increases were offset
+by lower sales of our legacy line of POS impact printers, as expected, as these
+printers are being replaced by our newer thermal and inkjet printers. Our sales
+into the POS and banking market over the last several years have been impacted
+by a shift in technology in the market from impact printing technology to
+thermal and inkjet printing technology. This change in technology has resulted
+in declining sales of our impact printers that were at higher average selling
+prices and increasing sales of our thermal and inkjet printers that are at lower
+average selling prices. And, although our unit sales volume has increased over
+the last several years, the revenue generated from those sales have not
+increased to the same extent due to lower average selling prices of thermal and
+inkjet printers as compared to impact printers.
+International POS and banking printer sales decreased by approximately
+$774,000, or 35%, due primarily to lower sales of our legacy impact printers to
+our international POS distributors in Europe and Latin America, somewhat offset
+by higher sales of our iTHERM(R) 280 thermal printer to our distributors in
+Latin America.
+19
+Gaming and lottery: Revenue from the gaming and lottery market includes
+sales of printers used in slot machines, video lottery terminals ("VLTs") and
+other gaming machines that print tickets instead of issuing coins ("ticket-in,
+ticket-out" or "TITO") at casinos, racetracks ("racinos") and other gaming
+venues worldwide. Revenue from this market also includes sales of lottery
+printers to GTECH, the world's largest provider of lottery terminals, for
+various lottery applications. Sales of our gaming and lottery printers increased
+by $11,043,000, or 47%, from 2005, primarily due to an increase in sales of our
+slot machine and other gaming printers, both domestically and internationally,
+as well as higher sales of lottery printers to GTECH.
+Change
+Year ended Year ended --------------
+(In thousands) December 31, 2006 December 31, 2005 $ %
+----------------- ----------------- ------- ----
+Domestic $25,198 72.7% $16,271 68.8% $ 8,927 54.9%
+International 9,479 27.3% 7,363 31.2% 2,116 28.7%
+------- ----- ------- ----- -------
+$34,677 100.0% $23,634 100.0% $11,043 46.7%
+======= ===== ======= ===== =======
+Domestic sales of our gaming and lottery printers increased by $8,927,000,
+or 55%, from 2005 due largely to a significant increase in both sales of lottery
+printers to GTECH and thermal casino printers. Lottery printer sales to GTECH
+(excluding any international sales), which include thermal on-line lottery and
+other lottery printers, increased by approximately $4,512,000, or 77%, in 2006
+compared to 2005. Our sales to GTECH are directly dependent on the timing and
+number of new and upgraded lottery terminal installations GTECH performs, and as
+a result, may fluctuate significantly between quarters and years. Our sales to
+GTECH are not indicative of GTECH's overall business or revenue.
+Domestic gaming printer sales increased by approximately $4,415,000 driven
+primarily by increased market share as we continue to benefit from our sales
+relationship with JCM American Corporation.
+International gaming and lottery printer sales increased by approximately
+$2,116,000, or 29%, to $9,479,000 in 2006 compared to 2005. Such sales
+represented 27% and 31% of total sales into our gaming and lottery market during
+2006 and 2005, respectively. This increase was led primarily by continued growth
+in international gaming printer sales, primarily in Australia and Asia, as these
+international markets continue to expand ticket printing in slot machines and
+other gaming machines. In addition, we experienced higher gaming printer sales
+in Canada, and slightly lower international lottery printer sales to GTECH.
+TransAct Services Group: Revenue from TSG includes sales of consumable
+products (inkjet cartridges, ribbons and receipt paper), replacement parts,
+maintenance and repair services, refurbished printers and shipping and handling
+charges. Sales by TSG increased by approximately $1,746,000, or 16%.
+Change
+Year ended Year ended -------------
+(In thousands) December 31, 2006 December 31, 2005 $ %
+-------------- ----------------- ----------------- ------ ----
+Domestic $ 9,582 74.9% $ 8,314 75.3% $1,268 15.3%
+International 3,211 25.1% 2,733 24.7% 478 17.5%
+------- ----- ------- ----- ------
+$12,793 100.0% $11,047 100.0% $1,746 15.8%
+======= ===== ======= ===== ======
+Domestic TSG revenue increased by approximately $1,268,000 or 15%, to
+$9,582,000 due to revenue generated from service contracts, as well as increased
+sales of refurbished printers and consumable products. These increases were
+somewhat offset by a decline in the sale of replacement parts for certain legacy
+impact printers, as the installed base of these legacy printers in the market
+declines. International TSG sales increased by approximately $478,000, or 18%,
+to $3,211,000, due largely to an increase in maintenance and repair services
+revenue, as well as increased sales of consumable products.
+The primary operations of our United Kingdom subsidiary, a European sales
+and service center, relates to revenue generated from a service contract from a
+single customer in the United Kingdom. The contract has a termination date of
+May 2007. We do not expect that such contract will be renewed at the same volume
+of activity as the previous contract. We are currently evaluating the impact
+that this may have on our financial results.
+GROSS PROFIT. Gross profit is measured as revenue less cost of goods sold.
+Cost of goods sold includes primarily the cost of all raw materials and
+component parts, direct labor, and the associated manufacturing overhead
+expenses. Gross profit increased by $6,775,000, or 43%, to $22,365,000, and
+gross margin increased to 34.8% from 30.5% due primarily to a higher volume of
+sales and a more favorable sales mix in 2006 compared to 2005, as well as lower
+product costs resulting from increased sourcing of components for our printers
+in Asia. In addition, gross profit for 2005 was negatively impacted
+20
+by a charge of $600,000, or 1.2% of net sales, related to the write-down of
+inventory and accrual for estimated settlement/cancellation payments for
+non-cancelable purchase orders for certain excess inventory components related
+primarily to our Model 850 casino ticket printer. The charge was largely the
+result of the faster than expected acceptance of our new Epic 950(R) casino
+ticket printer, which replaces our Model 850 casino ticket printer.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses primarily include salary and payroll related expenses for
+our engineering staff, depreciation and design expenses (including prototype
+printer expenses, outside design and testing services and supplies). Such
+expenses increased by $98,000, or 4%, to $2,824,000, from 2005 as we incurred
+higher expenses related to increased engineering staffing and other employee
+compensation expenses and product development expenses related to our new line
+of off-premise gaming printers, which were largely offset by a decrease in costs
+associated with International Game Technology's ("IGT") integration and
+attainment of jurisdictional approvals for our Epic 950(R) thermal casino
+printer on all of IGT's slot platforms worldwide (the "IGT Integration"). We
+incurred approximately $150,000 of IGT Integration costs in 2005 that did not
+recur in 2006. Engineering and product development expenses decreased as a
+percentage of net sales to 4.4% from 5.3%, primarily due to higher sales volume
+in 2006 compared to 2005.
+SELLING AND MARKETING. Selling and marketing expenses primarily include
+salaries and payroll related expenses for our sales and marketing staff, sales
+commissions, travel expenses, expenses associated with the lease of sales
+offices, advertising, trade show expenses and other promotional marketing
+expenses. Selling and marketing expenses increased by $573,000, or 9%, to
+$6,892,000, as we incurred the full year effect in 2006 of expenses related to
+the addition of new corporate marketing staff, and new sales staff for our three
+strategic sales units, including those for our service centers in Las Vegas, NV
+and Wallingford, CT, made throughout 2005. We also incurred increased expenses
+related to demonstration printers and the redesign of our website that we
+re-launched in August 2006. These increases were somewhat offset by decreased
+travel, trade show, advertising, consulting and other promotional marketing
+expenses compared with 2005. Selling and marketing expenses decreased as a
+percentage of net sales to 10.7% from 12.4%, due primarily to higher sales
+volume in proportion to a higher level of expenses in 2006 compared to 2005.
+GENERAL AND ADMINISTRATIVE. General and administrative expenses primarily
+include: salaries and payroll related expenses for our executive, accounting,
+human resource and information technology staff, expenses for our corporate
+headquarters, professional and legal expenses, telecommunication expenses, and
+other expenses related to being a publicly-traded company. General and
+administrative expenses increased by $719,000, or 11%, due primarily to (1) the
+full year effect in 2006 of compensation related expenses associated with the
+relocation of our accounting department from Ithaca, NY to Wallingford, CT
+during 2005, (2) expenses associated with the Company's Oracle implementation
+including data conversion expenses, temporary help, travel and compensation
+related expenses, (3) approximately $220,000 of legal and consulting services
+related to a potential acquisition that was not consummated, (4) higher
+incentive compensation expenses based on the Company's improved performance in
+2006 and (5) increased telecommunications expenses associated with the
+implementation of our new company-wide phone system. These increases were
+partially offset by lower travel expenses and a decrease in recruiting costs
+incurred during 2005 related to the relocation of our accounting department and
+the increased staffing of the TSG sales unit that did not recur in 2006. General
+and administrative expenses decreased as a percentage of net sales to 10.9% from
+12.4%, due primarily to increased sales in proportion to higher expenses in 2006
+as compared to 2005.
+BUSINESS CONSOLIDATION AND RESTRUCTURING. During the fourth quarter of
+2006, we executed an agreement, effective May 1, 2007, to terminate the lease
+agreement for our existing corporate headquarters and eastern region service
+center facility located in Wallingford, CT (the "Release Agreement"). Prior to
+the execution of the Release Agreement, we accrued for the remaining
+non-cancelable lease payments and other related costs for this facility through
+the expiration date of the lease (March 31, 2008). As a result of the Release
+Agreement and the early termination of the old lease, we were released from the
+legal obligation for lease payments after May 1, 2007 and, accordingly, we
+reversed $479,000 of previously accrued expenses related to the Consolidation in
+the fourth quarter of 2006. As of December 31, 2006, we have provided for the
+estimated remaining non-cancelable lease payments and other related costs for
+this facility through the new termination date of the lease (May 1, 2007).
+We do not expect to incur any further restructuring expenses or to adjust
+our restructuring accrual. The restructuring accrual balance will be reduced to
+zero as of May 1, 2007.
+OPERATING INCOME. During 2006, we reported operating income of $6,088,000,
+or 9.5% of net sales, compared to $224,000, or 0.4% of net sales, in 2005. The
+substantial increase in our operating income and operating margin was due
+largely to the operating leverage we experienced in 2006 resulting from higher
+sales and gross profit, somewhat offset by higher operating expenses, compared
+to that of 2005.
+21
+INTEREST. We recorded net interest income of $104,000 in 2006 compared to
+net interest income of $73,000 in 2005. Even though our average cash balance was
+lower in 2006 compared to 2005 due largely to the repurchase of common stock
+under our stock repurchase program, our net interest income still increased as
+we substantially improved our overall rate of return on our invested cash
+balance. See "Liquidity and Capital Resources" below for more information.
+OTHER EXPENSE. We recorded other expense of $159,000 in 2006 due primarily
+to transaction exchange losses recorded by our UK subsidiary in 2006 due to the
+weakening of the U.S. dollar against the British pound. We recorded other income
+of $32,000 in 2005 due primarily to transaction exchange gains due to the
+strengthening of the U.S. dollar against the British pound in 2005.
+INCOME TAXES. We recorded an income tax provision of $2,117,000, at an
+effective rate of 35.1% during 2006 compared to an income tax benefit of
+$48,000, at an effective rate of (14.6%) in 2005. During 2005, we recorded an
+income tax benefit, as compared to an income tax provision in 2006, as we
+recognized certain discrete tax benefits and tax credits and reversed certain
+valuation allowances during 2005, combined with an unusually low level of income
+before taxes.
+NET INCOME. We reported net income in 2006 of $3,916,000, or $0.40 per
+diluted share compared to net income of $377,000, or $0.04 per diluted share in
+2005.
+(II) YEAR ENDED DECEMBER 31, 2005 COMPARED TO YEAR ENDED DECEMBER 31, 2004
+NET SALES. Net sales, which include printer sales and sales of spare parts,
+consumables and repair services, by market for the years ended December 31, 2005
+and 2004 were as follows:
+Change
+Year ended Year ended ----------------
+(In thousands) December 31, 2005 December 31, 2004 $ %
+----------------- ----------------- ------- ------
+Point of sale and banking $16,410 32.1% $17,659 29.5% $(1,249) (7.1%)
+Gaming and lottery 23,634 46.3% 31,937 53.4% (8,303) (26.0%)
+TransAct Services Group 11,047 21.6% 10,251 17.1% 796 7.8%
+------- ----- ------- ----- -------
+$51,091 100.0% $59,847 100.0% $(8,756) (14.6%)
+======= ===== ======= ===== =======
+International $12,318 24.1% $ 6,423 10.7% $ 5,895 91.8%
+======= ===== ======= ===== =======
+* International sales do not include sales of printers made to domestic
+distributors or other domestic customers who in turn ship those printers to
+international destinations.
+Net sales for 2005 decreased $8,756,000, or 15%, from 2004 due to
+significantly lower printer shipments into our gaming and lottery market, as
+well as lower printer shipments into our POS and banking market. However, sales
+from our TransAct Services Group increased by $796,000, or 8%, from 2004, as our
+installed base of printers grows and as we continue to aggressively pursue these
+after-market sales. Overall, international sales almost doubled to $12,318,000,
+due largely to higher international shipments of our gaming printers, primarily
+to Europe and Australia, as well as international shipments of lottery printers
+to GTECH.
+Point of sale and banking: Sales of our POS and banking printers worldwide
+decreased approximately $1,249,000, or 7%, from 2004.
+Change
+Year ended Year ended ---------------
+(In thousands) December 31, 2005 December 31, 2004 $ %
+----------------- ----------------- ------- -----
+Domestic $14,188 86.5% $15,734 89.1% $(1,546) (9.8%)
+International 2,222 13.5% 1,925 10.9% 297 15.4%
+------- ----- ------- ----- -------
+$16,410 100.0% $17,659 100.0% $(1,249) (7.1%)
+======= ===== ======= ====== =======
+Domestic POS and banking printer sales decreased to $14,188,000, or 10%,
+due largely to significantly lower shipments of our BANKjet(R) line of inkjet
+printers in 2005 as compared to 2004. We experienced this decrease due to the
+project-oriented nature of banking printer sales. During 2004, we shipped
+banking printers to two top-tier financial services companies. However, during
+2005, we shipped banking printers primarily to only one top-tier financial
+services company. The decrease in banking printer sales was slightly offset by
+increasing sales of our POS printers, primarily our iTHERM(R)
+22
+280 thermal printer and our new line of printers exclusively for POS
+distributors. Excluding banking printers, sales of our POS printers increased by
+2% in 2005 compared to 2004.
+International POS and banking printer sales increased by approximately
+$297,000, or 15%, due primarily to higher sales through our growing network of
+international POS distributors in Europe and Latin America, somewhat offset by
+lower sales to distributors in the Pacific Rim.
+Gaming and lottery: Revenue from the gaming and lottery market includes
+sales of printers used in slot machines, video lottery terminals ("VLTs") and
+other gaming machines that print tickets instead of issuing coins ("ticket-in,
+ticket-out" or "TITO") at casinos, racetracks ("racinos") and other gaming
+venues worldwide. Revenue from this market also includes sales of lottery
+printers to GTECH, the world's largest provider of lottery terminals, for
+various lottery applications. Sales of our gaming and lottery printers decreased
+by $8,303,000, or 26%, from 2004, primarily due to a decrease in sales of slot
+machine printers in North America, as well as a decrease in sales of lottery
+printers to GTECH. This decrease was partially offset by significantly higher
+sales of our slot machine and other gaming printers in Europe and Australia.
+Change
+Year ended Year ended ----------------
+(In thousands) December 31, 2005 December 31, 2004 $ %
+----------------- ----------------- -------- -----
+Domestic $16,271 68.8% $29,692 93.0% $(13,421) (45.2%)
+International 7,363 31.2% 2,245 7.0% 5,118 228.0%
+------- ----- ------- ----- --------
+$23,634 100.0% $31,937 100.0% $ (8,303) (26.0%)
+======= ===== ======= ===== ========
+Domestic sales of our gaming and lottery printers declined by $13,421,000,
+or 45%, from 2004. Due to the continued decline in slot machine sales into the
+domestic casino market, including the effects of Hurricane Katrina, lower
+capital spending due to mergers of major casino operators, and the loss of
+revenue from a large slot machine manufacturer as it depletes a large inventory
+position, we experienced significantly lower sales of our TITO casino printers
+throughout North America during 2005.
+Printer sales to GTECH Corporation (a worldwide lottery terminal provider
+and major customer), which include impact and thermal on-line lottery printers,
+decreased by approximately $1,153,000, or 14%, in 2005 compared to 2004. This
+decrease was largely due to shipments of legacy impact printers to GTECH in 2004
+that did not recur in 2005.
+International gaming and lottery printer sales more than tripled to
+$7,363,000 in 2005 compared to 2004. Such sales represented 31% and 7% of total
+sales into our gaming and lottery market during 2005 and 2004, respectively. We
+experienced growth in both international gaming and lottery printer sales in
+2005 as markets in Europe and Australia continue to adopt and roll out ticket
+printing in slot machines and other gaming/amusement machines, and GTECH
+installs our lottery printers in its international markets.
+TransAct Services Group: Revenue from TSG includes sales of consumable
+products (inkjet cartridges, ribbons and receipt paper), replacement parts,
+maintenance and repair services, refurbished printers and shipping and handling
+charges. Sales by TSG increased by approximately $796,000, or 8%.
+Change
+Year ended Year ended ------------
+(In thousands) December 31, 2005 December 31, 2004 $ %
+----------------- ----------------- ---- -----
+Domestic $ 8,314 75.3% $ 7,998 78.0% $316 4.0%
+International 2,733 24.7% 2,253 22.0% 480 21.3%
+------- ----- ------- ----- ----
+$11,047 100.0% $10,251 100.0% $796 7.8%
+======= ===== ======= ===== ====
+Domestic TSG revenue increased by approximately $316,000 or 4%, to
+$8,314,000 largely due to higher revenue from maintenance and repair services
+and refurbished printer sales, offset by a decline in the sale of spare parts,
+mostly for legacy printers. International TSG sales increased by approximately
+$480,000, or 21%, to $2,733,000, due primarily to an increase in service
+revenue.
+GROSS PROFIT. Gross profit decreased by $6,452,000, or 29%, to $15,590,000,
+and gross margin decreased to 30.5% from 36.8% due primarily to lower volume of
+sales in 2005 compared to 2004 and a less favorable sales mix. In addition,
+gross profit for 2005 was negatively impacted by a charge of $600,000, or 1.2%
+of net sales, related to the write-down of inventory and accrual for estimated
+settlement/cancellation payments for non-cancelable purchase orders for certain
+excess inventory components related primarily to our Model 850 casino ticket
+printer. The charge was largely the result of the
+23
+faster than expected acceptance of our new Epic 950(R) casino ticket printer,
+which replaces our Model 850 casino ticket printer.
+ENGINEERING AND PRODUCT DEVELOPMENT. Engineering, design and product
+development expenses increased slightly by $11,000, or less than 1%, to
+$2,726,000, from 2004 as we incurred higher expenses related to increased
+engineering staffing and other employee compensation expenses, which were almost
+entirely offset by a decrease in costs associated with IGT's integration and
+attainment of jurisdictional approvals for our new Epic 950(R) thermal casino
+printer on all of IGT's slot platforms worldwide (the "IGT Integration"). We
+incurred approximately $150,000 of IGT Integration costs in 2005 compared to
+$350,000 in 2004. Engineering and product development expenses increased as a
+percentage of net sales to 5.3% from 4.5%, primarily due to lower sales volume
+in 2005 compared to 2004.
+SELLING AND MARKETING. Selling and marketing expenses increased by
+$1,208,000, or 24%, to $6,319,000, due primarily to increased expenses related
+to (1) the addition of new sales staff for our three business units and our new
+service centers in Las Vegas, NV and Wallingford, CT, (2) marketing, promotional
+and trade show expenses related to the launch of our new line of printers
+exclusively for POS distributors and our increased presence at this year's
+Global Gaming Exposition (G2E) trade show in Las Vegas, NV, and (3) the
+recruitment and hiring of a Senior Vice President of Marketing during the second
+quarter of 2005. Selling and marketing expenses increased as a percentage of net
+sales to 12.4% from 8.5%, due primarily to the increases noted above in
+proportion to lower sales volume in 2005 compared to 2004.
+GENERAL AND ADMINISTRATIVE. General and administrative expenses increased
+by $331,000, or 6%, due primarily to (1) recruiting and compensation related
+expenses associated with the re-location of our accounting department from
+Ithaca, NY to Wallingford, CT, (2) higher legal expenses related to our lawsuit
+against FutureLogic, Inc., and (3) increased software maintenance, travel,
+training and temporary help expenses associated with our Oracle software
+implementation. These increases were partially offset by (1) a decrease related
+to a one-time listing fee incurred in 2004 resulting from our move back onto the
+NASDAQ National Market from the NASDAQ SmallCap Market, (2) lower audit and
+professional expenses related to compliance with the Sarbanes-Oxley Act of 2002
+incurred during 2005 (our second year of compliance) compared to 2004 (our
+initial year of compliance), and (3) expenses incurred in 2004 associated with
+our proposed acquisition of TPG, Inc. that was terminated and did not recur in
+2005. General and administrative expenses increased as a percentage of net sales
+to 12.4% from 10.0%, due primarily to the increased expenses noted above in
+proportion to a lower volume of sales in 2005 compared to 2004.
+BUSINESS CONSOLIDATION AND RESTRUCTURING. We recorded a reversal of expense
+of $225,000 related to the Consolidation in 2004. This amount was the result of
+a revision to our original estimate for non-cancelable lease payments included
+in the restructuring accrual.
+OPERATING INCOME. During 2005, we reported operating income of $224,000, or
+0.4% of net sales, compared to $8,451,000, or 14.1% of net sales, in 2004. The
+significant decrease in our operating income and operating margin was due
+largely to lower sales and gross margin, and higher operating expenses
+(primarily selling and marketing expenses and general and administrative
+expenses).
+INTEREST. We recorded net interest income of $73,000 in 2005 compared to
+net interest income of $4,000 in 2004, due to our higher average cash balances
+and slightly higher interest rates throughout 2005 as compared to 2004.
+OTHER EXPENSE. We recorded other income of $32,000 in 2005 compared to
+other expense of $18,000 in 2004, due primarily to transaction exchange gains
+recorded by our UK subsidiary in 2005 due to the weakening of the British pound
+against the U.S. dollar as compared to transaction exchange losses recorded in
+2004 due to the strengthening of the British pound against the U.S. dollar.
+INCOME TAXES. We recorded an income tax benefit of $48,000, at an effective
+rate of (14.6%) during 2005 compared to an income tax provision of $2,979,000,
+at an effective rate of 35.3% in 2004. Despite reporting $329,000 of income
+before taxes in 2005, we recorded a net income tax benefit, resulting largely
+from the recognition of certain discrete tax benefits and tax credits, as well
+as the reversal of valuation allowances during the year, combined with an
+unusually low level of income before taxes.
+NET INCOME. We reported net income in 2005 of $377,000, or $0.04 per
+diluted share compared to net income of $5,458,000, or $0.51 per diluted share
+in 2004. Dividends paid in 2004 were approximately $86,000, and there will be no
+dividends or allocation of earnings to preferred shareholders beyond 2004, as
+the preferred stock was converted to common stock in April 2004. All share and
+per share amounts reflect the April 2004 stock split on a retroactive basis.
+24
+(B) LIQUIDITY AND CAPITAL RESOURCES
+CASH FLOW
+Overview: During 2006, our cash flows reflected the results of higher sales
+volume, increased investment in infrastructure and our stock repurchase program
+as compared to 2005. Even with the repurchase of approximately $2,625,000 of our
+common stock, and capital expenditures of $2,891,000, we still finished 2006
+with no outstanding bank debt and approximately $3.4 million of cash and cash
+equivalents.
+Operating activities: The following significant factors primarily affected
+our cash provided by operations of $3,300,000 in 2006:
+- We reported net income of $3,916,000.
+- We recorded depreciation, amortization and non-cash compensation
+expense of $2,149,000.
+- Accounts receivable increased by $3,063,000 due primarily to a higher
+volume of sales in the fourth quarter of 2006 compared to the fourth
+quarter of 2005.
+- Inventories increased by $1,531,000 and accounts payable increased by
+$1,138,000 due to higher inventory purchases and inventory levels
+related to higher sales volume in the fourth quarter of 2006 compared
+to the fourth quarter of 2005.
+- Accrued liabilities and other liabilities increased by $1,423,000 due
+to increases in: (1) compensation related accruals, (2) income tax
+accrual based on the increased level of income before taxes, (3)
+deferred revenue balances related to increased sales of extended
+service contracts, (4) accruals for legal fees and (5) consulting
+services accruals related to our Oracle software implementation. These
+increases were partly offset by a decrease in warranty accruals.
+- Accrued restructuring expenses decreased by $878,000 due to $399,000
+of payments made on our Wallingford, CT lease obligation and the
+reversal of $479,000 of expense related to the execution of an
+agreement effective May 1, 2007 to terminate the lease agreement for
+our existing corporate headquarters located in Wallingford, CT.
+Investing activities: Our capital expenditures were approximately
+$2,891,000 and $2,756,000 in 2006 and 2005, respectively. Expenditures in 2006
+included approximately $1,058,000 for the purchase of hardware, software and
+outside consulting costs related to our Oracle software implementation, $366,000
+for the purchase of hardware and consulting costs related to our new phone
+system, $244,000 for the purchase of leasehold improvements made on the gaming
+and lottery headquarters and western region service center in Las Vegas, NV,
+with the remaining amount primarily related to the purchase of new product
+tooling.
+Financing activities: We used approximately $1,684,000 from financing
+activities during 2006, largely due to the repurchase of Company stock of
+approximately $2,625,000, partly offset by proceeds and tax benefits from stock
+option exercises of approximately $1,029,000. We also used approximately $88,000
+of cash related to deferred financing costs for the new revolving credit
+facility we entered into with TD Banknorth during November 2006.
+WORKING CAPITAL
+Our working capital increased to $16,438,000 at December 31, 2006 from
+$15,375,000 at December 31, 2005. The current ratio decreased to 2.9 to 1 at
+December 31, 2006 compared to 3.2 to 1 at December 31, 2005. The decrease in the
+current ratio was largely due to higher accounts payable resulting from higher
+sales volume and inventory purchases and an increase in income taxes payable
+resulting from a higher level of income before taxes, somewhat offset by higher
+accounts receivable and inventory levels. In addition, our working capital and
+current ratio were impacted by our stock repurchase program, as we continue to
+use available cash to repurchase shares of our common stock in the open market.
+DEFERRED TAXES
+As of December 31, 2006, we had a net deferred tax asset of approximately
+$2,709,000. In order to utilize this deferred tax asset, we will need to
+generate approximately $6.8 million of taxable income in future years. Based on
+future projections of taxable income, we have determined that it is more likely
+than not that the existing net deferred tax asset will be realized.
+CREDIT FACILITY AND BORROWINGS
+On November 28, 2006, we signed a new, five-year $20 million credit
+facility (the "New TD Banknorth Credit Facility") with TD Banknorth, N.A. ("TD
+Banknorth"). The new credit facility provides for a $20 million revolving credit
+line expiring on November 28, 2011. The New TD Banknorth Credit facility
+replaces a previous $11.5 million credit facility also with TD Banknorth. Due to
+TransAct's improved financial performance, our New TD Banknorth Credit Facility
+provides substantially improved terms compared to our existing credit facility,
+including lower on-going costs, fewer financial covenants, reduced reporting
+requirements and a lower interest rate. Borrowings under the new revolving
+credit line
+25
+bear a floating rate of interest at the prime rate minus one percent
+and are secured by a lien on all of our assets. We also pay a fee of 0.25% on
+unused borrowings under the revolving credit line. Deferred financing costs
+relating to expenses incurred to complete the New TD Banknorth Credit Facility
+were $88,000 at December 31, 2006. The New TD Banknorth Credit Facility imposes
+certain quarterly financial covenants on us and restricts the payment of
+dividends on our common stock and the creation of other liens. We were in
+compliance with all financial covenants of the New TD Banknorth Credit Facility
+at December 31, 2006.
+As of December 31, 2006, we had no balances outstanding on the revolving
+credit line. Undrawn commitments under the New TD Banknorth Credit facility were
+approximately $20,000,000 at December 31, 2006.
+STOCK REPURCHASE PROGRAM
+On March 25, 2005, the Board of Directors approved a stock repurchase
+program ("the Stock Repurchase Program"). Under the Stock Repurchase Program, we
+are authorized to repurchase up to $10 million of our outstanding shares of
+common stock from time to time in the open market over a three year period
+ending on March 25, 2008, depending on market conditions, share price and other
+factors. During 2006, we repurchased a total of 296,300 shares of common stock
+for approximately $2,625,000 at an average price of $8.86 per share. As of
+December 31, 2006, we have repurchased a total of 801,300 shares of common stock
+for approximately $6,492,000, at an average price of $8.10 per share.
+SHAREHOLDERS' EQUITY
+Shareholders' equity increased by $3,033,000 to $24,290,000 at December 31,
+2006 from $21,257,000 at December 31, 2005. The increase was primarily due to
+(1) net income of $3,916,000, (2) proceeds of approximately $687,000 from the
+issuance of approximately 136,000 shares of common stock from stock option
+exercises, (3) an increase in additional paid-in capital of approximately
+$342,000 resulting from tax benefits from tax deductions arising from the sale
+of employee stock from stock option exercises and vesting of restricted stock,
+and (4) non-cash compensation expense of $581,000 related to stock options and
+restricted stock, and (5) foreign currency translation adjustments of
+approximately $132,000. These increases were offset by treasury stock purchases
+of 296,300 shares of common stock for approximately $2,625,000.
+CONSOLIDATION EXPENSES
+During 2001 through 2007, we recognized approximately $5.5 million of
+business consolidation, restructuring and related expenses as a result of the
+Consolidation. These expenses primarily included employee severance and
+termination related expenses, facility closure and consolidation expenses
+(including moving expenses, estimated non-cancelable lease payments and other
+costs) and accelerated depreciation and asset disposal losses on certain
+leasehold improvements and other fixed assets.
+In November 2006, we executed an agreement, effective May 1, 2007, to
+terminate the lease agreement for our facility located in Wallingford, CT (the
+"Release Agreement"). Prior to the execution of the Release Agreement, we
+accrued for the remaining non-cancelable lease payments and other related costs
+for this facility through the expiration date of the lease (March 31, 2008). As
+a result of the Release Agreement and the early termination of the old lease, we
+were released from the legal obligation for lease payments after May 1, 2007
+and, accordingly, we reversed $479,000 of previously accrued expenses related to
+the Consolidation in the fourth quarter of 2006. As of December 31, 2006, we
+have provided for the estimated remaining non-cancelable lease payments and
+other related costs for this facility through the new termination date of the
+lease (May 1, 2007).
+As of December 31, 2006, our restructuring accrual amounted to $315,000
+which represents the estimated remaining non-cancelable lease payments and other
+related costs for the Wallingford facility through the new termination date of
+the lease (May 1, 2007). We do not expect to incur any further restructuring
+expenses or to adjust our restructuring accrual. The restructuring accrual
+balance will be reduced to zero as of May 1, 2007. We paid approximately
+$399,000, $447,000 and $446,000 of expenses related to the Consolidation in
+2006, 2005 and 2004, respectively.
+CONTRACTUAL OBLIGATIONS
+TransAct's contractual obligations as of December 31, 2006 were as follows:
+(In thousands) Total < 1 year 1-3 years 3-5 years > 5 years
+------- -------- --------- --------- ---------
+Operating lease obligations $ 5,622 $ 978 $1,743 $1,461 $1,440
+Purchase obligations 16,918 16,848 70 -- --
+------- ------- ------ ------ ------
+Total $22,540 $17,826 $1,813 $1,461 $1,440
+======= ======= ====== ====== ======
+Purchase obligations are for purchases made in the normal course of
+business to meet operational requirements, primarily of raw material and
+component part inventory.
+26
+RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
+ACCOUNTING FOR INCOME TAX UNCERTAINTIES: In July 2006, the FASB issued FASB
+Interpretation 48, "Accounting for Income Tax Uncertainties" ("FIN 48"). FIN 48
+defines the threshold for recognizing the benefits of tax return positions in
+the financial statements as "more-likely-than-not" to be sustained by the taxing
+authority. The recently issued literature also provides guidance on the
+derecognition, measurement and classification of income tax uncertainties, along
+with any related interest and penalties. FIN 48 also includes guidance
+concerning accounting for income tax uncertainties in interim periods and
+increases the level of disclosures associated with any recorded income tax
+uncertainties. FIN 48 is effective for fiscal years beginning after December 15,
+2006. The differences between the amounts recognized in the statements of
+financial position prior to the adoption of FIN 48 and the amounts reported
+after adoption will be accounted for as a cumulative-effect adjustment recorded
+to the beginning balance of retained earnings. In July 2006, the FASB issued FIN
+48, Accounting for Uncertainty in Income Taxes, which will be effective the
+first quarter of 2007. Based on the "more-likely-than-not" standard under FIN
+48, we expect that this guidance may impact the Company's recognition of tax
+benefits related to uncertain tax positions. However, the Company has not yet
+finalized its assessment of FIN 48.
+EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING CURRENT YEAR
+MISSTATEMENTS: In September 2006, the Securities and Exchange Commission issued
+Staff Accounting Bulletin ("SAB") No. 108, "Considering the Effects of Prior
+Year Misstatements when Quantifying Current Year Misstatements". SAB No. 108
+requires analysis of misstatements using both an income statement (rollover)
+approach and balance sheet (iron curtain) approach in assessing materiality and
+provides for a one-time cumulative effect transition adjustment. SAB No. 108 is
+effective for our fiscal year 2006 annual financial statements. The adoption of
+this guidance did not have a material impact on our financial position, results
+of operations or cash flows.
+FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued Statement of
+Financial Accounting Standards No. 157, "Fair Value Measurements" ("FASB 157")
+which is effective for fiscal years beginning after November 15, 2007 and for
+interim periods within those years. This statement defines fair value,
+establishes a framework for measuring fair value and expands the related
+disclosure requirements. Because the guidance was recently issued, management
+has not yet determined the impact, if any, of adopting the provisions of FASB
+157 on the Company's financial position and results of operations.
+RESOURCE SUFFICIENCY
+We believe that our cash on hand, cash flows generated from operations and
+borrowings available under the New TD Banknorth Credit Facility will provide
+sufficient resources to meet our working capital needs, including costs
+associated with the Consolidation, to finance our capital expenditures, to fund
+our Stock Repurchase Program, and meet our liquidity requirements through at
+least the next twelve months.
+(C) IMPACT OF INFLATION
+TransAct believes that its business has not been affected to a significant
+degree by inflationary trends because of the low rate of inflation during the
+past three years, nor does it believe it will be significantly affected by
+inflation during 2007.
+ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
+INTEREST RATE RISK
+Our exposure to market risk for changes in interest rates relates primarily
+to the investment of our available cash and cash equivalents. In accordance with
+our investment policy, we strive to achieve above market rates of return in
+exchange for accepting a prudent amount of incremental risk, which includes the
+risk of interest rate movements. Risk tolerance is constrained by an overriding
+objective to preserve capital. An effective increase or decrease of 10% in
+interest rates would not have a material effect on our results of operations or
+cash flows.
+FOREIGN CURRENCY EXCHANGE RISK
+A substantial portion of our sales are denominated in U.S. dollars and, as
+a result, we have relatively little exposure to foreign currency exchange risk
+with respect to sales made. This exposure may change over time as business
+practices evolve and could have a material adverse impact on our financial
+results in the future. We do not use forward exchange contracts to hedge
+exposures denominated in foreign currencies or any other derivative financial
+instruments for trading or speculative purposes. The effect of an immediate 10%
+change in exchange rates would not have a material impact on our future results
+of operations or cash flows.
+27
+ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
+Page
+Number
+------
+Report of Independent Registered Public Accounting Firm 29
+TransAct Technologies Incorporated consolidated financial statements:
+Consolidated balance sheets as of December 31, 2006 and 2005 30
+Consolidated statements of income for the years ended December 31,
+2006, 2005 and 2004 31
+Consolidated statements of changes in shareholders' equity and
+comprehensive income for the years ended December 31, 2006,
+2005 and 2004 32
+Consolidated statements of cash flows for the years ended December
+31, 2006, 2005 and 2004 33
+Notes to consolidated financial statements 34-50
+Financial Statement Schedule
+The following financial statement schedule is included herein:
+Schedule II - Valuation and Qualifying Accounts 51
+All other financial statement schedules are omitted because they are not
+applicable or the required information is shown in the consolidated financial
+statements or notes thereto
+28
+REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
+To the Board of Directors and Shareholders of TransAct Technologies
+Incorporated:
+We have completed integrated audits of TransAct Technologies Incorporated's
+consolidated financial statements and of its internal control over financial
+reporting as of December 31, 2006 in accordance with the standards of the Public
+Company Accounting Oversight Board (United States). Our opinions, based on our
+audits, are presented below.
+Consolidated financial statements and financial statement schedule
+In our opinion, the consolidated financial statements listed in the accompanying
+index present fairly, in all material respects, the financial position of
+TransAct Technologies Incorporated and its subsidiaries (the "Company") at
+December 31, 2006 and 2005, and the results of their operations and their cash
+flows for each of the three years in the period ended December 31, 2006 in
+conformity with accounting principles generally accepted in the United States of
+America. In addition, in our opinion, the financial statement schedule listed in
+the accompanying index presents fairly, in all material respects, the
+information set forth therein when read in conjunction with the related
+consolidated financial statements. These financial statements and financial
+statement schedule are the responsibility of the Company's management. Our
+responsibility is to express an opinion on these financial statements and
+financial statement schedule based on our audits. We conducted our audits of
+these statements 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 of financial statements
+includes 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. We believe that our audits provide a
+reasonable basis for our opinion.
+As discussed in Note 2 to the consolidated financial statements, the Company
+changed the manner in which it accounts for share-based compensation in 2006.
+Internal control over financial reporting
+Also, in our opinion, management's assessment, included in Management's Report
+on Internal Control Over Financial Reporting appearing under Item 9a, that the
+Company maintained effective internal control over financial reporting as of
+December 31, 2006 based on criteria established in Internal Control - Integrated
+Framework issued by the Committee of Sponsoring Organizations of the Treadway
+Commission (COSO), is fairly stated, in all material respects, based on those
+criteria. Furthermore, in our opinion, the Company maintained, in all material
+respects, effective internal control over financial reporting as of December 31,
+2006 based on criteria established in Internal Control - Integrated Framework
+issued by the 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. Our
+responsibility is to express opinions on management's assessment and on the
+effectiveness of the Company's internal control over financial reporting based
+on our audit. We conducted our audit of internal control over financial
+reporting 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. An audit of internal control over financial reporting includes
+obtaining an understanding of internal control over financial reporting,
+evaluating management's assessment, testing and evaluating the design and
+operating effectiveness of internal control, and performing such other
+procedures as we consider necessary in the circumstances. We believe that our
+audit provides 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
+PricewaterhouseCoopers LLP
+Hartford, CT
+March 15, 2007
+29
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED BALANCE SHEETS
+(In thousands, except share data)
+December 31, December 31,
+2006 2005
+------------ ------------
+ASSETS:
+Current assets:
+Cash and cash equivalents $ 3,436 $ 4,579
+Receivables, net 11,422 8,359
+Inventories 7,567 6,036
+Refundable income taxes 42 295
+Deferred tax assets 2,167 2,735
+Other current assets 552 258
+------- -------
+Total current assets 25,186 22,262
+------- -------
+Fixed assets, net 5,938 4,510
+Goodwill 1,469 1,469
+Deferred tax assets 542 557
+Intangible and other assets, net of accumulated amortization
+of $122 and $41, respectively 571 534
+------- -------
+8,520 7,070
+------- -------
+Total assets $33,706 $29,332
+======= =======
+LIABILITIES AND SHAREHOLDERS' EQUITY:
+Current liabilities:
+Accounts payable $ 3,997 $ 2,859
+Accrued liabilities 4,047 3,198
+Accrued restructuring expenses 315 420
+Deferred revenue 389 410
+------- -------
+Total current liabilities 8,748 6,887
+------- -------
+Accrued restructuring expenses, net of current portion -- 773
+Deferred revenue, net of current portion 508 270
+Accrued warranty, net of current portion 160 145
+------- -------
+668 1,188
+------- -------
+Total liabilities 9,416 8,075
+------- -------
+Commitments and contingencies (Note 11)
+Shareholders' equity:
+Preferred stock, $0.01 par value, 4,800,000
+authorized, none issued and outstanding -- --
+Preferred stock, Series A, $0.01 par value, 200,000
+authorized, none issued and outstanding -- --
+Common stock, $0.01 par value, 20,000,000 authorized at
+December 31, 2006 and 2005; 9,574,777 and
+9,731,670 shares issued; 8,773,477 and 9,226,670
+shares outstanding, at December 31, 2006 and 2005,
+respectively 104 102
+Additional paid-in capital 19,105 19,334
+Retained earnings 11,405 7,489
+Unamortized restricted stock compensation -- (1,837)
+Accumulated other comprehensive income, net of tax 168 36
+Treasury stock, 801,300 and 505,000 shares at cost (6,492) (3,867)
+------- -------
+Total shareholders' equity 24,290 21,257
+------- -------
+Total liabilities and shareholders' equity $33,706 $29,332
+======= =======
+See accompanying notes to consolidated financial statements.
+30
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF INCOME
+(In thousands, except per share data)
+Year Ended December 31,
+---------------------------
+2006 2005 2004
+------- ------- -------
+Net sales $64,328 $51,091 $59,847
+Cost of sales 41,963 35,501 37,805
+------- ------- -------
+Gross profit 22,365 15,590 22,042
+------- ------- -------
+Operating expenses:
+Engineering, design and product development 2,824 2,726 2,715
+Selling and marketing 6,892 6,319 5,111
+General and administrative 7,040 6,321 5,990
+Business consolidation and restructuring (479) -- (225)
+------- ------- -------
+16,277 15,366 13,591
+------- ------- -------
+Operating income 6,088 224 8,451
+------- ------- -------
+Interest and other income (expense):
+Interest expense (44) (41) (44)
+Interest income 148 114 48
+Other, net (159) 32 (18)
+------- ------- -------
+(55) 105 (14)
+------- ------- -------
+Income before income taxes 6,033 329 8,437
+Income tax provision (benefit) 2,117 (48) 2,979
+------- ------- -------
+Net income 3,916 377 5,458
+Dividends and accretion charges on preferred
+stock -- -- (111)
+Earnings allocated to preferred shareholders -- -- (111)
+------- ------- -------
+Net income available to common shareholders $ 3,916 $ 377 $ 5,236
+======= ======= =======
+Net income per common share:
+Basic $ 0.41 $ 0.04 $ 0.55
+Diluted $ 0.40 $ 0.04 $ 0.51
+Shares used in per-share calculation:
+Basic 9,577 9,849 9,593
+Diluted 9,870 10,163 10,231
+See accompanying notes to consolidated financial statements.
+31
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY AND
+COMPREHENSIVE INCOME
+(In thousands, except share data)
+Unamortized Accumulated
+Common Stock Additional Restricted Other Total
+------------------ Paid-in Retained Stock Treasury Comprehensive Comprehensive
+Shares Amount Capital Earnings Compensation Stock Income (Loss) Total Income
+---------- ------ ---------- -------- ------------ -------- ------------- ------- -------------
+Balance, December 31,
+2003 8,952,650 60 8,441 1,769 (30) -- 107 10,347
+Cancellation of
+restricted stock (3,000) -- (72) -- 72 -- -- --
+Issuance of shares
+from exercise of
+stock options 321,947 3 1,376 -- -- -- -- 1,379
+Issuance of shares
+from employee
+stock purchase
+plan 3,706 -- 47 -- -- -- -- 47
+Issuance of shares
+from exercise of
+common stock
+warrants 15,000 -- 90 -- -- -- -- 90
+Issuance of shares
+from conversion
+of preferred
+stock, net of
+issuance and
+registration
+costs 666,665 6 3,818 -- -- -- -- 3,824
+Issuance of
+restricted stock 81,000 1 1,399 -- (1,400) -- -- --
+Share-based
+compensation
+expense -- -- -- -- 291 -- -- 291
+Tax benefit related
+to employee
+stock sales -- -- 2,332 -- -- -- -- 2,332
+Redemption of
+partial shares
+of common stock
+in connection
+with the 3:2
+stock split (202) 30 (30) -- -- -- -- --
+Dividends paid on
+preferred stock -- -- -- (91) -- -- -- (91)
+Accretion of
+preferred stock
+discount and
+issuance costs -- -- -- (24) -- -- -- (24)
+Comprehensive
+income:
+Foreign currency
+translation
+adj. -- -- -- -- -- -- 62 62 62
+Net income -- -- -- 5,458 -- -- -- 5,458 5,458
+---------- ---- ------- ------- ------- ------- ------ ------- ------
+Balance, December 31,
+2004 10,037,766 100 17,401 7,112 (1,067) -- 169 23,715 5,520
+======
+Cancellation of
+restricted stock (250) -- (3) -- 3 -- -- --
+Issuance of shares
+from exercise of
+stock options 71,064 1 323 -- -- -- -- 324
+Issuance of shares
+from employee
+stock purchase
+plan 2,690 -- 23 -- -- -- -- 23
+Acceleration of
+outstanding
+stock options -- -- 26 -- -- -- -- 26
+Issuance of
+restricted stock 125,400 1 1,230 -- (1,231) -- -- --
+Share-based
+compensation
+expense -- -- -- -- 458 -- -- 458
+Tax benefit related
+to employee
+stock sales and
+vesting of
+restricted stock -- -- 337 -- -- -- -- 337
+Purchase of
+treasury stock (505,000) -- -- -- -- (3,867) -- (3,867)
+Expenses related to
+preferred stock
+conversion -- -- (3) -- -- -- -- (3)
+Comprehensive
+income:
+Foreign currency
+translation
+adj., net of
+tax -- -- -- -- -- -- (133) (133) (133)
+Net income -- -- -- 377 -- -- -- 377 377
+---------- ---- ------- ------- ------- ------- ------ ------- ------
+Balance, December 31,
+2005 9,731,670 102 19,334 7,489 (1,837) (3,867) 36 21,257 244
+======
+Impact of adoption
+of new
+accounting
+pronouncements -- -- (1,837) -- 1,837 -- -- --
+Cancellation of
+restricted stock (11,750) -- -- -- -- -- -- --
+Issuance of shares
+from exercise of
+stock options 136,157 2 685 -- -- -- -- 687
+Issuance of
+restricted stock 15,000 -- -- -- -- -- -- --
+Tax benefit related
+to employee
+stock sales and
+vesting of
+restricted stock -- -- 342 -- -- -- -- 342
+Purchase of
+treasury stock (296,300) -- -- -- -- (2,625) -- (2,625)
+Share-based
+compensation
+expense -- -- 581 -- -- -- -- 581
+Comprehensive
+income:
+Foreign currency
+translation
+adj., net of
+tax -- -- -- -- -- -- 132 132 132
+Net income -- -- -- 3,916 -- -- -- 3,916 3,916
+---------- ---- ------- ------- ------- ------- ------ ------- ------
+Balance, December 31,
+2006 9,574,777 $104 $19,105 $11,405 $ -- $(6,492) $ 168 $24,290 $4,048
+========== ==== ======= ======= ======= ======= ====== ======= ======
+See accompanying notes to consolidated financial statements.
+32
+TRANSACT TECHNOLOGIES INCORPORATED
+CONSOLIDATED STATEMENTS OF CASH FLOWS
+(In thousands)
+Year Ended December 31,
+---------------------------
+2006 2005 2004
+------- ------- -------
+Cash flows from operating activities:
+Net income $ 3,916 $ 377 $ 5,458
+Adjustments to reconcile net income to net cash provided by
+operating activities:
+Share-based compensation expense 581 484 291
+Incremental tax benefits from stock options exercised (342) -- --
+Depreciation and amortization 1,568 1,493 1,634
+Deferred income taxes 583 (648) 380
+Loss (gain) on sale of fixed assets -- 4 --
+Reversal of accrued restructuring expense (479) -- (225)
+Changes in operating assets and liabilities:
+Receivables (3,063) 551 164
+Inventories (1,531) 2,038 (13)
+Refundable income taxes 253 215 (380)
+Other current assets (276) 328 (207)
+Other assets (72) 3 (8)
+Accounts payable 1,138 (945) 516
+Accrued liabilities and deferred revenue 1,423 (580) 1,179
+Accrued restructuring expenses (399) (447) (446)
+------- ------- -------
+Net cash provided by operating activities 3,300 2,873 8,343
+------- ------- -------
+Cash flows from investing activities:
+Purchases of fixed assets (2,891) (2,756) (1,178)
+Purchase of intangible assets -- (510) --
+------- ------- -------
+Net cash used in investing activities (2,891) (3,266) (1,178)
+------- ------- -------
+Cash flows from financing activities:
+Term loan repayments -- -- (420)
+Payment of deferred financing costs (88) -- --
+Proceeds from stock option exercises 687 347 1,516
+Purchases of common stock for treasury (2,625) (3,867) --
+Incremental tax benefits from stock options exercised 342
+Payment of cash dividends -- -- (91)
+Payment of preferred stock conversion and registration -- (3) (102)
+expense
+------- ------- -------
+Net cash (used in) provided by financing activities (1,684) (3,523) 903
+------- ------- -------
+Effect of exchange rate changes 132 (133) 62
+------- ------- -------
+(Decrease) increase in cash and cash equivalents (1,143) (4,049) 8,130
+Cash and cash equivalents, beginning of period 4,579 8,628 498
+------- ------- -------
+Cash and cash equivalents, end of period $ 3,436 $ 4,579 $ 8,628
+======= ======= =======
+Supplemental cash flow information:
+Interest paid $ 43 $ 41 $ 44
+Income taxes paid 1,201 431 517
+Non-cash financing activities:
+Conversion of preferred stock to common stock $ -- $ -- $ 3,926
+Tax benefit related to employee stock sales and restricted
+stock 342 337 2,332
+Accretion of preferred stock discount and issuance costs -- -- 24
+Issuance of restricted stock 207 1,231 1,400
+See accompanying notes to consolidated financial statements.
+33
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+1. DESCRIPTION OF BUSINESS
+TransAct Technologies Incorporated ("TransAct"), which has its
+headquarters in Wallingford, CT and its primary operating facility in
+Ithaca, NY, operates in one industry segment, market-specific printers for
+transaction-based industries. These industries include gaming, lottery,
+banking and hospitality. Our printers are designed based on market specific
+requirements and are sold under the Ithaca(R) and Epic(TM) product brands.
+We distribute our products through OEMs, value-added resellers, selected
+distributors, and directly to end-users. Our product distribution spans
+across the Americas, Europe, the Middle East, Africa, Asia, Australia, the
+Caribbean Islands and the South Pacific. We also generate revenue from the
+after-market side of the business, providing printer service, supplies and
+spare parts.
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+STOCK SPLIT: On March 17, 2004, we effected a three-for-two split of
+our common stock in the form of a 50 percent stock dividend. All share and
+per-share amounts within the accompanying financial statements and
+footnotes reflect the stock split.
+PRINCIPLES OF CONSOLIDATION: The accompanying consolidated financial
+statements were prepared on a consolidated basis to include the accounts of
+TransAct and its wholly-owned subsidiaries. All intercompany accounts,
+transactions and unrealized profit were eliminated in consolidation.
+RECLASSIFICATIONS: Certain amounts in the prior years' financial
+statements have been reclassified to conform to the current year's
+presentation.
+USE OF ESTIMATES: The accompanying consolidated financial statements
+were prepared using estimates and assumptions that affect the reported
+amounts of assets, liabilities, revenue and expenses, and disclosure of
+contingent assets and liabilities as of the date of the consolidated
+financial statements and the reported amounts of revenues and expenses
+during the reporting period. Actual results could differ from those
+estimates.
+SEGMENT REPORTING: We apply the provisions of Statement of Financial
+Accounting Standards No. 131, "Disclosures about Segments of an Enterprise
+and Related Information" ("FAS 131"). We view our operations and manage our
+business as one segment: the design, development, manufacture and sale of
+transaction-based printers. Factors used to identify TransAct's single
+operating segment include the organizational structure of the Company and
+the financial information available for evaluation by the chief operating
+decision-maker in making decisions about how to allocate resources and
+assess performance. We operate predominantly in one geographical area, the
+United States of America. See Note 20 for information regarding our
+international operations. We provide the following disclosures of revenues
+from products and services:
+Year ended Year ended Year ended
+(In thousands) December 31, 2006 December 31, 2005 December 31, 2004
+----------------- ----------------- -----------------
+POS and banking printers $16,858 26.2% $16,410 32.1% $17,659 29.5%
+Gaming and lottery printers 34,677 53.9% 23,634 46.3% 31,937 53.4%
+Services, spare parts and
+consumables 12,793 19.9% 11,047 21.6% 10,251 17.1%
+------- ----- ------- ----- ------- -----
+Total net sales $64,328 100.0% $51,091 100.0% $59,847 100.0%
+======= ===== ======= ===== ======= =====
+CASH AND CASH EQUIVALENTS: We consider all highly liquid investments with a
+maturity date of three months or less at date of purchase to be cash
+equivalents.
+ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS: We have
+standardized credit granting and review policies and procedures for all customer
+accounts, including:
+- Credit reviews of all new customer accounts,
+- Ongoing credit evaluations of current customers,
+- Credit limits and payment terms based on available credit information,
+- Adjustments to credit limits based upon payment history and the
+customer's current creditworthiness.
+34
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+We establish an allowance for doubtful accounts to ensure trade
+receivables are valued appropriately. We maintain an allowance for doubtful
+accounts based on a variety of factors, including the length of time
+receivables are past due, significant one-time events and historical
+experience. We record a specific allowance for individual accounts when we
+become aware of a customer's inability to meet its financial obligations,
+such as in the case of bankruptcy filings or deterioration in the
+customer's operating results or financial position. If circumstances
+related to customers change, we would further adjust estimates of the
+recoverability of receivables. Allowances for doubtful accounts on accounts
+receivable balances were $204,000 and $240,000, as of December 31, 2006 and
+2005, respectively.
+INVENTORIES: Inventories are stated at the lower of cost (principally
+standard cost which approximates actual cost on a first-in, first-out
+basis) or market. We assess market value based on historical usage and
+estimates of future demand in the market.
+FIXED ASSETS: Fixed assets are stated at cost. Depreciation is
+recorded using the straight-line method over the estimated useful lives.
+The estimated useful life of tooling is five years; machinery and equipment
+is ten years; furniture and office equipment is five to ten years; and
+computer software and equipment is three to seven years. Leasehold
+improvements are amortized over the shorter of the term of the lease or the
+useful life of the asset. Costs related to repairs and maintenance are
+expensed as incurred. The costs of sold or retired assets are removed from
+the related asset and accumulated depreciation accounts and any gain or
+loss is recognized. Depreciation expense was $1,466,000, $1,419,000 and
+$1,608,000 in 2006, 2005 and 2004, respectively.
+LEASES: Rent expense under non-cancelable operating leases with
+scheduled rent increases or free rent periods is accounted for on a
+straight-line basis over the lease term, beginning on the date of control
+of physical use of the asset or of initial possession. The amount of the
+excess of straight-line rent expense over scheduled payments is recorded as
+a deferred liability. Construction allowances and other such lease
+incentives are recorded as deferred credits, and are amortized on a
+straight-line basis as a reduction of rent expense beginning in the period
+they are deemed to be earned, which generally coincides with the occupancy
+date.
+GOODWILL: We adopted the provisions of Statement of Financial
+Accounting Standard No. 142, "Goodwill and Other Intangible Assets" ("FAS
+142") on January 1, 2002. Under FAS 142, goodwill is no longer amortized
+and is tested for impairment at least annually at the reporting unit level.
+We test goodwill annually for impairment, or whenever events or
+changes in circumstances indicate that the carrying value may not be
+recoverable. We have performed an impairment test as of December 31, 2006
+and determined that no impairment has occurred.
+REVENUE RECOGNITION: Our typical contracts include the sale of
+printers, which are sometimes accompanied by separately-priced extended
+warranty contracts. We also sell spare parts, consumables, and other repair
+services (sometimes pursuant to multi-year product maintenance contracts)
+which are not included in the original printer sale and are ordered by the
+customer as needed. We recognize revenue pursuant to the guidance within
+SAB 104, "Revenue Recognition." Specifically, revenue is recognized when
+evidence of an arrangement exists, delivery (based on shipping terms, which
+are generally FOB shipping point) has occurred, the selling price is fixed
+and determinable, and collectibility is reasonably assured. We provide for
+an estimate of product returns based on historical experience at the time
+of revenue recognition.
+Revenue related to extended warranty and product maintenance contracts
+is recognized pursuant to FASB Technical Bulletin 90-1 ("FTB 90-1"),
+"Accounting for Separately Priced Extended Warranty and Product Maintenance
+Contracts." Pursuant to FTB 90-1, revenue related to separately priced
+product maintenance contracts is deferred and recognized over the term of
+the maintenance period. We record deferred revenue for amounts received
+from customers for maintenance contracts prior to the maintenance period.
+35
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+CONCENTRATION OF CREDIT RISK: Financial instruments that potentially
+expose TransAct to concentrations of credit risk are limited to accounts
+receivable.
+Accounts receivable from customers representing 10% or more of total
+accounts receivable were as follows:
+December 31,
+------------
+2006 2005
+---- ----
+Customer A 14% 19%
+Customer B 10% *
+Customer C 14% *
+* - customer balances were less than 10% of total accounts receivable
+Sales to customers representing 10% or more of total net sales were as
+follows:
+Year ended December 31,
+-----------------------
+2006 2005 2004
+---- ---- ----
+Customer A 20% 17% 16%
+Customer B * 14% *
+Customer C * * 14%
+* - customer balances were less than 10% of total net sales
+The primary operations of our United Kingdom subsidiary, a European
+sales and service center, relates to revenue generated from a service
+contract from a single customer in the United Kingdom. The contract has a
+termination date of May 2007. We do not expect that such contract will be
+renewed at the same volume of activity as the previous contract. We are
+currently evaluating the impact that this may have on our financial
+results.
+WARRANTY: We generally warrant our products for up to 24 months and
+record the estimated cost of such product warranties at the time the sale
+is recorded. Estimated warranty costs are based upon actual past experience
+of product repairs and the related estimated cost of labor and material to
+make the necessary repairs.
+The following table summarizes the activity recorded in the accrued
+product warranty liability:
+Year ended December 31,
+-----------------------
+(In thousands) 2006 2005 2004
+----- ----- -----
+Balance, beginning of year $ 644 $ 597 $ 495
+Additions related to warranties issued 595 613 610
+Warranty costs incurred (636) (566) (508)
+----- ----- -----
+Balance, end of year $ 603 $ 644 $ 597
+===== ===== =====
+Approximately $160,000 and $145,000 of the accrued product warranty
+liability were classified as long-term at December 31, 2006 and 2005,
+respectively.
+RESEARCH AND DEVELOPMENT EXPENSES: Research and development expenses
+include engineering, design and product development expenses incurred in
+connection with specialized engineering and design to introduce new
+products and to customize existing products, and are expensed as a
+component of operating expenses as incurred. We recorded approximately
+$2,824,000, $2,726,000 and $2,715,000 of research and development expense
+in the years ended December 31, 2006, 2005 and 2004, respectively.
+ADVERTISING: Advertising costs are expensed as incurred. Advertising
+expenses, which are included in selling and marketing on the accompanying
+consolidated statements of income, for the years ended December 31, 2006,
+2005 and 2004 totaled $182,000, $371,000 and $343,000, respectively.
+36
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+RESTRUCTURING: In 2001, we undertook a plan to consolidate all
+manufacturing and engineering into our existing Ithaca, NY facility and
+close our Wallingford, CT manufacturing facility. We continue to apply the
+consensus set forth in EITF 94-3, "Liability Recognition for Certain
+Employee Termination Benefits and Other Costs to Exit an Activity
+(Including Certain Costs Incurred in a Restructuring)" in recognizing
+restructuring expenses. See Note 8 for additional disclosures related to
+our restructuring plan.
+INCOME TAXES: The income tax amounts reflected in the accompanying
+financial statements are accounted for under the liability method in
+accordance with FAS 109 "Accounting for Income Taxes." Deferred tax assets
+and liabilities are recognized for the estimated future tax consequences
+attributable to differences between the financial statement carrying
+amounts of existing assets and liabilities and their respective tax bases
+and operating loss and tax credit carryforwards. Deferred tax assets and
+liabilities are measured using enacted tax rates in effect for the year in
+which those temporary differences are expected to be recovered or settled.
+We assess the likelihood that net deferred tax assets will be realized from
+future taxable income, and to the extent that we believe that realization
+is not likely, we establish a valuation allowance.
+FOREIGN CURRENCY TRANSLATION: The financial position and results of
+operations of our foreign subsidiary in the United Kingdom are measured
+using local currency as the functional currency. Assets and liabilities of
+such subsidiary have been translated into U.S. dollars at the year-end
+exchange rate, related revenues and expenses have been translated at the
+weighted average exchange rate for the year, and shareholders' equity has
+been translated at historical exchange rates. The resulting translation
+gains or losses, net of tax, are recorded in stockholders' equity as a
+cumulative translation adjustment, which is a component of accumulated
+other comprehensive income. Foreign currency transaction gains and losses,
+including those related to intercompany balances, are recognized in other
+income (expense).
+FAIR VALUE OF FINANCIAL INSTRUMENTS: The carrying amount for cash and
+cash equivalents approximates fair value because of the short maturity of
+these instruments. The carrying amount of receivables, accounts payable and
+accrued liabilities is a reasonable estimate of fair value because of the
+short-term nature of these accounts.
+COMPREHENSIVE INCOME: Statement of Accounting Standard No. 130,
+"Reporting Comprehensive Income" ("FAS 130"), requires that items defined
+as comprehensive income or loss be separately classified in the financial
+statements and that the accumulated balance of other comprehensive income
+or loss be reported separately from accumulated deficit and additional
+paid-in-capital in the equity section of the balance sheet. We include the
+foreign currency translation adjustment, net of tax, related to our
+subsidiary in the United Kingdom within our calculation of comprehensive
+income.
+SHARE-BASED PAYMENTS: In December 2004, the Financial Accounting
+Standards Board ("FASB") revised Statement of Financial Accounting
+Standards No. 123 (revised 2004), "Share-Based Payment" ("FAS 123R"), which
+establishes accounting for share-based awards exchanged for employee
+services and requires companies to expense the estimated fair value of
+these awards over the requisite employee service period. We adopted the
+accounting provisions of FAS 123R beginning in the first quarter of 2006.
+Prior to January 1, 2006, we accounted for share-based compensation to
+employees in accordance with Accounting Principles Board Opinion No. 25,
+("APB 25") "Accounting for Stock Issued to Employees," and related
+interpretations. We also followed the disclosure requirements of Statement
+of Financial Accounting Standards No. 123, "Accounting for Stock-Based
+Compensation" ("FAS 123"), as amended by Statement of Financial Accounting
+Standards 148, "Accounting for Stock-Based Compensation - Transition and
+Disclosure" ("FAS 148").
+Under FAS 123R, share-based compensation expense is measured at the
+grant date, based on the estimated fair value of the award, and is
+recognized as expense over the employee's requisite service period. We have
+no awards with market or performance conditions. We adopted the provisions
+of FAS 123R on January 1, 2006, using a modified prospective application
+("MPA"), which provides for certain changes to the method for valuing
+share-based compensation. Under the MPA, prior periods are not revised for
+comparative purposes. The valuation provisions of FAS 123R apply to new
+awards and to modifications or cancellations of awards that are outstanding
+on the effective date.
+37
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
+In November 2005, the FASB issued FASB Staff Position No. FAS
+123(R)-3, "Transition Election Related to Accounting for Tax Effects of
+Share-Based Payment Awards." We have elected to adopt the alternative
+transition method provided in this FASB Staff Position for calculating the
+tax effects of share-based compensation pursuant to FAS 123R. The
+alternative transition method includes a simplified method to establish the
+beginning balance of the additional paid-in capital pool related to the tax
+effects of employee share-based compensation, which is available to absorb
+tax deficiencies recognized subsequent to the adoption of FAS 123R.
+We use the Black-Scholes option-pricing model to calculate the fair
+value of share based awards. The key assumptions for this valuation method
+include the expected term of the option, stock price volatility, risk-free
+interest rate, dividend yield and exercise price. Many of these assumptions
+are judgmental and highly sensitive in the determination of compensation
+expense. In addition, we estimate forfeitures when recognizing compensation
+expense, and we will adjust our estimate of forfeitures over the requisite
+service period based on the extent to which actual forfeitures differ, or
+are expected to differ, from such estimates. Changes in estimated
+forfeitures will be recognized through a cumulative true-up adjustment in
+the period of change and will also impact the amount of compensation
+expense to be recognized in future periods.
+On November 2, 2005, the Compensation Committee of the Board of
+Directors approved the acceleration of the vesting of all outstanding
+unvested stock options granted to directors, officers and employees of the
+Company under our applicable stock incentive plans. As a result of the
+acceleration, options to acquire approximately 109,500 shares of our common
+stock, which otherwise would have vested from time to time over the next
+four years, became immediately exercisable. All other terms and conditions
+applicable to the outstanding stock option grants remain in effect. The
+option plans under which accelerated grants were issued are our 1996 Stock
+Plan, 1996 Directors' Stock Plan and the 2001 Employee Stock Plan.
+The Compensation Committee's decision to accelerate the vesting of
+affected stock options was primarily based upon our required adoption of
+FAS 123R effective January 1, 2006. Due to the acceleration of vesting of
+unvested options prior to the adoption of FAS123R, we are only recording
+compensation expense related to stock options granted in 2006 and beyond.
+We recorded approximately $26,000 of compensation expense in the fourth
+quarter of 2005 related to the acceleration of vesting.
+NET INCOME AND LOSS PER SHARE: We report net income or loss per share
+in accordance with Financial Standard No. 128, "Earnings per Share (EPS)"
+("FAS 128"). Under FAS 128, basic EPS, which excludes dilution, is computed
+by dividing income or loss available to common shareholders by the weighted
+average number of common shares outstanding for the period. Unvested
+restricted stock is excluded from the calculation of weighted average
+common shares for basic EPS. Net income or loss available to common
+shareholders represents reported net income or loss less accretion of
+redeemable convertible preferred stock and allocation of preferred
+earnings. Diluted EPS reflects the potential dilution that could occur if
+securities or other contracts to issue common stock were exercised or
+converted into common stock. Diluted EPS includes restricted stock,
+in-the-money options and warrants using the treasury stock method, and also
+includes the assumed conversion of preferred stock using the if-converted
+method, but only if dilutive. During a loss period, the assumed exercise of
+in-the-money stock options and warrants and the conversion of convertible
+preferred stock has an anti-dilutive effect, and therefore, these
+instruments are excluded from the computation of dilutive EPS. See Note 16
+for EPS calculation.
+Beginning in the second quarter of 2004, the Company applied the
+consensus set forth in EITF 03-06 "Participating Securities and the
+Two-Class Method under FASB Statement No. 128, Earnings Per Share", which
+requires the two-class method of computing earnings per share when
+participating securities, such as our redeemable preferred stock, are
+outstanding. The two-class method is an earnings allocation formula that
+determines earnings per share for common stock and participating securities
+based upon an allocation of earnings as if all of the earnings for the
+period had been distributed in accordance with participation rights on
+undistributed earnings. EITF 03-6 became effective for reporting periods
+beginning after March 31, 2004. The application of EITF 03-06 only impacted
+the calculation of earnings per share for the year ended December 31, 2004
+due to no preferred stock outstanding in 2006 and 2005.
+38
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+3. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
+ACCOUNTING FOR INCOME TAX UNCERTAINTIES: In July 2006, the FASB issued
+FASB Interpretation 48, "Accounting for Income Tax Uncertainties" ("FIN
+48"). FIN 48 defines the threshold for recognizing the benefits of tax
+return positions in the financial statements as "more-likely-than-not" to
+be sustained by the taxing authority. The recently issued literature also
+provides guidance on the derecognition, measurement and classification of
+income tax uncertainties, along with any related interest and penalties.
+FIN 48 also includes guidance concerning accounting for income tax
+uncertainties in interim periods and increases the level of disclosures
+associated with any recorded income tax uncertainties. FIN 48 is effective
+for fiscal years beginning after December 15, 2006. The differences between
+the amounts recognized in the statements of financial position prior to the
+adoption of FIN 48 and the amounts reported after adoption will be
+accounted for as a cumulative-effect adjustment recorded to the beginning
+balance of retained earnings. In July 2006, the FASB issued FIN 48,
+Accounting for Uncertainty in Income Taxes, which will be effective the
+first quarter of 2007. Based on the "more-likely-than-not" standard under
+FIN 48, we expect that this guidance may impact the Company's recognition
+of tax benefits related to uncertain tax positions. However, the Company
+has not yet finalized its assessment of FIN 48.
+EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING CURRENT YEAR
+MISSTATEMENTS: In September 2006, the Securities and Exchange Commission
+issued Staff Accounting Bulletin ("SAB") No. 108, "Considering the Effects
+of Prior Year Misstatements when Quantifying Current Year Misstatements".
+SAB No. 108 requires analysis of misstatements using both an income
+statement (rollover) approach and balance sheet (iron curtain) approach in
+assessing materiality and provides for a one-time cumulative effect
+transition adjustment. SAB No. 108 is effective for our fiscal year 2006
+annual financial statements. The adoption of this guidance did not have a
+material impact on our financial position, results of operations or cash
+flows.
+FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued Statement
+of Financial Accounting Standards No. 157, "Fair Value Measurements" ("FASB
+157") which is effective for fiscal years beginning after November 15, 2007
+and for interim periods within those years. This statement defines fair
+value, establishes a framework for measuring fair value and expands the
+related disclosure requirements. Because the guidance was recently issued,
+management has not yet determined the impact, if any, of adopting the
+provisions of FASB 157 on the Company's financial position and results of
+operations.
+4. INVENTORIES
+The components of inventories are:
+December 31,
+---------------
+(In thousands) 2006 2005
+------ ------
+Raw materials and purchased component parts $7,337 $5,788
+Finished goods 230 248
+------ ------
+$7,567 $6,036
+====== ======
+5. FIXED ASSETS
+The components of fixed assets are:
+December 31,
+-------------------
+(In thousands) 2006 2005
+-------- --------
+Tooling, machinery and equipment $ 12,407 $ 13,748
+Furniture and office equipment 1,560 1,553
+Computer software and equipment 4,985 3,515
+Leasehold improvements 1,051 949
+-------- --------
+20,003 19,765
+Less: accumulated depreciation and amortization (14,065) (15,255)
+-------- --------
+$ 5,938 $ 4,510
+======== ========
+39
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+6. INTANGIBLE ASSETS
+On June 30, 2005, we acquired certain intangible assets related to
+casino ticket printer designs and technology from Bally Gaming, Inc.
+("Bally") for $475,000, plus the costs of effecting the acquisition
+(approximately $35,000). Prior to the acquisition, pursuant to the terms of
+a license agreement, we were required to pay Bally a royalty on sales of
+certain gaming printers utilizing the licensed technology. As a result of
+the acquisition, effective July 1, 2005, we were no longer required to pay
+any future royalties to Bally.
+The purchase price was allocated, based on management's estimates, to
+intangible assets based on their relative fair value at the date of
+acquisition. The fair value of the intangibles, comprised of purchased
+technology and a covenant not to compete, was determined using the future
+discounted cash flows method. The intangible assets are being amortized on
+a straight-line basis over six and seven years, respectively, for the
+estimated life of the assets.
+The following summarizes the allocation of the purchase price for the
+acquisition of certain intangible assets from Bally (in thousands):
+Purchased technology $364
+Covenant not to compete 146
+----
+Consideration paid $510
+====
+Amortization expense associated with the technology purchased from
+Bally was $81,000 and $41,000 for 2006 and 2005, respectively. Amortization
+expense for each of the next five years ending December 31 is expected to
+be as follows: $81,000 in each of 2007 through 2010; and $51,000 in 2011.
+7. ACCRUED LIABILITIES
+The components of accrued liabilities (current portion) are:
+December 31,
+---------------
+(In thousands) 2006 2005
+------ ------
+Payroll and fringe benefits $1,671 $1,219
+Income taxes 710 679
+Warranty - current portion 443 499
+Rent and occupancy 251 200
+Professional and consulting 364 80
+Other 608 521
+------ ------
+$4,047 $3,198
+====== ======
+8. ACCRUED BUSINESS CONSOLIDATION AND RESTRUCTURING EXPENSES
+In February 2001, we announced plans to establish a global engineering
+and manufacturing center at our Ithaca, NY facility. As part of this
+strategic decision, we undertook a plan to consolidate all manufacturing
+and engineering into our existing Ithaca, NY facility and close our
+Wallingford, CT manufacturing facility (the "Consolidation"). As of
+December 31, 2001, substantially all Wallingford product lines were
+successfully transferred to Ithaca, NY. We currently maintain our corporate
+headquarters and a service center in Wallingford. The closing of the
+Wallingford manufacturing facility resulted in the termination of
+employment of approximately 70 production, administrative and management
+employees. We continue to apply the consensus set forth in EITF 94-3,
+"Liability Recognition for Certain Employee Termination Benefits and Other
+Costs to Exit an Activity (Including Certain Costs Incurred in a
+Restructuring)" in recognizing the accrued restructuring expenses.
+During 2001 through 2003, we recorded expenses of approximately
+$6,182,000 related to costs associated with the Consolidation, including
+severance pay, stay bonuses, employee benefits, moving expenses,
+non-cancelable lease payments, accelerated depreciation and other costs.
+40
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+8. ACCRUED BUSINESS CONSOLIDATION AND RESTRUCTURING EXPENSES (CONTINUED)
+In December 2004, we determined that certain functions would be
+relocated and/or expanded in our Wallingford, CT corporate offices. In
+order to achieve the benefit of these changes, we expanded our use of space
+in our current facility. Because of this increase in use of space in the
+Wallingford facility, and because we had experienced lower than expected
+operating and maintenance costs than previously estimated, during 2004 we
+reversed $225,000 of previously accrued amounts provided for the remaining
+non-cancelable lease payments and related costs.
+In November 2006, we executed an agreement effective May 1, 2007 to
+terminate the lease agreement for our Wallingford, CT facility (the
+"Release Agreement"). Prior to the execution of the Release Agreement, we
+accrued for the remaining non-cancelable lease payments and other related
+costs for the unused portion of this facility through the expiration date
+of the lease (March 31, 2008). As a result of the Release Agreement and the
+early termination of the lease, we were released from the legal obligation
+for lease payments after May 1, 2007 and, accordingly, we were released
+from the legal obligation for lease payments after May 1, 2007 and,
+accordingly, we reversed approximately $479,000 of previously accrued
+restructuring reserve in the fourth quarter of 2006. As of December 31,
+2006, our restructuring accrual was $315,000, which represents the
+estimated remaining non-cancelable lease payments and other related costs
+for the unused portion of this facility through the new termination date of
+the lease (May 1, 2007).
+The following table summarizes the activity recorded in the
+restructuring accrual:
+Year ended December 31,
+------------------------
+(In thousands) 2006 2005 2004
+------ ------ ------
+Accrual balance, beginning of year $1,193 $1,640 $2,311
+------ ------ ------
+Business consolidation and
+restructuring expenses:
+Reversal of lease obligation related
+to unused space (479) -- (225)
+------ ------ ------
+(479) -- (225)
+------ ------ ------
+Cash payments (399) (447) (446)
+------ ------ ------
+Accrual balance, end of year $ 315 $1,193 $1,640
+====== ====== ======
+At December 31, 2006 and 2005, $0 and $773,000, respectively, of the
+restructuring accrual was classified as part of long-term liabilities. The
+long-term portion represents the portion of non-cancelable lease
+termination costs and other costs expected to be paid beyond one year.
+9. RETIREMENT SAVINGS PLAN
+On April 1, 1997, we established the TransAct Technologies Retirement
+Savings Plan (the "401(k) Plan"), a defined contribution plan under Section
+401(k) of the Internal Revenue Code. All full-time employees are eligible
+to participate in the 401(k) Plan at the beginning of the calendar quarter
+immediately following their date of hire. We match employees' contributions
+at a rate of 50% of employees' contributions up to the first 6% of the
+employees' compensation contributed to the 401(k) Plan. Our matching
+contributions were $249,000, $225,000 and $201,000 in 2006, 2005 and 2004,
+respectively.
+41
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+10. BORROWINGS
+On November 28, 2006, we signed a new, five-year $20 million credit
+facility (the "New TD Banknorth Credit Facility") with TD Banknorth, N.A.
+("TD Banknorth"). The new credit facility provides for a $20 million
+revolving credit line expiring on November 28, 2011. The New TD Banknorth
+Credit facility replaces a previous $11.5 million credit facility also with
+TD Banknorth. Borrowings under the new revolving credit line bear a
+floating rate of interest at the prime rate minus one-percent and are
+secured by a lien on all of our assets. We also pay a fee of 0.25% on
+unused borrowings under the revolving credit line. Deferred financing costs
+relating to expenses incurred to complete the New TD Banknorth Credit
+Facility were $88,000 at December 31, 2006. The New TD Banknorth Credit
+Facility imposes certain quarterly financial covenants on us and restricts
+the payment of dividends on our common stock and the creation of other
+liens. We were in compliance with all financial covenants of the New TD
+Banknorth Credit Facility at December 31, 2006.
+As of December 31, 2006, we had no outstanding borrowings on the
+revolving credit line. Undrawn commitments under the New TD Banknorth
+Credit Facility were $20,000,000 at December 31, 2006.
+11. COMMITMENTS AND CONTINGENCIES
+In April 2005, we announced a complaint against FutureLogic, Inc.
+("FutureLogic") in Connecticut, which charges FutureLogic with
+disseminating false and misleading statements. We assert claims of
+defamation and certain other charges. In May 2005, FutureLogic filed a
+complaint against us in California, asserting false advertising,
+defamation, trade libel and certain other charges. We moved to dismiss
+FutureLogic's action in California, on the grounds that any claims raised
+in that action should have been brought as part of the case filed by us in
+Connecticut. In the alternative, we moved to stay the California action
+pending the resolution of jurisdictional motions in the Connecticut court.
+In January 2006, the California court filed an order granting our motion to
+stay the California proceeding pending the resolution of jurisdictional
+motions in the Connecticut case. Under the California court's order, should
+the Connecticut court find that it has jurisdiction over FutureLogic,
+FutureLogic's case will be transferred to the Connecticut court for
+consolidation with the action pending in that forum. In September 2006, the
+District of Connecticut dismissed our case because of a lack of
+jurisdiction. The decision was not on the merits of our claims, but on the
+jurisdiction of the court in which the suit was brought. The California
+District Court has been notified of this development. The action is
+currently in the pre-trial motion stage and, as of December 31, 2006, we
+are currently unable to estimate any potential liability or range of loss
+associated with this litigation. Accordingly, no amounts have been accrued
+in the financial statements related to this matter.
+At December 31, 2005, we were lessee on operating leases for equipment
+and real property. Rent expense was approximately $1,330,000, $1,294,000
+and $1,098,000 in 2006, 2005 and 2004, respectively. Minimum aggregate
+rental payments required under operating leases that have initial or
+remaining non-cancelable lease terms in excess of one year as of December
+31, 2006 are as follows: $978,000 in 2007; $877,000 in 2008; $867,000 in
+2009; $716,000 in 2010; $745,000 in 2011; and $1,440,000 thereafter. Such
+payments include those related to the lease of our Wallingford, CT
+manufacturing facility, a portion of which has been recognized within the
+restructuring accrual described in Note 8.
+12. PATENT LICENSE FEES
+During 2004, we signed a cross licensing agreement with Seiko Epson.
+Under the agreement, Seiko Epson received a license to three of our
+patents, and we received a license to eighteen of Seiko Epson's patents
+relating to printing applications for the point of sale and banking
+markets. In addition, we agreed to pay $900,000 as a royalty for the usage
+of certain Seiko Epson technology prior to January 1, 2003, which we paid
+in full by January 2005. Under the agreement, we continue to pay royalties
+on a quarterly basis related to the sales of licensed printers, which is
+reflected in cost of sales.
+42
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. STOCK INCENTIVE PLANS AND WARRANTS
+STOCK INCENTIVE PLANS. We currently have four primary stock incentive
+plans: the 1996 Stock Plan, which provides for the grant of awards to
+officers and other key employees of the Company; the 1996 Directors' Stock
+Plan, which provides for non-discretionary awards to non-employee
+directors; the 2001 Employee Stock Plan, which provides for the grant of
+awards to key employees of the Company and other non-employees who may
+provide services to the Company; and the 2005 Equity Incentive Plan, which
+provides for awards to executives, key employees, directors and
+consultants. The plans generally provide for awards in the form of: (i)
+incentive stock options, (ii) non-qualified stock options, (iii) restricted
+stock, (iv) restricted stock units, (v) stock appreciation rights or (vi)
+limited stock appreciation rights. However, the 2001 Employee Stock Plan
+does not provide for incentive stock option awards. Options granted under
+these plans have exercise prices equal to 100% of the fair market value of
+the common stock at the date of grant. Options granted have a ten-year term
+and generally vest over a three- to five-year period, unless automatically
+accelerated for certain defined events. Effective upon the approval of the
+2005 Equity Incentive Plan on May 25, 2005, no new awards will be made
+under the 1996 Stock Plan, the 1996 Directors' Stock Plan or the 2001
+Employee Stock Plan. At December 31, 2006, approximately 462,000 shares of
+common stock remained available for issuance under the 2005 Equity
+Incentive Plan.
+EMPLOYEE STOCK PURCHASE PLAN: In May 2000, our shareholders approved
+the Employee Stock Purchase Plan (the "ESPP"), under which 75,000 shares of
+our common stock were available for issuance to employees beginning June 1,
+2000. All full-time employees were eligible to participate in the ESPP at
+the beginning of each six-month period (the "Offering Period"), which began
+on June 1 and December 1. Eligible employees could elect to withhold up to
+5% of their salary to purchase shares of our common stock at a price equal
+to 85% of the fair market value of the stock on the first or last day of
+each Offering Period, whichever is lower. The ESPP was terminated on May
+31, 2005. We issued 2,690 and 3,706, shares of common stock under the ESPP
+during 2005 and 2004, respectively. At December 31, 2006, no shares
+remained available for issuance due to the termination of the ESPP.
+Under the assumptions indicated below, the weighted-average fair value
+of stock option grants for the year ended December 31, 2006 and 2004 was
+$5.91 and $20.64, respectively. No fair value or assumptions have been
+disclosed for the year ended December 31, 2005 as no stock option grants
+were made during this period. The table below indicates the key assumptions
+used in the option valuation calculations for options granted in the twelve
+months ended December 31, 2006 and 2004 and a discussion of our methodology
+for developing each of the assumptions used in the valuation model:
+Year ended December Year ended December
+31, 2006 31, 2004
+------------------- -------------------
+Expected option term 5.2 years 8.9 years
+Expected volatility 78.4% 81.5%
+Risk-free interest rate 4.5% 3.6%
+Dividend yield 0% 0%
+Expected Option Term - This is the weighted average period of time
+over which the options granted are expected to remain outstanding giving
+consideration to our historical exercise patterns. Options granted have a
+maximum term of ten years. An increase in the expected term will increase
+compensation expense.
+Expected Volatility - The stock volatility for each grant is measured
+using the weighted average of historical daily price changes of our common
+stock over the most recent period approximately equal to the expected
+option term of the grant. An increase in the expected volatility factor
+will increase compensation expense.
+Risk-Free Interest Rate - This is the U.S. Treasury rate in effect at
+the time of grant having a term approximately equal to the expected term of
+the option. An increase in the risk-free interest rate will increase
+compensation expense.
+Dividend Yield - We have not made any dividend payments on our common
+stock, and we have no plans to pay dividends in the foreseeable future. An
+increase in the dividend yield will decrease compensation expense.
+43
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+Prior to adopting the provisions of FAS 123R, we recorded estimated
+compensation expense for employee stock options based upon their intrinsic
+value on the date of grant pursuant to APB 25 and provided the required pro
+forma disclosures of FAS 123. Because we established the exercise price
+based on the fair market value of our common stock at the date of grant,
+the stock options had no intrinsic value upon grant, and therefore no
+expense was recorded prior to adopting FAS 123R. We recorded compensation
+expense for restricted stock at the fair value of the stock at the date of
+grant, recognized over the service period. Each accounting period, we
+reported the potential dilutive impact of stock options in our diluted
+earnings per common share using the treasury-stock method. Out-of-the-money
+stock options (i.e., the average stock price during the period was below
+the strike price of the stock option) were not included in diluted earnings
+per common share as their effect was anti-dilutive.
+For purposes of pro forma disclosures under FAS 123 for the years
+ended December 31, 2005 and 2004, the estimated fair value of the
+share-based awards was assumed to be amortized to expense over the stock
+option's vesting periods. The pro forma effects of recognizing estimated
+compensation expense under the fair value method on net income and net
+income per common share were as follows:
+Year ended Year ended
+December 31, December 31,
+2005 2004
+(In thousands, except per share data) ------------ ------------
+Net income available to common shareholders:
+Net income available to common shareholders, as reported $ 377 $5,236
+Add: Stock-based compensation expense included
+in reported net income, net of tax 315 205
+Deduct: Stock-based compensation expense determined
+under fair value based method for all awards, net
+of tax (1,294) (390)
+------- ------
+Pro forma net (loss) income available to common shareholders $ (602) $5,051
+======= ======
+Net (loss) income per common share:
+Basic:
+As reported $ 0.04 $ 0.55
+Pro forma $ (0.06) $ 0.53
+Diluted:
+As reported $ 0.04 $ 0.51
+Pro forma $ (0.06) $ 0.49
+The fair values used to reflect the pro forma effects of estimated
+share-based compensation expense on net income and earnings per common
+share for the years ended December 31, 2005 and 2004 were estimated at the
+date of grant using the Black-Scholes option-pricing model.
+44
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+After the adoption of FAS 123R, we recognized compensation expense
+associated with awards granted after January 1, 2006, and the unvested
+portion of previously granted restricted stock awards that were outstanding
+as of January 1, 2006, in our condensed consolidated statement of income
+for the year ended December 31, 2006. During 2006, we recognized
+compensation expense, net of reversal of expense related to forfeitures, of
+$111,000 for stock options and $470,000 for restricted stock, which was
+recorded in our consolidated statement of income. The income tax benefits
+from share-based payments recorded in the income statement totaled $204,000
+for 2006. No compensation expense related to stock options was recorded in
+2005 and $458,000 in compensation expense related to restricted stock was
+recorded in 2005. The following table illustrates the impact of the
+adoption of FAS 123R on reported amounts:
+Year ended December 31, 2006
+----------------------------
+Impact of
+As FAS 123R
+Reported Adoption
+-------- ---------
+Operating income $6,088 $ 111
+Income before income taxes 6,033 111
+Net income 3,916 72
+Net income per share:
+Basic $ 0.41 $0.01
+Diluted 0.40 0.01
+For the year ended December 31, 2006, the adoption of FAS 123R
+resulted in tax benefits from stock options exercised in the period being
+classified as financing activities in the 2006 statement of cash flows.
+Shares that are issued upon exercise of employee stock options are newly
+issued shares and not issued from treasury stock. Upon the adoption of FAS
+123R, we also reclassified the unamortized restricted stock compensation
+account of $1,837,000 against additional paid-in capital. This adjustment
+was applied using MPA and, accordingly, has not been reflected in the 2005
+financial statements.
+45
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+The 1996 Stock Plan, 1996 Directors' Stock Plan, 2001 Employee Stock
+Plan and 2005 Equity Incentive Plan option activity is summarized below:
+Year Ended December 31,
+---------------------------------------------------------------
+2006 2005 2004
+------------------- ------------------ --------------------
+Weighted Weighted Weighted
+Average Average Average
+Exercise Exercise Exercise
+Shares Price Shares Price Shares Price
+-------- -------- ------- -------- --------- --------
+Outstanding at beginning of
+period: 741,501 $ 6.10 813,664 $ 5.97 1,123,533 $ 4.50
+Granted 115,000 8.83 -- -- 52,750 26.81
+Exercised (136,157) 5.05 (71,064) 4.55 (321,947) 4.28
+Canceled (13,000) 10.62 (1,099) 3.93 (40,672) 5.74
+-------- ------ ------- ------ --------- ------
+Outstanding at end of period 707,344 $ 6.67 741,501 $ 6.10 813,664 $ 5.97
+======== ====== ======= ====== ========= ======
+Options exercisable at end of
+Period 602,344 $ 6.29 741,501 $ 6.10 458,382 $ 4.67
+======== ====== ======= ====== ========= ======
+Options Outstanding
+---------------------------------------- Options Exercisable
+Weighted- --------------------------
+Weighted- Average Weighted-
+Outstanding at Average Remaining Exercisable at Average
+December 31, Exercise Contractual December 31, Exercise
+Range of Exercise Prices 2006 Price Life 2006 Price
+------------------------ -------------- --------- ----------- -------------- ---------
+(In years)
+$ 2.00 - $ 5.00 423,469 $ 3.70 5.0 423,469 $ 3.70
+5.01 - 7.50 115,875 6.53 4.3 115,875 6.53
+7.51 - 10.00 118,750 8.74 8.2 13,750 8.09
+10.01 - 25.00 13,500 16.50 5.2 13,500 16.50
+25.01 - 35.00 35,750 31.66 7.2 35,750 31.66
+------- -------
+707,344 6.67 5.6 602,344 6.29
+======= =======
+At December 31, 2006, outstanding stock options at the end of the year
+had an intrinsic value of $2,180,000. At December 31, 2006, outstanding
+stock options that are vested or expected to vest were 658,603 at a
+weighted average exercise price of $6.67. In addition, outstanding stock
+options that are vested or expected to vest had an intrinsic value of
+$2,042,000 with a weighted average remaining contractual life of 4.0 years.
+As of December 31, 2006, unrecognized compensation cost related to stock
+options totaled $509,000, which is expected to be recognized over a
+weighted average period of 4.1 years.
+At December 31, 2006, exercisable stock options had an intrinsic value
+of $2,159,000 with a weighted average remaining contractual life of 4.9
+years. In addition, exercisable stock options that are vested or expected
+to vest were 556,417 and had an intrinsic value of $2,022,000 at a
+weighted average exercise price of $6.29.
+The total intrinsic value of stock options exercised was $825,000 for
+the year ended December 31, 2006. No stock options vested during the year
+ended December 31, 2006.
+Cash received from stock option exercises for the year ended December
+31, 2006 was $687,000.
+46
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+13. STOCK INCENTIVE PLANS AND WARRANTS (CONTINUED)
+RESTRICTED STOCK: Under the 1996 Stock Plan, 2001 Employee Stock Plan
+and 2005 Equity Incentive Plan, we have granted shares of restricted common
+stock, for no consideration, to our officers, directors and certain key
+employees. Restricted stock activity for the 1996 Stock Plan, 2001 Employee
+Stock Plan and 2005 Equity Incentive Plan is summarized below:
+Weighted
+Average Grant
+Date Fair
+Values
+-------------
+Nonvested shares at December 31, 2005 $12.23
+Granted 13.78
+Vested 12.78
+Canceled 12.64
+Nonvested shares at December 31, 2006 12.22
+Year Ended December 31,
+---------------------------
+2006 2005 2004
+------- ------- -------
+Nonvested shares at beginning of period 187,550 79,500 16,999
+Granted 15,000 125,400 81,000
+Vested (36,684) (17,100) (15,499)
+Canceled (11,750) (250) (3,000)
+------- ------- -------
+Nonvested shares at end of period 154,116 187,550 79,500
+======= ======= =======
+As of December 31, 2006, unrecognized compensation cost related to
+restricted stock totaled $1,426,000, which is expected to be recognized
+over a weighted average period of 3.1 years. The total intrinsic value of
+restricted stock that vested during the twelve months ended December 31,
+2006 was $338,000.
+14. STOCKHOLDER RIGHTS PLAN
+In December 1997, our Board of Directors adopted a Stockholder Rights
+Plan declaring a distribution of one right (the "Rights") for each
+outstanding share of our common stock to shareholders of record at December
+15, 1997. Initially, each of the Rights will entitle the registered holder
+to purchase from the Company one one-thousandth of a share of Series A
+Preferred Stock, $0.01 par value, at a price of $69 per one one-thousandth
+of a share. The Rights, however, will not become exercisable unless and
+until, among other things, any person or group of affiliated persons
+acquires beneficial ownership of 15 percent or more of the then outstanding
+shares of the Company's Common Stock. If a person, or group of persons,
+acquires 15 percent or more of the outstanding Common Stock of the Company
+(subject to certain conditions and exceptions more fully described in the
+Rights Agreement), each Right will entitle the holder (other than the
+person, or group of persons, who acquired 15 percent or more of the
+outstanding Common Stock) to purchase Preferred Stock of the Company having
+a market value equal to twice the exercise price of the Right. The Rights
+are redeemable, under certain circumstances, for $0.0001 per Right and will
+expire, unless earlier redeemed, on December 2, 2007.
+On February 16, 1999, we amended the Stockholder Rights Plan to remove
+the provision in the plan that stipulated that the plan may be modified or
+redeemed only by those members of the Board of Directors who are defined as
+continuing directors.
+47
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+15. INCOME TAXES
+The components of the income tax provision (benefit) are as follows:
+Year Ended December 31,
+-----------------------
+(In thousands) 2006 2005 2004
+------ ----- ------
+Current:
+Federal $ 952 $ 7 $2,077
+State 41 68 216
+Foreign 541 525 306
+------ ----- ------
+1,534 600 2,599
+------ ----- ------
+Deferred:
+Federal 552 (634) 363
+State 31 (14) 17
+Foreign -- -- --
+------ ----- ------
+583 (648) 380
+------ ----- ------
+Income tax provision (benefit) $2,117 $ (48) $2,979
+====== ===== ======
+At December 31, 2006, we have $1,599,000 of state net operating loss
+carryforwards that begin to expire in 2009, and no federal net operating
+loss carryforwards. We also have approximately $129,000 in federal research
+and development tax credit carryforwards that begin to expire in 2011 and
+foreign tax credit carryforwards of approximately $401,000 that begin to
+expire in 2011. We had foreign income before taxes of $1,813,000,
+$1,833,000 and $1,084,000 in 2006, 2005 and 2004, respectively.
+Deferred income taxes arise from temporary differences between the tax
+basis of assets and liabilities and their reported amounts in the financial
+statements. Our gross deferred tax assets and liabilities were comprised of
+the following:
+December 31,
+---------------
+(In thousands) 2006 2005
+------ ------
+Gross deferred tax assets:
+Net operating losses $ 47 $ 67
+Accrued restructuring expenses 116 418
+Capitalized research and development 574 790
+Inventory reserves 702 800
+Deferred revenue 100 165
+Warranty reserve 223 238
+Foreign tax and other credits 615 927
+Other liabilities and reserves 516 591
+------ ------
+2,893 3,996
+Valuation allowance (64) (207)
+------ ------
+Net deferred tax assets 2,829 3,789
+------ ------
+Gross deferred tax liabilities:
+Depreciation 12 401
+Other 108 96
+------ ------
+Net deferred tax liabilities 120 497
+------ ------
+Net deferred tax assets $2,709 $3,292
+====== ======
+48
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+15. INCOME TAXES (CONTINUED)
+During 2006 and 2005, we recorded a valuation allowance of $64,000 and
+$207,000 on a portion of our foreign tax credits, research and development
+credits and certain state net operating loss carryforwards. We have
+determined that it is more likely than not that the remaining net deferred
+tax assets will be realized, and no additional valuation allowance is
+considered necessary, as of December 31, 2006 and 2005.
+Differences between the U.S. statutory federal income tax rate and our
+effective income tax rate are analyzed below:
+Year Ended December 31,
+-----------------------
+2006 2005 2004
+---- ----- ----
+Federal statutory tax rate 34.0% 34.0% 34.0%
+State income taxes, net of federal income taxes 1.1 (9.1) 1.0
+Tax benefit from tax credits, net of valuation
+allowance (0.7) (17.5) (0.8)
+Foreign rate differential -- 9.4 (0.7)
+Valuation allowance and tax accruals 0.4 (41.7) --
+Permanent items 0.6 13.0 --
+Other (0.3) (2.7) 1.8
+---- ----- ----
+Effective tax rate 35.1% (14.6%) 35.3%
+==== ===== ====
+16. EARNINGS PER SHARE
+For the years ended December 31, 2006, 2005 and 2004, earnings per
+share were computed as follows (in thousands, except per share amounts):
+Year Ended December 31,
+--------------------------
+2006 2005 2004
+------ ------- -------
+Net income $3,916 $ 377 $ 5,458
+Dividends and accretion on preferred stock -- -- (111)
+Earnings allocation to preferred shareholders -- -- (111)
+------ ------- -------
+Net income available to common shareholders $3,916 $ 377 $ 5,236
+====== ======= =======
+Shares:
+Basic: Weighted average common shares outstanding 9,577 9,849 9,593
+Add: Dilutive effect of outstanding options and
+warrants as determined by the treasury stock method 293 314 638
+------ ------- -------
+Diluted: Weighted average common and common
+equivalent shares outstanding
+9,870 10,163 10,231
+====== ======= =======
+Net income per common share:
+Basic $ 0.41 $ 0.04 $ 0.55
+Diluted 0.40 0.04 0.51
+For the years ended December 31, 2006 and 2005, potentially dilutive
+shares that were excluded from the earnings per share calculation,
+consisting of out-of-the-money stock options and warrants, were 101,750 and
+52,250 shares, respectively.
+49
+TRANSACT TECHNOLOGIES INCORPORATED
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
+17. PREFERRED STOCK
+On April 7, 2000 we sold 4,000 shares of 7% Series B Cumulative
+Convertible Redeemable Preferred Stock (the "Preferred Stock") in
+consideration of $1,000 per share (the "Stated Value"), for a total of
+$4,000,000, less issuance costs. The holders of the Preferred Stock were
+entitled to receive a cumulative annual dividend of $70 per share, payable
+quarterly and had preference to any other dividends, if any, paid by the
+Company. In April 2004, all shareholders of our Series B Preferred Stock
+converted all their preferred shares into common stock. Pursuant to the
+conversion, a total of 666,665 new shares of common stock were issued. We
+recorded the costs of registering and issuing these shares as a deduction
+to Additional Paid-In Capital.
+18. STOCK REPURCHASE PROGRAM
+On March 25, 2005, our Board of Directors approved a stock repurchase
+program ("the Stock Repurchase Program"). Under the Stock Repurchase
+Program, we are authorized to repurchase up to $10 million of our
+outstanding shares of common stock from time to time in the open market
+over a three-year period ending on March 25, 2008, depending on market
+conditions, share price and other factors. As of December 31, 2006, we
+repurchased a total of 801,300 shares of common stock for approximately
+$6,492,000 under this program, at an average price of $8.10 per share. We
+use the cost method to account for treasury stock purchases, under which
+the price paid for the stock is charged to the treasury stock account.
+19. INTERNATIONAL OPERATIONS
+We have foreign operations primarily from TransAct Technologies Ltd.,
+a wholly-owned subsidiary in the United Kingdom, which had sales to its
+customers of approximately $2,722,000, $2,181,000 and $1,000,000 in 2006,
+2005 and 2004, respectively. Tangible assets at foreign locations are not
+material. We had sales from the United States to our customers outside of
+the United States of approximately $11,416,000, $10,137,000 and $5,423,000
+in 2006, 2005 and 2004, respectively. International sales do not include
+sales of printers made to domestic distributors or other domestic customers
+who in turn may ship those printers to international destinations.
+20. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
+Our quarterly results of operations for 2006 and 2005 are as follows:
+Quarter Ended
+-----------------------------------------------
+(In thousands, except per share amounts) March 31 June 30 September 30 December 31
+-------- ------- ------------ -----------
+2006:
+Net sales $16,434 $16,905 $15,276 $15,713
+Gross profit 5,687 5,746 5,438 5,494
+Net income 1,057 857 1,019 983
+Net income per share:
+Basic 0.11 0.09 0.11 0.10
+Diluted 0.11 0.09 0.10 0.10
+March 31 June 30 September 30 December 31
+-------- ------- ------------ -----------
+2005:
+Net sales $12,036 $12,346 $14,210 $12,499
+Gross profit 3,677 4,254 4,576 3,083
+Net income (loss) 163 267 674 (727)
+Net income (loss) per share:
+Basic 0.02 0.03 0.07 (0.08)
+Diluted 0.02 0.03 0.07 (0.08)
+50
+TRANSACT TECHNOLOGIES INCORPORATED
+Schedule II
+Valuation and Qualifying Accounts
+(Amounts in thousands)
+Balance at Balance at
+Beginning of Write-offs, net End of
+Description Period Provision of recoveries Period
+----------- ------------ --------- --------------- ----------
+Valuation account for accounts receivable:
+Year ended December 31, 2006 $ 240 $ -- $ (36) $ 204
+Year ended December 31, 2005 $ 175 $ 68 $ (3) $ 240
+Year ended December 31, 2004 $ 100 $ 73 $ 2 $ 175
+Valuation account for inventories:
+Year ended December 31, 2006 $2,165 $266 $(531) $1,900
+Year ended December 31, 2005 $2,010 $995 $(840) $2,165
+Year ended December 31, 2004 $1,950 $148 $ (88) $2,010
+51
+ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
+FINANCIAL DISCLOSURE.
+None.
+ITEM 9A. CONTROLS AND PROCEDURES
+Attached as exhibits to this Form 10-K are certifications of our Chief
+Executive Officer (CEO) and Chief Financial Officer (CFO), which are required in
+accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended
+(the Exchange Act). This "Controls and Procedures" section includes information
+concerning the controls and controls evaluation referred to in the
+certifications. Part II, Item 8 of this Form 10-K sets forth the report of
+PricewaterhouseCoopers LLP, our independent registered public accounting firm,
+regarding its audit of TransAct's internal control over financial reporting as
+of December 31, 2006 and of management's assessment of internal control over
+financial reporting as of December 31, 2006 set forth below in this section.
+This section should be read in conjunction with the CEO and CFO certifications
+and the PricewaterhouseCoopers LLP report for a more complete understanding of
+the topics presented.
+EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
+We conducted an evaluation of the effectiveness of the design and operation
+of our "disclosure controls and procedures" ("Disclosure Controls") for the
+period covered by this Form 10-K. The controls evaluation was conducted under
+the supervision and with the participation of management, including our CEO and
+CFO. Disclosure Controls are controls and procedures designed to reasonably
+assure that information required to be disclosed in our reports filed under the
+Exchange Act, such as this Form 10-K, is recorded, processed, summarized and
+reported within the time periods specified in the U.S. Securities and Exchange
+Commission's (SEC's) rules and forms. Disclosure Controls are also designed to
+reasonably assure that such information is accumulated and communicated to our
+management, including the CEO and CFO, as appropriate to allow timely decisions
+regarding required disclosure. Our quarterly evaluation of Disclosure Controls
+includes an evaluation of some components of our internal control over financial
+reporting, and internal control over financial reporting is also separately
+evaluated on an annual basis for purposes of providing the management report
+which is set forth below.
+The evaluation of our Disclosure Controls included a review of the
+controls' objectives and design, the company's implementation of the controls
+and the effect of the controls on the information generated for use in this Form
+10-K. In the course of the controls evaluation, we review data errors, control
+problems or acts of fraud, if any, and seek to confirm that appropriate
+corrective actions, including process improvements, are being undertaken. This
+type of evaluation is performed on a quarterly basis so that the conclusions of
+management, including the CEO and CFO, concerning the effectiveness of the
+Disclosure Controls can be reported in our periodic reports on Form 10-Q and
+Form 10-K. Many of the components of our Disclosure Controls are also evaluated
+on an ongoing basis by personnel in our finance organization. The overall goals
+of these various evaluation activities are to monitor our Disclosure Controls,
+and to modify them as necessary. Our intent is to maintain the Disclosure
+Controls as dynamic systems that change as conditions warrant.
+Based upon the evaluation of the controls, our CEO and CFO have concluded
+that, as of the end of the period covered by this Form 10-K, our Disclosure
+Controls were effective to provide reasonable assurance that information
+required to be disclosed in our Exchange Act reports is recorded, processed,
+summarized and reported within the time periods specified by the SEC, and that
+material information relating to TransAct and our consolidated subsidiaries is
+made known to management, including the CEO and CFO, particularly during the
+period when our periodic reports are being prepared.
+CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
+The implementation of our new accounting system, completed effective
+January 8, 2007, required us to modify and add certain internal controls and
+processes and procedures. Otherwise, no change in our internal control over
+financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the
+Exchange Act) occurred during the three months ended December 31, 2006 that has
+materially affected, or is reasonably likely to materially affect, our internal
+control over financial reporting.
+MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
+Our management is responsible for establishing and maintaining adequate
+internal control over financial reporting to provide reasonable assurance
+regarding the reliability of our financial reporting and the preparation of
+financial statements for external purposes in accordance with generally accepted
+accounting principles. 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.
+52
+Management assessed our internal control over financial reporting as of
+December 31, 2006. Management based its assessment on criteria established in
+Internal Control-Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission (COSO).
+Based on our assessment, management has concluded that our internal control
+over financial reporting was effective as of December 31, 2006 based on the COSO
+criteria identified above, to provide reasonable assurance regarding the
+reliability of financial reporting and the preparation of financial statements
+for external reporting purposes in accordance with generally accepted accounting
+principles.
+Our management's assessment of the effectiveness of the Company's internal
+control over financial reporting as of December 31, 2006 has been audited by
+PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
+stated in their report which appears herein.
+INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS
+A control system, no matter how well designed and operated, can provide
+only reasonable, not absolute, assurance that the control system's objectives
+will be met. 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. Further, because of the inherent limitations in all control
+systems, no evaluation of controls can provide absolute assurance that
+misstatements due to error or fraud will not occur or that all control issues
+and instances of fraud, if any, within the 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
+errors or mistakes. Controls can also be circumvented by the individual acts of
+some persons, by collusion of two or more people, or by management override of
+the controls. The design of any system of controls is based in part on 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. Projections of any evaluation of controls effectiveness to
+future periods are subject to risks. Over time, controls may become inadequate
+because of changes in conditions or deterioration in the degree of compliance
+with policies or procedures.
+PART III
+ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
+The information in response to this item is incorporated by reference from
+the Proxy Statement sections entitled "Election of Directors" and "Executive
+Officers."
+ITEM 11. EXECUTIVE COMPENSATION
+The information in response to this item is incorporated by reference from
+the Proxy Statement sections entitled "Executive Compensation and Certain
+Transactions" and "Compensation Discussion and Analysis."
+ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
+RELATED STOCKHOLDER MATTERS
+The information contained in "Security Ownership of Certain Beneficial
+Owners and Management" of the Proxy Statement is hereby incorporated herein by
+reference.
+53
+Information regarding our equity compensation plans as of December 31, 2006
+is as follows:
+(c)
+Number of securities
+remaining available
+(a) (b) for future issuance
+Number of securities Weighted average under equity
+to be issued upon exercise price of compensation plans
+exercise of outstanding (excluding securities
+outstanding options, options, warrants reflected in column
+Plan category warrants and rights and rights (a))
+------------- -------------------- ----------------- ---------------------
+Equity compensation plans approved by
+security holders:
+1996 Stock Plan 472,278 $ 2.95 --
+1996 Non-Employee Director Plan 176,250 10.91 --
+2005 Equity Incentive Plan 135,000 6.86 462,000
+------- ------ -------
+Total 783,528 $ 5.42 462,000
+------- ------ -------
+Equity compensation plans not approved
+by security holders:
+2001 Employee Stock Plan 77,932 $ 6.03 --
+------- ------ -------
+861,460 $ 5.47 462,000
+======= ====== =======
+The TransAct Technologies Incorporated 2001 Employee Stock Plan (the "2001
+Employee Plan") was adopted by our Board of Directors, without approval of our
+security holders, effective February 26, 2001. Under the 2001 Employee Plan, we
+may issue non-qualified stock options, shares of restricted stock, restricted
+units to acquire shares of common stock, stock appreciation rights and limited
+stock appreciation rights to key employees of TransAct or any of our
+subsidiaries and to non-employees who provide services to TransAct or any of our
+subsidiaries. The 2001 Employee Plan is administered by our Compensation
+Committee, which has the authority to determine the vesting period and other
+similar restrictions and terms of awards, provided that the exercise price of
+options granted under the plan may not be less than the fair market value of the
+underlying shares on the date of grant.
+In May 2005, our shareholders approved the adoption of the 2005 Equity
+Incentive Plan. No new awards will be available for future issuance under any
+existing TransAct equity plan other than the 2005 Equity Incentive Plan.
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
+ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
+The information contained in "Independent Registered Public Accounting
+Firm's Fees" of the Proxy Statement is herby incorporated herein by reference.
+54
+PART IV
+ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
+THE FOLLOWING FINANCIAL STATEMENTS AND EXHIBITS ARE FILED AS PART OF THIS
+REPORT:
+(i) Financial statements
+See Item 8.
+(ii) Financial statement schedules
+All other schedules are omitted since the required information is
+either (a) not present or not present in amounts sufficient to require
+submission of the schedule or (b) included in the financial statements
+or notes thereto.
+(iii) List of exhibits
+3.1(a) Certificate of Incorporation of TransAct Technologies Incorporated ("TransAct" or the (2)
+"Company"), filed with the Secretary of State of Delaware on June 17, 1996.
+3.1(b) Certificate of Amendment of Certificate of Incorporation of the Company, filed with (4)
+the Secretary of State of Delaware on June 4, 1997.
+3.1(c) Certificate of Designation, Series A Preferred Stock, filed with the Secretary of (5)
+State of Delaware on December 2, 1997.
+3.1(d) Certificate of Designation, Series B Preferred Stock, filed with the Secretary of (8)
+State of Delaware on April 6, 2000.
+3.2 Amended and Restated By-laws of the Company. (6)
+4.1 Specimen Common Stock Certificate. (2)
+4.2 Amended and Restated Rights Agreement between TransAct and American Stock Transfer & (5)
+Trust Company dated February 16, 1998.
+10.1(x) 1996 Stock Plan, effective July 30, 1996. (3)
+10.2(x) Non-Employee Directors' Stock Plan, effective August 22, 1996. (3)
+10.3(x) 2001 Employee Stock Plan. (9)
+10.4(x) 2005 Equity Incentive Plan (14)
+10.5(x) Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. (2)
+Shuldman.
+10.6(x) Severance Agreement by and between TransAct and Michael S. Kumpf, dated September 4, (3)
+1996.
+10.7(x) Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, (13)
+2004.
+10.8 Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, (2)
+1992.
+10.9 Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated (4)
+December 2, 1996.
+10.10 Agreement regarding the Continuation and Renewal of Lease by and between Bomax (11)
+Properties, LLC and TransAct, dated July 18, 2001.
+10.11 Lease Agreement by and between Pyramid Construction Company and Magnetec, dated July (4)
+30, 1997.
+10.12 Lease Addendum by and between Wallingford Warehouse LLC (successor in interest to (1)
+Pyramid Construction Company) and TransAct dated November 28, 2006.
+10.13 Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated (13)
+December 2, 2004.
+55
+10.14 Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated (1)
+November 27, 2006.
+10.15 OEM Purchase Agreement by and between GTECH Corporation, TransAct and Magnetec (7)
+Corporation commencing July 14, 1999. (Pursuant to Rule 24-b-2 under the Exchange Act,
+the Company has requested confidential treatment of portions of this exhibit deleted
+from the filed copy.)
+10.16 OEM Purchase Agreement by and between GTECH Corporation and TransAct commencing July (10)
+2, 2002. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested
+confidential treatment of portions of this exhibit deleted from the filed copy.)
+10.17 Amendment to OEM Purchase Agreement by and between GTECH Corporation and TransAct, (15)
+dated February 17, 2006. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company
+has requested confidential treatment of portions of this exhibit deleted from the
+filed copy.)
+10.18 Amended and Restated Revolving Credit and Security Agreement between TransAct and TD (1)
+Banknorth, N.A. dated November 28, 2006
+10.19 License Agreement between Seiko Epson Corporation and TransAct dated May 17, 2004 (12)
+(Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested confidential
+treatment of portions of this exhibit deleted from the filed copy.)
+23.1 Consent of PricewaterhouseCoopers LLP. (1)
+31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley (1)
+Act of 2002
+31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley (1)
+Act of 2002
+32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted (1)
+pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
+32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted (1)
+pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
+56
+(1) These exhibits are filed herewith.
+(2) These exhibits, which were previously filed with the Company's Registration
+Statement on Form S-1 (No. 333-06895), are incorporated by reference.
+(3) These exhibits, which were previously filed with the Company's Quarterly
+Report on Form 10-Q for the period ended September 30, 1996 (Commission
+File No. 000-21121), are incorporated by reference.
+(4) These exhibits, which were previously filed with the Company's Annual
+Report on Form 10-K for the year ended December 31, 1997 (Commission File
+No. 000-21121), are incorporated by reference.
+(5) These exhibits, which were previously filed with the Company's Current
+Report on Form 8-K filed February 18, 1999 (Commission File No. 000-21121),
+are incorporated by reference.
+(6) This exhibit, which was previously filed with the Company's Annual Report
+on Form 10-K for the year ended December 31, 1998 (Commission File No.
+000-21121), is incorporated by reference.
+(7) This exhibit, which was previously filed with the Company's Quarterly
+Report on Form 10-Q for the period ended September 25, 1999 (Commission
+File No. 000-21121), is incorporated by reference.
+(8) These exhibits, which were previously filed with the Company's Quarterly
+Report on Form 10-Q for the period ended March 25, 2000, are incorporated
+by reference.
+(9) This exhibit, which was previously filed with the Company's Registration
+Statement on Form S-8 (No. 333-59570), is incorporated by reference.
+(10) This exhibit, which was previously filed with the Company's Quarterly
+Report on Form 10-Q for the period ended June 30, 2002, is incorporated by
+reference.
+(11) This exhibit, which was previously filed with the Company's Quarterly
+Report on Form 10-Q for the period ended June 30, 2003, is incorporated by
+reference.
+(12) This exhibit, which was previously filed with the Company's Quarterly
+Report on Form 10-Q for the period ended June 30, 2004, is incorporated by
+reference.
+(13) These exhibits, which were previously filed with the Company's Annual
+Report on Form 10-K for the year ended December 31, 2004, are incorporated
+by reference.
+(14) This exhibit, which was previously filed with the Company's Current Report
+on Form 8-K filed June 1, 2005 (Commission File No. 000-21121), is
+incorporated by reference.
+(15) These exhibits, which were previously filed with the Company's Annual
+Report on Form 10-K for the year ended December 31, 2005, are incorporated
+by reference.
+(x) Management contract or compensatory plan or arrangement required to be
+filed pursuant to Item 14(c).
+57
+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.
+TRANSACT TECHNOLOGIES INCORPORATED
+By: /s/ Bart C. Shuldman
+------------------------------------
+Name: Bart C. Shuldman
+Title: Chairman of the Board, President
+and Chief Executive Officer
+Date: March 15, 2007
+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/ Bart C. Shuldman Chairman of the Board, President and March 15, 2007
+------------------------------------- Chief Executive Officer
+Bart C. Shuldman (Principal Executive Officer)
+/s/ Steven A. DeMartino Executive Vice President, Chief Financial March 15, 2007
+------------------------------------- Officer, Treasurer and Secretary
+Steven A. DeMartino (Principal Financial and Accounting Officer)
+/s/ Charles A. Dill Director March 15, 2007
+-------------------------------------
+Charles A. Dill
+/s/ Thomas R. Schwarz Director March 15, 2007
+-------------------------------------
+Thomas R. Schwarz
+/s/ Graham Y. Tanaka Director March 15, 2007
+-------------------------------------
+Graham Y. Tanaka
+58
+EXHIBIT LIST
+The following exhibits are filed herewith.
+Exhibit
+-------
+10.12 Lease Addendum by and between Wallingford Warehouse LLC (successor in
+interest to Pyramid Construction Company) and TransAct dated November
+28, 2006.
+10.14 Lease Agreement by and between 2319 Hamden Center I, L.L.C. and
+TransAct dated November 27, 2006.
+10.18 Amended and Restated Revolving Credit and Security Agreement between
+TransAct and TD Banknorth, N.A. dated November 28, 2006
+23.1 Consent of PricewaterhouseCoopers LLP
+31.1 Certification of Chief Executive Officer pursuant to Section 302 of
+the Sarbanes-Oxley Act of 2002
+31.2 Certification of Chief Financial Officer pursuant to Section 302 of
+the Sarbanes-Oxley Act of 2002
+32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section
+1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
+2002
+32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section
+1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
+2002
+59
\ No newline at end of file
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new file mode 100644
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diff --git a/raw/filings/0001017303/2006/0000950123-07-003917/item1.txt b/raw/filings/0001017303/2006/0000950123-07-003917/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8880469ac4854d52ece1a88a1862b20eb0b93713
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@@ -0,0 +1,314 @@
+ITEM 1. BUSINESS.
+THE COMPANY
+TransAct was incorporated in June 1996 and began operating as a stand-alone
+business in August 1996 as a spin-off of the printer business that was formerly
+conducted by certain subsidiaries of Tridex Corporation. We completed an initial
+public offering on August 22, 1996.
+TransAct Technologies Incorporated ("TransAct" or the "Company") designs,
+develops, assembles, markets and services world-class transaction printers under
+the Epic(TM) and Ithaca(R) brand names. Known and respected worldwide for
+innovative designs and real-world service reliability, our impact, thermal and
+inkjet printers generate top-quality transaction records such as receipts,
+tickets, coupons, register journals and other documents. We focus on two core
+markets: (1) point-of-sale ("POS") and banking and (2) gaming and lottery. We
+sell our products to original equipment manufacturers ("OEMs"), value-added
+resellers ("VARs"), selected distributors, as well as directly to end-users. Our
+product distribution spans across the Americas, Europe, the Middle East, Africa,
+Asia, Australia, the Caribbean Islands and the South Pacific. In addition, we
+have a strong focus on the after-market side of the business, with a growing
+commitment to printer service, supplies and spare parts. We have one primary
+operating facility located in Ithaca, NY, five sales offices located in the
+United States (including our global gaming and lottery headquarters and western
+region service center in Las Vegas, NV), and a European sales and service center
+in the United Kingdom. Our executive offices and eastern region service center
+are located at 7 Laser Lane, Wallingford, CT 06492, with a telephone number of
+(203) 859-6800.
+FINANCIAL INFORMATION ABOUT SEGMENTS
+We have determined that we operate in one reportable segment, the design,
+development, assembly and marketing of transaction printers and printer-related
+service, supplies and spare parts.
+PRODUCTS AND SERVICES
+Printers
+TransAct designs, develops, assembles and markets a broad array of
+transaction-based printers utilizing inkjet, thermal and impact printing
+technology for applications requiring up to 60 character columns, primarily in
+the POS and banking, and gaming and lottery markets. Our printers are
+configurable and offer customers the ability to choose from a variety of
+features and functions. Options typically include interface configuration, paper
+cutting devices, paper handling capacities and cabinetry color. In addition to
+our configurable printers, we design and assemble custom printers for certain
+OEM customers. In collaboration with these customers, we provide engineering and
+manufacturing expertise for the design and development of specialized printers.
+POS and banking: Our POS and banking printers include hundreds of optional
+configurations that can be selected to meet particular customer needs. We
+believe that this is a significant competitive strength, as it allows us to
+satisfy a wide variety of printing applications that our customers request. In
+the POS market, we sell several models of printers utilizing inkjet, thermal and
+impact printing technology. Our printers are used primarily by retailers in the
+hospitality, restaurant (including fine dining, casual dining, and fast food)
+and specialty retail industries to print receipts for consumers, validate
+checks, or print on other inserted media. We also sell printers that are used by
+banks, credit unions and other financial institutions to print and/or validate
+receipts at bank teller stations.
+Gaming and lottery: In the lottery portion of our gaming and lottery
+market, we supply lottery printers to GTECH, our largest customer and the
+world's largest provider of lottery terminals, with an approximate 70% market
+share. These printers are designed for high-volume, high-speed printing of
+lottery tickets for various lottery applications.
+In the gaming portion of our gaming and lottery market, we sell several
+models of printers used in slot machines and video lottery terminals that print
+tickets instead of issuing coins at casinos, racetracks and other gaming
+establishments worldwide. These printers utilize thermal printing technology and
+can print tickets in monochrome or two-color (depending upon the model), and
+offer various other features such as jam resistant bezels and a dual port
+interface that will allow casinos to print coupons/promotions. In addition, we
+sell printers using thermal and impact printing technology for use in non-casino
+gaming establishments, including game types such as Amusements with Prizes
+("AWP"), Skills with Prizes ("SWP"), Video lottery terminals ("VLT"), Fixed Odds
+Betting Terminals ("FOBT") and other off-premise gaming type machines around the
+world.
+TransAct Services Group
+Through our TransAct Services Group, we proactively market the sale of
+consumable products (including inkjet cartridges, ribbons and receipt paper),
+replacement parts and maintenance services for all of our products. Our
+maintenance services include the sale of extended warranties, multi-year
+maintenance contracts, 24-hour guaranteed replacement product service TransAct
+Xpress(SM), and other repair services for our printers. Within the United
+States, we provide repair services
+3
+through our eastern region service center in Wallingford, CT and our western
+region service center in Las Vegas, NV. Internationally, we provide repair
+services through our European service center located in Doncaster, United
+Kingdom, and through partners strategically located around the world.
+We also provide customers with telephone sales and technical support, and a
+personal account representative to handle orders, shipping and general
+information. Technical and sales support personnel receive training on all of
+our manufactured products and our services.
+Product Warranty
+Our printers generally carry up to a two-year limited warranty against
+defects in material and workmanship. Defective equipment may be returned to any
+of our service centers, or our manufacturing facility in Ithaca, NY for
+newly-released printers only, for repair or replacement during the applicable
+warranty period.
+PRODUCTION, MANUFACTURING AND SOURCES AND AVAILABILITY OF RAW MATERIALS
+We design our products to optimize product performance, quality,
+reliability and durability. These designs combine cost efficient materials,
+sourcing and assembly methods with high standards of workmanship. We finalize
+assembly of our products in our Ithaca, NY facility largely on a
+configure-to-order basis using components that have been sourced from around the
+world. Our manufacturing engineers work closely with our new product engineers
+and vendors during the development of new products. As a result, this
+collaboration increases manufacturing efficiency by specifying materials and
+designing manufacturing processes in conjunction with new product design.
+We procure component parts and subassemblies for use in the manufacture and
+assembly of our products. Critical component parts and subassemblies include
+inkjet, thermal and impact printheads, printing/cutting mechanisms, power
+supplies, motors, injection molded plastic parts, circuit boards and electronic
+components, which are obtained from domestic and foreign suppliers at
+competitive prices. In addition, we have begun to procure fully assembled
+printers from a foreign supplier. We typically strive to maintain more than one
+source for our component parts, subassemblies and fully assembled printers to
+reduce the risk of parts shortages or unavailability. However, we could
+experience temporary disruption if certain suppliers ceased doing business with
+us, as described below.
+Okidata Americas, Inc. ("Okidata"), is the sole supplier for an impact
+printer component kit consisting of a printhead, control board and carriage (the
+"Oki Kit"), that is used in all of our Ithaca(R) brand impact printers. The loss
+of the supply of Oki Kits would have a material adverse effect on TransAct.
+However, sales of impact printers continue to decline as sales of these printers
+are replaced by sales of thermal and inkjet printers. As such, we believe that
+any possible loss of supply of Oki Kits will have less of an impact on TransAct
+in 2007 and beyond. Although we do not have a supply agreement with Okidata, our
+relationship with Okidata remains strong and we have no reason to believe that
+Okidata will discontinue its supply of Oki Kits to us or that their terms to us
+will be any less favorable than they have been historically.
+Hewlett-Packard Company ("HP") is the sole supplier of inkjet cartridges
+that are used in all of our inkjet printers. The loss of the supply of HP inkjet
+cartridges would have a material adverse effect on the sale of our inkjet
+printers. Prior to February 2006, we had a supply agreement with HP to purchase
+inkjet cartridges at fixed prices. This agreement expired on February 1, 2006
+and was not renewed, as HP informed us that they no longer maintain supply
+agreements for these inkjet cartridges; however, we continue to purchase inkjet
+cartridges from HP. Although we no longer have a supply agreement with HP, our
+relationship with HP remains strong and we have no reason to believe that HP
+will discontinue its supply of inkjet cartridges to us. The inkjet cartridges we
+purchase from HP are used not only in our inkjet printers for the POS and
+banking market, but also in other manufacturer's printing devices across several
+other markets.
+We currently buy substantially all of our thermal print mechanisms, an
+important component of our thermal printers, from one supplier. Although we
+believe that other suppliers could provide similar thermal print mechanisms on
+comparable terms, a change in suppliers could cause a delay in manufacturing and
+possible loss of sales which may have a material adverse effect on our operating
+results.
+4
+PATENTS AND PROPRIETARY INFORMATION
+We have significantly expanded our patent portfolio over the past six
+years, and expect to continue to do so in the future. We also believe our patent
+portfolio could provide additional opportunities to license our intellectual
+property in the future. We hold 21 United States and nine foreign patents and
+have nine United States and 19 foreign patent applications pending pertaining to
+our products. The duration of these patents range from 11 to 18 years. The
+expiration of any individual patent would not have a significant negative impact
+on our business. We regard certain manufacturing processes and designs to be
+proprietary and attempt to protect them through employee and third-party
+nondisclosure agreements and similar means. It may be possible for unauthorized
+third parties to copy certain portions of our products or to reverse engineer or
+otherwise obtain and use, to our detriment, information that we regard as
+proprietary. Moreover, the laws of some foreign countries do not afford the same
+protection to our proprietary rights as do United States laws. There can be no
+assurance that legal protections relied upon by the Company to protect our
+proprietary position will be adequate or that our competitors will not
+independently develop technologies that are substantially equivalent or superior
+to our technologies.
+During 2004, we signed a cross licensing agreement with Seiko Epson. Under
+the agreement, Seiko Epson received a license to three of our patents, and we
+received a license to eighteen of Seiko Epson's patents relating to printing
+applications for the point of sale and banking markets. In addition, we agreed
+to pay $900,000 as a royalty for the usage of certain Seiko Epson technology
+prior to January 1, 2003, which was paid in full by January 2005. Under the
+agreement, we continue to pay royalties on a quarterly basis related to the
+sales of licensed printers, which is reflected in cost of sales.
+SEASONALITY
+Retailers typically reduce purchases of new POS equipment in the fourth
+quarter, due to the increased volume of consumer transactions in that holiday
+period, and our sales of printers in the POS market historically have increased
+in the third quarter and decreased in the fourth quarter. Similarly,
+installations of lottery terminals are typically reduced in the fourth quarter,
+resulting in decreased sales of lottery printers.
+CERTAIN CUSTOMERS
+We currently have an ongoing OEM purchase agreement, as amended in February
+2006, (the "GTECH Thermal Printer Agreement") with GTECH Corporation ("GTECH")
+that provides for the sale of thermal on-line lottery printers and spare parts,
+at fixed prices, through June 28, 2012. Firm purchase orders for printers under
+the GTECH Thermal Printer Agreement may be placed as required by GTECH. Prior to
+this agreement, we had a purchase agreement with GTECH that provided for the
+sale of impact on-line lottery printers and spare parts through December 31,
+2004. Because our new thermal on-line lottery printer is a replacement for our
+impact on-line printer, we do not expect any further shipments of impact on-line
+lottery printers. However, we do expect to continue to sell spare parts to GTECH
+for the remaining installed base of impact on-line lottery printers, although we
+expect such sales to decline as the installed base of impact on-line lottery
+printers are replaced with our thermal printer.
+BACKLOG
+Our backlog of firm orders was approximately $4,300,000 as of February 28,
+2007, compared to $8,300,000 as of February 28, 2006. Based on customers'
+current delivery requirements, we expect to ship our entire current backlog
+during 2007.
+COMPETITION
+The market for transaction-based printers is extremely competitive, and we
+expect such competition to continue in the future. We compete with a number of
+companies, many of which have greater financial, technical and marketing
+resources than us. We believe our ability to compete successfully depends on a
+number of factors both within and outside our control, including durability,
+reliability, quality, design capability, product customization, price, customer
+support, success in developing new products, manufacturing expertise and
+capacity, supply of component parts and materials, strategic relationships with
+suppliers, the timing of new product introductions by us and our competitors,
+general market, economic and political conditions and, in some cases, the
+uniqueness of our products.
+In the POS and banking market, our major competitor is Epson America, Inc.,
+which holds a dominant market position of the POS markets into which we sell. We
+also compete, to a much lesser extent, with Transaction Printer Group, Star
+Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources,
+Inc. and Samsung/Bixolon. Certain competitors of ours have greater financial
+resources, lower costs attributable to higher volume production and sometimes
+offer lower prices than us.
+In the lottery market (consisting principally of on-line lottery
+transaction printing), we hold a leading position, based largely on our
+long-term purchase agreement with GTECH, which holds approximately 70% market
+share of the worldwide on-line lottery market. We compete in this market based
+solely on our ability to provide specialized, custom-engineered products to
+GTECH.
+5
+In the gaming market (consisting principally of slot machine and video
+lottery terminal transaction printing), we compete with several companies
+including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others.
+Certain of our products sold for gaming applications compete based upon our
+ability to provide highly specialized products, custom engineering and ongoing
+technical support.
+The TransAct Services Group business is highly fragmented, and we compete
+with numerous competitors of various sizes depending on the geographic area.
+Our strategy for competing in our markets is to continue to develop new
+products and product line extensions, to increase our geographic market
+penetration, to take advantage of strategic relationships, and to lower product
+costs by sourcing certain products overseas. Although we believe that our
+products, operations and relationships provide a competitive foundation, there
+can be no assurance that we will compete successfully in the future. In
+addition, our products utilize certain inkjet, thermal and impact printing
+technology. If other technologies, or variations to existing technologies were
+to evolve or become available to us, it is possible that we would incorporate
+these technologies into our products. Alternatively, if such technologies were
+to evolve or become available to our competitors, our products could become
+obsolete, which would have a significant negative impact on our business.
+RESEARCH AND DEVELOPMENT ACTIVITIES
+We spent approximately $2,824,000, $2,726,000 and $2,715,000 in 2006, 2005
+and 2004, respectively, on engineering, design and product development efforts
+in connection with specialized engineering and design to introduce new products
+and to customize existing products.
+ENVIRONMENT
+We are not aware of any material noncompliance with federal, state and
+local provisions that have been enacted or adopted regulating the discharge of
+materials into the environment, or otherwise relating to the protection of the
+environment.
+EMPLOYEES
+As of February 28, 2007, TransAct and our subsidiaries employed 185
+persons, of whom 172 were full-time and 13 were temporary employees. None of our
+employees are unionized, and we consider our relationships with our employees to
+be good.
+FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
+We have foreign operations primarily from TransAct Technologies Ltd., a
+wholly-owned subsidiary located in the United Kingdom, which had sales to its
+customers of $2,722,000, $2,181,000, and $1,000,000, (primarily for the service
+of printers used in the British Post Office) in 2006, 2005 and 2004,
+respectively. We had export sales from our domestic operations of approximately
+$11,416,000, $10,137,000 and $5,423,000 in 2006, 2005 and 2004, respectively.
+Total international sales, which include sales from our foreign subsidiary and
+export sales from our domestic operations, were approximately $14,138,000,
+$12,318,000 and $6,423,000 in 2006, 2005 and 2004, respectively.
+ADDITIONAL INFORMATION
+We make available free of charge through our internet website,
+WWW.TRANSACT-TECH.COM, 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 as soon
+as reasonably practicable after such material is electronically filed with or
+furnished to the SEC.
+We maintain a Code of Business Conduct that includes our code of ethics
+that is applicable to all employees, including our Chief Executive Officer,
+Chief Financial Officer and Controller. This Code, which requires continued
+observance of high ethical standards such as honesty, integrity and compliance
+with the law in the conduct of our business, is available for public access on
+our internet website. Any person may request a copy of our Code of Business
+Conduct free of charge by calling (203) 859-6800.
+EXECUTIVE OFFICERS OF THE REGISTRANT
+The following list is included as an unnumbered item in Part I of this
+Report in lieu of being included in the Proxy Statement for the Annual Meeting
+of Stockholders to be held on May 15, 2007.
+6
+The following is a list of the names and ages of all executive officers of the
+registrant, indicating all positions and offices with the registrant held by
+each such person and each person's principal occupations and employment during
+at least the past five years.
+Name Age Position
+---- --- ----------------------------------------------------------------
+Bart C. Shuldman 49 Chairman of the Board, President and Chief Executive Officer
+Steven A. DeMartino 37 Executive Vice President, Chief Financial Officer, Treasurer and
+Secretary
+Michael S. Kumpf 57 Executive Vice President - Engineering
+BART C. SHULDMAN has been Chief Executive Officer, President and a Director
+of the Company since its formation in June 1996. Previously, Mr. Shuldman served
+as President of Magnetec and later the combined operations of Magnetec and
+Ithaca Peripherals from August 1993 until June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board.
+STEVEN A. DEMARTINO was named as TransAct's Executive Vice President, Chief
+Financial Officer, Treasurer and Secretary on June 1, 2004. Previously, Mr.
+DeMartino served as Senior Vice President, Finance and Information Technology
+from October 2001 to May 2004, Vice President and Corporate Controller from
+January 1998 to October 2001, and Corporate Controller from August 1996 to
+December 1997. Prior to joining TransAct, Mr. DeMartino was a self-employed
+financial consultant from May 1996 to August 1996. Prior to that, Mr. DeMartino
+served as Controller of Copart, Inc. from September 1994 to May 1996. Mr.
+DeMartino is a certified public accountant.
+MICHAEL S. KUMPF was appointed Executive Vice President of Engineering in
+March 2002. He served as Senior Vice President, Engineering from June 1996 to
+March 2002 and Vice President, Engineering of Ithaca Peripherals from 1991 until
+June 1996.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2006/0000950123-07-003917/item13.txt b/raw/filings/0001017303/2006/0000950123-07-003917/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6aaf28f561750415b42aaeebfc2caed4df64ff04
--- /dev/null
+++ b/raw/filings/0001017303/2006/0000950123-07-003917/item13.txt
@@ -0,0 +1,3 @@
+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
+The information contained in "Certain Relationships and Related
+Transactions" of the Proxy Statement is hereby incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2006/0000950123-07-003917/item9a.txt b/raw/filings/0001017303/2006/0000950123-07-003917/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..03370fd037a5920b6a23125bc00a345b9d912a4c
--- /dev/null
+++ b/raw/filings/0001017303/2006/0000950123-07-003917/item9a.txt
@@ -0,0 +1,113 @@
+ITEM 9A. CONTROLS AND PROCEDURES
+Attached as exhibits to this Form 10-K are certifications of our Chief
+Executive Officer (CEO) and Chief Financial Officer (CFO), which are required in
+accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended
+(the Exchange Act). This "Controls and Procedures" section includes information
+concerning the controls and controls evaluation referred to in the
+certifications. Part II, Item 8 of this Form 10-K sets forth the report of
+PricewaterhouseCoopers LLP, our independent registered public accounting firm,
+regarding its audit of TransAct's internal control over financial reporting as
+of December 31, 2006 and of management's assessment of internal control over
+financial reporting as of December 31, 2006 set forth below in this section.
+This section should be read in conjunction with the CEO and CFO certifications
+and the PricewaterhouseCoopers LLP report for a more complete understanding of
+the topics presented.
+EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
+We conducted an evaluation of the effectiveness of the design and operation
+of our "disclosure controls and procedures" ("Disclosure Controls") for the
+period covered by this Form 10-K. The controls evaluation was conducted under
+the supervision and with the participation of management, including our CEO and
+CFO. Disclosure Controls are controls and procedures designed to reasonably
+assure that information required to be disclosed in our reports filed under the
+Exchange Act, such as this Form 10-K, is recorded, processed, summarized and
+reported within the time periods specified in the U.S. Securities and Exchange
+Commission's (SEC's) rules and forms. Disclosure Controls are also designed to
+reasonably assure that such information is accumulated and communicated to our
+management, including the CEO and CFO, as appropriate to allow timely decisions
+regarding required disclosure. Our quarterly evaluation of Disclosure Controls
+includes an evaluation of some components of our internal control over financial
+reporting, and internal control over financial reporting is also separately
+evaluated on an annual basis for purposes of providing the management report
+which is set forth below.
+The evaluation of our Disclosure Controls included a review of the
+controls' objectives and design, the company's implementation of the controls
+and the effect of the controls on the information generated for use in this Form
+10-K. In the course of the controls evaluation, we review data errors, control
+problems or acts of fraud, if any, and seek to confirm that appropriate
+corrective actions, including process improvements, are being undertaken. This
+type of evaluation is performed on a quarterly basis so that the conclusions of
+management, including the CEO and CFO, concerning the effectiveness of the
+Disclosure Controls can be reported in our periodic reports on Form 10-Q and
+Form 10-K. Many of the components of our Disclosure Controls are also evaluated
+on an ongoing basis by personnel in our finance organization. The overall goals
+of these various evaluation activities are to monitor our Disclosure Controls,
+and to modify them as necessary. Our intent is to maintain the Disclosure
+Controls as dynamic systems that change as conditions warrant.
+Based upon the evaluation of the controls, our CEO and CFO have concluded
+that, as of the end of the period covered by this Form 10-K, our Disclosure
+Controls were effective to provide reasonable assurance that information
+required to be disclosed in our Exchange Act reports is recorded, processed,
+summarized and reported within the time periods specified by the SEC, and that
+material information relating to TransAct and our consolidated subsidiaries is
+made known to management, including the CEO and CFO, particularly during the
+period when our periodic reports are being prepared.
+CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
+The implementation of our new accounting system, completed effective
+January 8, 2007, required us to modify and add certain internal controls and
+processes and procedures. Otherwise, no change in our internal control over
+financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the
+Exchange Act) occurred during the three months ended December 31, 2006 that has
+materially affected, or is reasonably likely to materially affect, our internal
+control over financial reporting.
+MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
+Our management is responsible for establishing and maintaining adequate
+internal control over financial reporting to provide reasonable assurance
+regarding the reliability of our financial reporting and the preparation of
+financial statements for external purposes in accordance with generally accepted
+accounting principles. 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.
+52
+Management assessed our internal control over financial reporting as of
+December 31, 2006. Management based its assessment on criteria established in
+Internal Control-Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission (COSO).
+Based on our assessment, management has concluded that our internal control
+over financial reporting was effective as of December 31, 2006 based on the COSO
+criteria identified above, to provide reasonable assurance regarding the
+reliability of financial reporting and the preparation of financial statements
+for external reporting purposes in accordance with generally accepted accounting
+principles.
+Our management's assessment of the effectiveness of the Company's internal
+control over financial reporting as of December 31, 2006 has been audited by
+PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
+stated in their report which appears herein.
+INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS
+A control system, no matter how well designed and operated, can provide
+only reasonable, not absolute, assurance that the control system's objectives
+will be met. 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. Further, because of the inherent limitations in all control
+systems, no evaluation of controls can provide absolute assurance that
+misstatements due to error or fraud will not occur or that all control issues
+and instances of fraud, if any, within the 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
+errors or mistakes. Controls can also be circumvented by the individual acts of
+some persons, by collusion of two or more people, or by management override of
+the controls. The design of any system of controls is based in part on 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. Projections of any evaluation of controls effectiveness to
+future periods are subject to risks. Over time, controls may become inadequate
+because of changes in conditions or deterioration in the degree of compliance
+with policies or procedures.
+PART III
\ No newline at end of file
diff --git a/raw/filings/0001017303/2006/0000950123-07-003917/rp_note.txt b/raw/filings/0001017303/2006/0000950123-07-003917/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2006/0000950123-07-003917/rpt_disclosure.txt b/raw/filings/0001017303/2006/0000950123-07-003917/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9de13dca1f3c37ce683ccb70b31f5e6ddf56eec7
--- /dev/null
+++ b/raw/filings/0001017303/2006/0000950123-07-003917/rpt_disclosure.txt
@@ -0,0 +1,18 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
+The Company maintains policies that relate to the identification, review
+and approval of related party transactions. As part of a review of possible
+related person transactions, the Company annually distributes and collects
+questionnaires that solicit information about any direct or indirect
+transactions with the Company from each of our directors and officers.
+Our Standards of Business Conduct require all directors, officers and
+employees to avoid any situation that involves an actual or apparent conflict of
+interest in personal and professional relationships or with their duty to, or
+with any interest of, the Company. Under the Standards of Business Conduct,
+situations that involve, or may reasonably be inferred to involve, a conflict
+between a director, officer or employee's personal interests and the interests
+of the Company should be disclosed to the Chair of the Audit Committee. No
+related party transaction shall be approved or ratified if such transaction is
+contrary to the best interests of the Company.
+From January 1, 2006 to the date of this proxy statement, there have not
+been any transactions of the type described in Item 404 of Regulation S-K, and
+currently no such transactions are proposed.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2008/0001017303-09-000003/filing.txt b/raw/filings/0001017303/2008/0001017303-09-000003/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..71b2c370f069c632491b3ff55f48ef7275cecd96
--- /dev/null
+++ b/raw/filings/0001017303/2008/0001017303-09-000003/filing.txt
@@ -0,0 +1,7280 @@
+10-K
+1
+form10-k.htm
+FORM 10-K
+form10-k.htm 
+UNITED
+STATES 
+SECURITIES
+AND EXCHANGE COMMISSION 
+Washington,
+DC. 20549 
+FORM
+10-K 
+FOR
+ANNUAL AND TRANSITION REPORTS 
+PURSUANT
+TO SECTIONS 13 OR 15(d) OF THE 
+SECURITIES
+AND EXCHANGE ACT OF 1934 
+(Mark
+One) 
+x 
+ANNUAL
+REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
+1934 
+For
+the fiscal year ended December 31, 2008 
+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: 0-21121 
+______________________________________________________________________ 
+______________________________________________________________________ 
+(Exact
+name of registrant as specified in its charter) 
+Delaware 
+06-1456680 
+(State
+or other jurisdiction of incorporation or organization) 
+(I.R.S.
+Employer Identification No.) 
+One
+Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden,
+CT 
+06518 
+(Address
+of principal executive offices) 
+(Zip
+Code) 
+Registrant's
+telephone number, including area code 203-859-6800 
+______________________________________________________________________ 
+Securities
+registered pursuant to Section 12(b) of the Act: 
+Title
+of Each Class 
+Name
+of Exchange on which Registered 
+Common
+Stock, par value $.01 per share 
+NASDAQ
+Global 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 o 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 Securities Act. 
+Yes o 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 o 
+Indicate
+by 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 other 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 the definitions of “large accelerated
+filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2
+of the Exchange Act. 
+Large
+accelerated filer o 
+Accelerated
+filer o 
+Non-accelerated
+filer o (Do
+not check if a smaller reporting
+company) 
+Smaller
+reporting company ý 
+Indicate
+by check mark whether the registrant is a shell company (as defined in
+Rule 12b-2 of the Exchange Act). 
+Yes o No ý 
+As of
+June 30, 2008 the aggregate market value of the registrant's issued and
+outstanding voting stock held by non-affiliates of the registrant was
+$72,000,000. 
+As of
+February 28, 2009, the registrant had outstanding 9,303,238 shares of common stock,
+$0.01 par value. 
+DOCUMENTS
+INCORPORATED BY REFERENCE 
+Proxy
+Statement for the Annual Meeting of Shareholders to be held on May 28 ,
+2009 – Part III (Items 10-14). 
+Table of Contents 
+TRANSACT TECHNOLOGIES
+INCORPORATED 
+INDEX 
+PART
+I. 
+Item
+1. 
+Business 
+1 
+Item
+1A. 
+Risk
+Factors 
+5 
+Item
+1B. 
+Unresolved Staff
+Comments 
+1 0 
+Item
+2. 
+Properties 
+1 0 
+Item
+3. 
+Legal
+Proceedings 
+1 0 
+Item
+4. 
+Submission of Matters
+to a Vote of Security Holders 
+1 0 
+PART
+II. 
+Item
+5. 
+Market for
+Registrant’s Common Equity, Related Stockholder Matters and Issuer
+Purchases of Equity Securities 
+1 0 
+Item
+6. 
+Selected Financial
+Data 
+1 2 
+Item
+7. 
+Management's
+Discussion and Analysis of Financial Condition and Results of
+Operations 
+1 2 
+Item
+7A. 
+Quantitative and
+Qualitative Disclosures About Market Risk 
+26 
+Item
+8. 
+Financial Statements
+and Supplementary Data 
+26 
+Item
+9. 
+Changes in and
+Disagreements with Accountants on Accounting and Financial
+Disclosure 
+26 
+Item
+9A. 
+Controls and
+Procedures 
+27 
+Item
+9B. 
+Other
+Information 
+27 
+PART
+III. 
+Item
+10. 
+Directors, Executive
+Officers and Corporate Governance 
+27 
+Item
+11. 
+Executive
+Compensation 
+28 
+Item
+12. 
+Security Ownership of
+Certain Beneficial Owners and Management and Related Stockholder
+Matters 
+28 
+Item
+13. 
+Certain Relationships
+and Related Transactions, and Director
+Independence 
+28 
+Item
+14. 
+Principal Accounting
+Fees and Services 
+28 
+PART
+IV. 
+Item
+15. 
+Exhibits and Financial
+Statement Schedules 
+28 
+SIGNATURES 
+Signatures 
+29 
+CONSOLIDATED
+FINANCIAL STATEMENTS AND SCHEDULE 
+Index to Consolidated
+Financial Statements and Schedule 
+F-1 
+EXHIBITS 
+Index to
+Exhibits 
+Table of Contents 
+PART I 
+Item 1. Business. 
+The
+Company 
+TransAct
+Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June
+1996 and began operating as a stand-alone business in August 1996 as a spin-off
+of the printer business that was formerly conducted by certain subsidiaries of
+Tridex Corporation. We completed an initial public offering on August
+22, 1996. 
+TransAct
+designs, develops, assembles, markets and services world-class transaction
+printers under the Epic and Ithaca® brand
+names. Known and respected worldwide for innovative designs and
+real-world service reliability, our thermal, inkjet and impact printers generate
+top-quality transaction records such as receipts, tickets, coupons, register
+journals and other documents. We focus on three core markets: (1)
+banking and point-of-sale (“POS”), (2) casino and gaming and (3)
+lottery. We sell our products to original equipment manufacturers
+("OEMs"), value-added resellers ("VARs"), selected distributors, as well as
+directly to end-users. Our product distribution spans across the
+Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean
+Islands and the South Pacific. In addition, we have a strong focus on
+the after-market side of the business, through
+our TransAct Services Group, with a growing commitment to printer
+service, supplies and spare parts. We have one primary operating
+facility located in Ithaca, NY, our printer sales headquarters and western
+region service center in Las Vegas, NV, an eastern region service center located
+in New Britain, CT, a European sales and service center in the United Kingdom,
+and a sales office located in Macau and two other sales offices located in the
+United States. Our executive offices are located at
+One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518,
+with a telephone number of (203) 859-6800. 
+Financial
+Information about Segments 
+We have
+determined that we operate in one reportable segment, the design, development,
+assembly and marketing of transaction printers and printer-related service,
+supplies and spare parts. 
+Products
+and Services 
+Printers 
+TransAct
+designs, develops, assembles and markets a broad array of transaction-based
+printers utilizing inkjet, thermal and impact printing technology for
+applications requiring up to 60 character columns, primarily in the banking,
+POS, casino, gaming and lottery markets. Our printers are
+configurable and offer customers the ability to choose from a variety of
+features and functions. Options typically include interface
+configuration, paper cutting devices, paper handling capacities and cabinetry
+color. In addition to our configurable printers, we design and
+assemble custom printers for certain OEM customers. In collaboration
+with these customers, we provide engineering and manufacturing expertise for the
+design and development of specialized printers. 
+Banking
+and POS: Our banking and POS printers include hundreds of optional
+configurations that can be selected to meet particular customer
+needs. We believe that this is a significant competitive strength, as
+it allows us to satisfy a wide variety of printing applications that our
+customers request. In the banking market, we sell printers that are
+used by banks, credit unions and other financial institutions to print and/or
+validate receipts at bank teller stations. In the POS market, we sell
+several models of printers utilizing inkjet, thermal and impact printing
+technology. Our printers are used primarily by retailers in the
+restaurant (including fine dining, casual dining, and fast food), hospitality,
+and specialty retail industries to print receipts for consumers, validate
+checks, or print on other inserted media. 
+Lottery: We
+supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”),
+our largest customer and the world’s largest provider of lottery
+terminals, with an approximate 70% market share. These printers are
+designed for high-volume, high-speed printing of lottery tickets for various
+lottery applications. 
+Casino
+and gaming: We sell several models of printers used in slot machines
+and video lottery terminals that print tickets or receipts instead of issuing
+coins at casinos, racetracks and other gaming establishments
+worldwide. These printers utilize thermal printing technology and can
+print tickets or receipts in monochrome or two-color (depending upon the model),
+and offer various other features such as jam resistant bezels and a dual port
+interface that will allow casinos to print coupons/promotions. In
+addition, we sell printers using thermal and impact printing technology for use
+in non-casino establishments, including game types such as Amusements with
+Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”),
+Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines
+around the world. 
+TransAct
+Services Group 
+Through
+our TransAct Services Group, we proactively market the sale of consumable
+products (including inkjet cartridges, ribbons,
+receipt paper and other transaction supplies ), replacement parts and
+maintenance services for all of our products and certain competitor’s
+products. Our maintenance services include the sale of extended
+warranties, multi-year maintenance contracts, 24-hour guaranteed replacement
+product service TransAct Xpress SM ,
+and other repair services for our printers. Within the United States,
+we provide repair services through our eastern region service center in New
+Britain, CT and our western region service center in Las Vegas,
+NV. Internationally, we provide repair services through our European
+service center located in Doncaster, United Kingdom, and through partners
+strategically located around the world. 
+1 
+Table of Contents 
+We also
+provide customers with telephone sales and technical support, and a personal
+account representative to handle orders, shipping and general
+information. Technical and sales support personnel receive training
+on all of our manufactured products and our services. 
+In
+addition to personalized telephone and technical support, we also market and
+sell consumable products 24 hours a day, seven days a week, via our online
+webstore www.transactsupplies.com . 
+Product
+Warranty 
+Our
+printers generally carry up to a two-year limited warranty against defects in
+material and workmanship. Defective equipment may be returned to any
+of our service centers, or our assembly facility in Ithaca, NY for
+newly-released printers only, for repair or replacement during the applicable
+warranty period. 
+Production,
+Manufacturing and Sources and Availability of Raw Materials 
+We design
+our products to optimize product performance, quality, reliability and
+durability. These designs combine cost efficient materials, sourcing
+and assembly methods with high standards of workmanship. During 2008,
+we began a program to transfer final assembly for approximately 70% of our total
+printer production to a third-party contract manufacturer in China by the end of
+2009. As of December 31, 2008, we had transferred approximately
+30% of our total production to this contract manufacturer, and we expect the
+remaining 40% to be transferred during 2009. Over the remainder of
+2009, we will continue to finalize assembly for some of our products in our
+Ithaca, NY facility largely on a configure-to-order basis using components and
+subassemblies that have been sourced from vendors or contract manufacturers
+around the world. However, we plan to decrease in-house printer
+production in Ithaca, NY by printer model as the assembly of that printer model
+is transferred to our contract manufacturer. 
+We
+procure component parts and subassemblies for use in the assembly of our
+products in Ithaca, NY. Critical component parts and subassemblies
+include inkjet, thermal and impact printheads, printing/cutting mechanisms,
+power supplies, motors, injection molded plastic parts, circuit boards and
+electronic components, which are obtained from domestic and foreign suppliers at
+competitive prices. With the transition of 70% of our production to
+our contract manufacturer, during 2009 we expect purchases of component parts
+will decline, while purchases of fully-assembled printers will increase, as
+in-house printer assembly in Ithaca, NY declines and assembly by our contract
+manufacturer increases. Furthermore, during this transition, we
+expect inventories to temporarily rise, as we plan to increase our stocking
+levels to ensure product availability to meet our customers’
+demands. We typically strive to maintain more than one source for our
+component parts, subassemblies and fully assembled printers to reduce the risk
+of parts shortages or unavailability. However, we could experience
+temporary disruption if certain suppliers ceased doing business with us, as
+described below. 
+We
+currently buy substantially all of our thermal print mechanisms, an important
+component of our thermal printers, and fully assembled printers for several of
+our printer models, from one foreign contract manufacturer. Although
+we believe that other contract manufacturers could provide similar thermal print
+mechanisms or fully assembled printers, on comparable terms, a change in
+contract manufacturers could cause a delay in manufacturing and possible loss of
+sales, which may have a material adverse effect on our operating
+results. 
+Hewlett-Packard
+Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of
+our inkjet printers. The loss of the supply of HP inkjet cartridges
+would have a material adverse effect on the sale of our inkjet
+printers. Prior to February 2006, we had a supply agreement with HP
+to purchase inkjet cartridges at fixed prices. This agreement expired
+on February 1, 2006 and was not renewed, as HP informed us that they no longer
+maintain supply agreements for these inkjet cartridges; however, we continue to
+purchase inkjet cartridges from HP. Although we no longer have a
+supply agreement with HP, our relationship with HP remains strong and we have no
+reason to believe that HP will discontinue its supply of inkjet cartridges to
+us. The inkjet cartridges we purchase from HP are used not only in
+our inkjet printers for the banking and POS market, but also in other
+manufacturer’s printing devices across several other markets. 
+Okidata
+Americas, Inc. (“Okidata”) is the sole supplier for an impact printer component
+kit consisting of a printhead, control board and carriage (the “Oki Kit”) that
+is used in all of our Ithaca â brand impact
+printers. The loss of the supply of Oki Kits would have a material
+adverse effect on TransAct. However, sales of impact printers
+continue to decline as sales of these printers are replaced by sales of thermal
+and inkjet printers. As such,
+we believe that any possible loss of supply of Oki Kits will continue to have
+less of an impact on TransAct in 2009 and beyond. Although we do not
+have a supply agreement with Okidata, our relationship with Okidata remains
+strong and we have no reason to believe that Okidata will discontinue its supply
+of Oki Kits to us during 2009 or that their terms to us will be any less
+favorable than they have been historically. 
+2 
+Table of Contents 
+Patents
+and Proprietary Information 
+We have
+significantly expanded our patent portfolio since 2002, and expect to continue
+to do so in the future. We also believe our patent portfolio could
+provide additional opportunities to license our intellectual property in the
+future. We hold 23 United States and 19 foreign patents and have 8
+United States and 72 foreign patent applications pending pertaining to our
+products. The duration of these patents range from 10 to 18
+years. The expiration of any individual patent would not have a
+significant negative impact on our business. We regard certain
+manufacturing processes and designs to be proprietary and attempt to protect
+them through employee and third-party nondisclosure agreements and similar
+means. It may be possible for unauthorized third parties to copy
+certain portions of our products or to reverse engineer or otherwise obtain and
+use, to our detriment, information that we regard as
+proprietary. Moreover, the laws of some foreign countries do not
+afford the same protection to our proprietary rights as do United States laws.
+There can be no assurance that legal protections relied upon by the Company to
+protect our proprietary position will be adequate or that our competitors will
+not independently develop technologies that are substantially equivalent or
+superior to our technologies. 
+Seasonality 
+Retailers
+typically reduce purchases of new POS equipment in the fourth quarter, due to
+the increased volume of consumer transactions in that holiday period, and our
+sales of printers in the POS market historically have increased in the third
+quarter and decreased in the fourth quarter. Similarly, installations
+of lottery terminals are typically reduced in the fourth quarter, resulting in
+decreased sales of lottery printers. 
+Certain
+Customers 
+We
+currently have an ongoing OEM purchase agreement, as amended in February 2006
+(the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of
+thermal on-line lottery printers and spare parts, at fixed prices, through June
+28, 2012. During 2008, sales to GTECH accounted for 28% of our net
+sales, and no other customer individually accounted for more than 10% of total
+net product sales. Firm purchase orders for printers under the GTECH
+Thermal Printer Agreement may be placed as required by GTECH. Prior
+to this agreement, we had a purchase agreement with GTECH that provided for the
+sale of impact on-line lottery printers and spare parts through December 31,
+2004. Because our new thermal on-line lottery printer is a
+replacement for our impact on-line printer, we do not expect any further
+shipments of impact on-line lottery printers. However, we do expect
+to continue to sell spare parts to GTECH for the remaining installed base of
+impact on-line lottery printers, although we expect such sales to decline as the
+installed base of impact on-line lottery printers are replaced with our thermal
+printer. 
+Backlog 
+Our
+backlog of firm orders was approximately $9,994,000 as of February 28,
+2009, compared to $9,123,000 as of February 29, 2008. Based on
+customers’ current delivery requirements, we expect to ship our entire current
+backlog during 2009. 
+Competition 
+The
+market for transaction-based printers is extremely competitive, and we expect
+such competition to continue in the future. We compete with a number of
+companies, many of which have greater financial, technical and marketing
+resources than us. We believe our ability to compete successfully depends on a
+number of factors both within and outside our control, including durability,
+reliability, quality, design capability, product customization, price, customer
+support, success in developing new products, manufacturing expertise and
+capacity, supply of component parts and materials, strategic relationships with
+suppliers, the timing of new product introductions by us and our competitors,
+general market, economic and political conditions and, in some cases, the
+uniqueness of our products. 
+In the
+banking and POS market, our major competitor is Epson America, Inc., which holds
+a dominant market position of the POS markets into which we sell. We
+also compete, to a much lesser extent, with Transaction Printer Group, Star
+Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources,
+Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours
+have greater financial resources, lower costs attributable to higher volume
+production and sometimes offer lower prices than us. 
+In the
+lottery market (consisting principally of on-line lottery transaction printing),
+we hold a leading position, based largely on our long-term purchase agreement
+with GTECH, which holds approximately 70% market share of the worldwide on-line
+lottery market. We compete in this market based solely on our ability
+to provide specialized, custom-engineered products to GTECH. 
+In the
+casino and gaming market (consisting principally of slot machine and video
+lottery terminal transaction printing), we compete with several companies
+including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and
+others. Certain of our products sold for casino and gaming
+applications compete based upon our ability to provide highly specialized
+products, custom engineering and ongoing technical support. 
+The
+TransAct Services Group business is highly fragmented, and we compete with
+numerous competitors of various sizes depending on the geographic
+area. 
+3 
+Table of Contents 
+Our
+strategy for competing in our markets is to continue to develop new products and
+product line extensions, to increase our geographic market penetration, to take
+advantage of strategic relationships, and to lower product costs by sourcing
+certain products overseas. Although we believe that our products,
+operations and relationships provide a competitive foundation, there can be no
+assurance that we will compete successfully in the future. In
+addition, our products utilize certain inkjet, thermal and impact printing
+technology. If other technologies, or variations to existing
+technologies were to evolve or become available to us, it is possible that we
+would incorporate these technologies into our
+products. Alternatively, if such technologies were to evolve or
+become available to our competitors, our products could become obsolete, which
+would have a significant negative impact on our business. 
+Research
+and Development Activities 
+We spent
+approximately $2,942,000, $3,129,000 and $2,824,000 in 2008, 2007 and 2006,
+respectively, on engineering, design and product development efforts in
+connection with specialized engineering and design to introduce new products and
+to customize existing products. 
+Environment 
+We are
+not aware of any material noncompliance with federal, state and local provisions
+that have been enacted or adopted regulating the discharge of materials into the
+environment, or otherwise relating to the protection of the
+environment. 
+Employees 
+As of
+February 28, 2009, TransAct and our subsidiaries employed 151 persons, of whom
+150 were full-time and 1 was a temporary employee. None of our
+employees are unionized, and we consider our relationships with our employees to
+be good. 
+Financial
+Information About Geographic Areas 
+We have
+foreign operations primarily from TransAct Technologies Ltd., a wholly-owned
+subsidiary located in the United Kingdom, which had sales to its customers of
+$120,000, $2,121,000 and $2,722,000 in 2008, 2007 and 2006,
+respectively. We had export sales from our domestic operations of
+approximately $10,006,000, $8,674,000 and $11,416,000 in 2008, 2007 and 2006,
+respectively. Total international sales, which include sales from our
+foreign subsidiary and export sales from our domestic operations, were
+approximately $10,126,000, $10,795,000 and $14,138,000 in 2008, 2007 and 2006,
+respectively. 
+Additional
+Information 
+We make
+available free of charge through our internet website, www.transact-tech.com ,
+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 as soon as reasonably
+practicable after such material is electronically filed with or furnished to the
+SEC. 
+We
+maintain a Code of Business Conduct that includes our code of ethics that is
+applicable to all employees, including our Chief Executive Officer, Chief
+Financial Officer and Controller. This Code, which requires continued
+observance of high ethical standards such as honesty, integrity and compliance
+with the law in the conduct of our business, is available for public access on
+our internet website. Any person may request a copy of our Code of
+Business Conduct free of charge by calling (203) 859-6800. 
+Executive
+Officers of the Registrant 
+The
+following list is included as an unnumbered item in Part I of this Report in
+lieu of being included in the Proxy Statement for the Annual Meeting of
+Stockholders to be held on May 28 , 2009 . 
+The
+following is a list of the names and ages of all executive officers of the
+registrant, indicating all positions and offices with the registrant held by
+each such person and each person’s principal occupations and employment during
+at least the past five years. 
+Name 
+Age 
+Position 
+Bart
+C. Shuldman 
+51 
+Chairman
+of the Board, President and Chief Executive Officer 
+Steven
+A. DeMartino 
+39 
+Executive
+Vice President, Chief Financial Officer, Treasurer and
+Secretary 
+Michael
+S. Kumpf 
+59 
+Executive
+Vice President-Engineering 
+James
+B. Stetson 
+52 
+Senior
+Vice President and Business Manager of the TransAct Services
+Group 
+Tracey
+S. Chernay 
+49 
+Senior
+Vice President-Sales and Marketing 
+Andrew
+Hoffman 
+51 
+Senior
+Vice
+President-Operations 
+Bart C.
+Shuldman has been Chief Executive Officer, President and a Director of the
+Company since its formation in June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board. 
+Steven A.
+DeMartino was named as TransAct’s Executive Vice President, Chief Financial
+Officer, Treasurer and Secretary on June 1, 2004. Previously, Mr.
+DeMartino served as Senior Vice President, Finance and Information Technology
+from October 2001 to May 2004, Vice President and Corporate Controller from
+January 1998 to October 2001, and Corporate Controller from August 1996 to
+December 1997. Mr. DeMartino is a certified public
+accountant. 
+4 
+Table of Contents 
+Michael
+S. Kumpf was appointed Executive Vice President of Engineering in March
+2002. He served as Senior Vice President, Engineering from June 1996
+to March 2002. 
+James B.
+Stetson was appointed Senior Vice President and Business Manager of TransAct
+Services Group in January 2005. Previously, Mr. Stetson held the
+position of Executive Vice President of Sales and Marketing from February 2000
+to December 2004, and Vice President of Latin American Sales from October 1997
+to February 2000. 
+Tracey S.
+Chernay was appointed Senior Vice President, Sales and Marketing in June 2007,
+with responsibility for the sales and marketing of all TransAct printer products
+worldwide. Previously Ms. Chernay served as Sr. Vice President,
+Marketing & Sales, POS & Banking with the Company from July 2006 to June
+2007, and joined TransAct in May of 2005 as Senior Vice President,
+Marketing. Prior to joining TransAct, Ms. Chernay was employed with
+Xerox Corporation where she held the role of Manager, Worldwide Marketing since
+2003, and Manager, Sales Operations from 2000 to 2002. She joined
+Xerox Corporation in 1983. 
+Andrew
+Hoffman was appointed Senior Vice President, Operations for TransAct worldwide
+in November 2004. He served as Vice President, Operations from
+September 1994 to November 2004. 
+Item 1A. Risk Factors 
+Investors
+should carefully consider the risks, uncertainties and other factors described
+below, as well as other disclosures in Management’s Discussion and Analysis of
+Financial Condition and Results of Operations, because they could have a
+material adverse effect on our business, financial condition, operating results,
+and growth prospects. The risks described below and incorporated by
+reference are not the only ones facing our Company. Additional risks
+not known to us now or that we currently deem immaterial may also impair our
+business operations. 
+We assume
+no obligation (and specifically disclaim any such obligation) to update these
+Risk Factors or any other forward-looking statements contained in this Annual
+Report to reflect actual results, changes in assumptions or other factors
+affecting such forward-looking statements, except as required by
+law. 
+Current
+economic conditions and market disruptions may adversely affect our business and
+results of operations. 
+As widely
+reported, financial markets throughout the world have been experiencing extreme
+disruption in recent months, including, among other things, extreme volatility
+in security prices, severely diminished liquidity and credit availability,
+rating downgrades of certain investments and declining valuations of others,
+failure and potential failures of major financial institutions and unprecedented
+government support of financial institutions. The financial, casino
+and gaming industries have been more severely impacted by the current economic
+downturn than other industries and this may lead our customers in these
+industries to reduce, or discontinue, spending on our products which could
+adversely impact our business. These developments and the related general
+economic downturn may adversely impact our business and financial condition in a
+number of additional ways, including impacts beyond those typically associated
+with other recent downturns in the U.S. and foreign economies. The
+slowdown could lead to reduced capital spending by end users, which could
+adversely affect our product sales. The current tightening of credit
+in financial markets and the general economic downturn may adversely affect the
+ability of our customers, suppliers, outsource manufacturer and channel partners
+(e.g., distributors and resellers) to obtain financing for significant purchases
+and operations and to perform their obligations with the Company. The
+tightening could result in a decrease in or cancellation of orders for our
+products and services, could negatively impact our ability to collect our
+accounts receivable on a timely basis, could result in additional reserves for
+uncollectible accounts receivable being required, and in the event of the
+contraction in our sales, could lead to excess inventory and require additional
+reserves for obsolescence. Significant volatility and fluctuations in
+the rates of exchange for the U.S. dollar against foreign currencies could
+negatively impact our customer pricing and adversely affect our
+results. 
+We are
+unable to predict the duration and severity of the current economic downturn and
+disruption in financial markets or their effects on our business and results of
+operations, but the consequences may be materially adverse and more severe than
+other recent economic slowdowns. 
+Our
+success will depend on our ability to sustain and manage growth. 
+As part
+of our business strategy, we intend to pursue an aggressive growth
+strategy. Assuming this growth occurs, it will require the expansion
+of distribution relationships in international markets, the successful
+development and marketing of new products, expanded customer service and
+support, and the continued implementation and improvement of our operational,
+financial and management information systems. 
+To the
+extent that we seek growth through acquisitions, our ability to manage our
+growth will also depend on our ability to integrate businesses that have
+previously operated independently. We may not be able to achieve this
+integration without encountering difficulties or experiencing the loss of key
+employees, customers or suppliers. It may be difficult to design and
+implement effective financial controls for combined operations and differences
+in existing controls for each business may result in weaknesses that require
+remediation when the financial controls and reporting functions are
+combined. 
+5 
+Table of Contents 
+There can
+be no assurance that we will be able to successfully implement our growth
+strategy, or that we can successfully manage expanded operations. As
+the Company expands, we may from time to time experience constraints that will
+adversely affect our ability to satisfy customer demand in a timely
+fashion. Failure to manage growth effectively could adversely affect
+our results of operations and financial condition. 
+In
+the lottery market, we have been dependent on sales to one large customer; the
+loss of this customer or reduction in orders from this customer could materially
+affect our sales. 
+We expect
+that sales to one large customer will continue to represent a significant
+percentage of our net sales for the foreseeable future. A reduction,
+delay or cancellation in orders from this customer, including reductions or
+delays due to market, economic, or competitive conditions in the industries in
+which we serve, could have a material adverse effect upon our results of
+operations. 
+We
+rely on resellers to sell our products and services. 
+We use a
+variety of distribution channels, including OEMs and distributors, to market our
+products. We may be adversely impacted by any conflicts that could
+arise between and among our various sales channels. 
+Our
+dependence upon resellers exposes us to numerous risks, including: 
+· 
+loss
+of channel and the ability to bring new products to
+market; 
+· 
+concentration
+of credit risk, including disruption in distribution should the resellers’
+financial condition deteriorate; 
+· 
+reduced
+visibility to end user demand and pricing issues which makes forecasting
+more difficult; 
+· 
+resellers
+leveraging their buying power to change the terms of pricing, payment and
+product delivery schedules; and 
+· 
+direct
+competition should a reseller decide to manufacture printers internally or
+source printers from a competitor. 
+We cannot
+guarantee that resellers will not reduce, delay or eliminate purchases from us,
+which could have a material adverse effect upon the business, consolidated
+results of operations and financial condition. 
+Our
+operating results and financial condition may fluctuate. 
+Our
+operating results and financial condition may fluctuate from quarter to quarter
+and year to year and are likely to continue to vary due to a number of factors,
+many of which are not within our control. If our operating results do
+not meet the expectations of securities analysts or investors, who may derive
+their expectations by extrapolating data from recent historical operating
+results, the market price of our common stock will likely
+decline. Fluctuations in our operating results and financial
+condition may be due to a number of factors, including, but not limited to,
+those identified throughout this “Risk Factors” section: 
+· 
+market
+acceptance of our products, both domestically and
+internationally; 
+· 
+development
+of new competitive printers by
+others; 
+· 
+our
+responses to price competition; 
+· 
+our
+level of research and development
+activities; 
+· 
+changes
+in the amount that we spend to develop, acquire or license new products,
+consumables, technologies or
+businesses; 
+· 
+changes
+in the amount we spend to promote our products and
+services; 
+· 
+changes
+in the cost of satisfying our warranty obligations and servicing our
+installed base of printers; 
+· 
+delays
+between our expenditures to develop and market new or enhanced printers
+and consumables and the generation of sales from those
+products; 
+· 
+the
+geographic distribution of our
+sales; 
+· 
+availability
+of third-party components at reasonable
+prices; 
+· 
+general
+economic and industry conditions, including changes in interest rates
+affecting returns on cash balances and investments, that affect customer
+demand; 
+· 
+severe
+weather events (such as hurricanes) that can disrupt or interrupt the
+operation of our customers or suppliers facilities;
+and 
+· 
+changes
+in accounting rules. 
+Due to
+all of the foregoing factors, and the other risks discussed in this report,
+quarter-to-quarter comparisons of our operating results may not be an indicator
+of future performance. 
+We
+depend on key personnel, the loss of which could materially impact our
+business. 
+Our
+future success will depend in significant part upon the continued service of
+certain key management and other personnel and our continuing ability to attract
+and retain highly qualified managerial, technical and sales and marketing
+personnel. There can be no assurance that we will be able to recruit
+and retain such personnel. The loss of either Bart C. Shuldman, the
+Company's Chairman of the Board, President and Chief Executive Officer, or
+Steven A. DeMartino, Executive Vice President, Chief Financial Officer,
+Treasurer and Secretary, or the loss of certain groups of key employees, could
+have a material adverse effect on our results of operations. 
+6 
+Table of Contents 
+Our
+stock price may fluctuate significantly. 
+The
+market price of our common stock could fluctuate significantly in response to
+variations in quarterly operating results and other factors, such
+as: 
+· 
+changes
+in our business, operations or
+prospects; 
+· 
+developments
+in our relationships with our
+customers; 
+· 
+announcements
+of new products or services by us or by our
+competitors; 
+· 
+announcement
+or completion of acquisitions by us or by our
+competitors; 
+· 
+changes
+in existing or adoption of additional government
+regulations; 
+· 
+unfavorable
+or reduced analyst coverage; and 
+· 
+prevailing
+domestic and international market and economic
+conditions. 
+In
+addition, the stock market has experienced significant price fluctuations in
+recent years. Broad market fluctuations, general economic conditions
+and specific conditions in the industries in which we operate may adversely
+affect the market price of our common stock. 
+Limited
+trading volume of our capital stock may contribute to its price
+volatility. 
+Our
+common stock is traded on the NASDAQ Global Market. During the twelve
+months ended December 31, 2008, the average daily trading volume for our common
+stock as reported by the NASDAQ Global Market was approximately 66,000
+shares. We are uncertain whether a more active trading market in our
+common stock will develop. In addition, many investment banks no
+longer find it profitable to provide securities research on micro-cap and
+small-cap companies. If any analyst were to discontinue coverage of
+our common stock, our trading volume may be further reduced. As a
+result, relatively small trades may have a significant impact on the market
+price of our common stock, which could increase the volatility and depress the
+price of our common stock. 
+Future
+sales of our common stock may cause our stock price to decline. 
+In the
+future, we may sell additional shares of our common stock in public or private
+offerings, and we may also issue additional shares of our common stock to
+finance future acquisitions. Shares of our common stock are also
+available for future sale pursuant to stock options that we have granted to our
+employees, and in the future we may grant additional stock options and other
+forms of equity compensation to our employees. Sales of our common
+stock or the perception that such sales could occur may adversely affect
+prevailing market prices for shares of our common stock and could impair our
+ability to raise capital through future offerings. 
+If
+we are unable to enforce our patents or if it is determined that we infringe
+patents held by others it could damage our business. 
+Prosecuting
+and defending patent lawsuits is very expensive. We are committed to
+aggressively asserting and defending our technology and related intellectual
+property, which we have spent a significant amount of money to
+develop. These factors could cause us to become involved in new
+patent litigation in the future. The expense of prosecuting or defending these
+future lawsuits could also have a material adverse effect on our business,
+financial condition and results of operations. 
+If we
+were to lose a patent lawsuit in which another party is asserting that our
+products infringe its patents, we would likely be prohibited from marketing
+those products and could also be liable for significant damages. Either or both
+of these results may have a material adverse effect on our business, financial
+condition and results of operations. If we lose a patent lawsuit in which we are
+claiming that another party’s products are infringing our patents and thus, are
+unable to enforce our patents, it may have a material adverse effect on our
+business, financial condition and results of operations. In addition
+to disputes relating to the validity or alleged infringement of other parties'
+rights, we may become involved in disputes relating to our assertion of our own
+intellectual property rights. Whether we are defending the assertion of
+intellectual property rights against us or asserting our intellectual property
+rights against others, intellectual property litigation can be complex, costly,
+protracted, and highly disruptive to business operations by diverting the
+attention and energies of management and key technical personnel. Plaintiffs in
+intellectual property cases often seek injunctive relief, and the measures of
+damages in intellectual property litigation are complex and often subjective or
+uncertain. Thus, any adverse determinations in this type of litigation could
+subject us to significant liabilities and costs. During the course of these
+lawsuits there may be public announcements of the results of hearings, motions,
+and other interim proceedings or developments in the litigation. If securities
+analysts or investors perceive these results to be negative, it could harm the
+market price of our stock. 
+The
+inability to protect intellectual property could harm our reputation, and our
+competitive position may be materially damaged. 
+Our
+intellectual property is valuable and provides us with certain competitive
+advantages. Copyrights, patents, trade secrets and contracts are used to protect
+these proprietary rights. Despite these precautions, it may be possible for
+third parties to copy aspects of our products or, without authorization, to
+obtain and use information which we regard as trade secrets. 
+7 
+Table of Contents 
+Infringement
+on the proprietary rights of others could put us at a competitive disadvantage,
+and any related litigation could be time consuming and costly. 
+Third
+parties may claim that we violated their intellectual property rights. To the
+extent of a violation of a third party’s patent or other intellectual property
+right, we may be prevented from operating our business as planned and may be
+required to pay damages, to obtain a license, if available, or to use a
+non-infringing method, if possible, to accomplish our objectives. Any of these
+claims, with or without merit, could result in costly litigation and divert the
+attention of key personnel. If such claims are successful, they could result in
+costly judgments or settlements. 
+We
+compete in a highly competitive market, which is likely to become more
+competitive. Competitors may be able to respond more quickly to new or emerging
+technology and changes in customer requirements. 
+We face
+significant competition in developing and selling our printers and
+services. Principal competitors have substantial marketing,
+financial, development and personnel resources. To remain
+competitive, we believe we must continue to provide: 
+· 
+Technologically
+advanced printers that satisfy the user
+demands, 
+· 
+Superior
+customer service, 
+· 
+High
+levels of quality and reliability,
+and 
+· 
+Dependable
+and efficient distribution
+networks. 
+We cannot
+ensure we will be able to compete successfully against current or future
+competitors. Increased competition in printers or supplies may result
+in price reductions, lower gross profit margins and loss of market share, and
+could require increased spending on research and development, sales and
+marketing and customer support. Some competitors may make strategic
+acquisitions or establish cooperative relationships with suppliers or companies
+that produce complementary products. Any of these factors could
+reduce our earnings. 
+We
+have outsourced a large portion of the assembly of our printers to a contract
+manufacturer and will be dependent on them for the manufacturing of such
+printers. A failure by this contract manufacturer , or any disruption
+in such manufacturing, may adversely affect our business results. 
+In an
+effort to achieve additional cost savings and operation benefits, we have
+continued to outsource the manufacturing and assembly of our printers to a
+contract manufacturer in China. 
+However,
+to the extent we rely on a third party service provider for manufacturing
+services, we may incur increased business continuity risks. We will
+no longer be able to exercise control over the assembly of certain of our
+printers or any related operations or processes, including the internal controls
+associated with operations and processes conducted and the quality of our
+products assembled by the contract manufacturer. If we are unable to
+effectively develop and implement our outsourcing strategy, we may not realize
+cost structure efficiencies and our operating and financial results could be
+materially adversely affected. 
+In
+addition, if the contract manufacturer experiences business difficulties or
+fails to meet our manufacturing needs, then we may be unable to meet production
+requirements, may lose revenue and may not be able to maintain relationships
+with our customers. Without the contract manufacturer continuing to
+manufacture our products and the continuing operation of the contract
+manufacturer’s facility, we will have limited means for the final
+assembly of a majority of our printers until we are able to secure the
+manufacturing capability at another facility or develop an alternative
+manufacturing facility, which could be costly and time consuming and have a
+material adverse effect on our operating and financial results. 
+The
+increased elements of risk that arise from conducting certain operating
+processes in foreign jurisdictions may lead to an increase in reputational
+risk. 
+Although
+we carry business interruption insurance to cover lost revenue and profits in an
+amount we consider adequate, this insurance does not cover all possible
+situations. In addition, the business interruption insurance would not
+compensate us for the loss of opportunity and potential adverse impact, both
+short-term and long-term, on relations with our existing customers resulting
+from our inability to produce products for them. 
+The
+contract manufacturer has access to our intellectual property, which
+increases the risk of infringement or misappropriation of this intellectual
+property. 
+We
+source some of our component parts and consumable products from sole source
+suppliers; any disruptions may impact our ability to manufacture and sell our
+products. 
+A
+disruption in the supply of such component parts and consumable products could
+have a material adverse effect on our operations and financial
+results. 
+8 
+Table of Contents 
+We
+sell a significant portion of our products internationally and purchase
+important components from foreign suppliers. These circumstances create a
+number of risks. 
+We sell a
+significant amount of our products to customers outside the United States.
+Shipments to international customers are expected to continue to account for a
+material portion of net sales. Risks associated with sales and purchases outside
+the United States include: 
+· 
+Fluctuating
+foreign currency rates could restrict sales, or increase costs of
+purchasing, in foreign countries. 
+· 
+Foreign
+governments may impose burdensome tariffs, quotas, taxes, trade barriers
+or capital flow restrictions. 
+· 
+Political
+and economic instability may reduce demand for our products or put our
+foreign assets at risk. 
+· 
+Restrictions
+on the export or import of technology may reduce or eliminate the ability
+to sell in or purchase from certain
+markets. 
+· 
+Potentially
+limited intellectual property protection in certain countries, such as
+China, may limit recourse against infringing products or cause us to
+refrain from selling in certain geographic
+territories. 
+If
+market conditions deteriorate or future results of operations are less than
+expected, a valuation allowance may be required for all or a portion of our
+deferred tax assets. 
+We
+currently have significant deferred tax assets, which may be used to reduce
+taxable income in the future. We assess the realization of these deferred tax
+assets on a quarterly basis, and if we determine that it is more likely than not
+that some portion of these assets will not be realized, an income tax valuation
+allowance is recorded. If market conditions deteriorate or future
+results of operations are less than expected, or there is a change to applicable
+tax rules, future assessments may result in a determination that it is more
+likely than not that some or all of our net deferred tax assets are not
+realizable. As a result, we may need to establish a valuation allowance for all
+or a portion of our net deferred tax assets, which may have a material adverse
+effect on our business, results of operations and financial
+condition. 
+We
+cannot provide any assurance that current laws, or any laws enacted in the
+future, will not have a material adverse effect on our business. 
+Our
+operations are subject to laws, rules, regulations, including environmental
+regulations, government policies and other requirements in each of the
+jurisdictions in which we conduct business. Changes in laws, rules,
+regulations, policies or requirements could result in the need to modify our
+products and could affect the demand for our products, which may have an adverse
+impact on our future operating results. If we do not comply with
+applicable laws, rules and regulations we could be subject to costs and
+liabilities and our business may be adversely impacted. 
+Our
+business could be adversely affected by actual or threatened terrorist attacks
+or the related heightened security measures, military actions and other efforts
+to combat terrorism. 
+Our
+business could be adversely affected by actual or threatened terrorist attacks
+or the related heightened security measures, military actions and other efforts
+to combat terrorism. It is possible that terrorist attacks could be
+directed at important locations for the gaming industry. Heightened security
+measures and other efforts to combat terrorism may also have an adverse effect
+on the gaming industry by reducing tourism. Any of these developments
+could also negatively affect the general economy and consumer
+confidence. Any downturn in the economy or in the gaming industry in
+particular could reduce demand for our products and adversely affect our
+business and results of operations. In addition, heightened security
+measures may cause certain governments to restrict the import/export of goods,
+which may have an adverse effect on our ability to buy/sell goods. 
+Additional
+risks and uncertainties not presently known to us or that we currently believe
+to be immaterial also may adversely impact our business. Should any risks or
+uncertainties develop into actual events, these developments could have material
+adverse effects on our business, financial condition, and results of
+operations. 
+9 
+Table of Contents 
+Item 1B. Unresolved Staff Comments . 
+Not
+applicable. 
+Item 2. Properties. 
+Our
+corporate headquarters is currently located in Hamden, CT. Our global
+engineering and assembly facility is located in Ithaca,
+NY. We also maintain a facility in Las Vegas, NV that serves as our
+global printer sales headquarters and western region service
+center. Our eastern region service center is currently located in New
+Britain, CT. 
+Our
+principal facilities as of December 31, 2008 are listed below: 
+Location 
+Operations
+Conducted 
+Size 
+(Approx. Sq.
+Ft.) 
+Owned
+or 
+Leased 
+Lease
+Expiration 
+Date 
+Hamden,
+Connecticut 
+Executive
+offices and TransAct Services Group sales office 
+11,100 
+Leased 
+April
+23, 2017 
+Ithaca,
+New York 
+Research,
+design and assembly facility 
+73,900 
+Leased 
+June
+30, 2012 
+Las
+Vegas, Nevada 
+Service
+center and printer sales headquarters 
+13,700 
+Leased 
+January
+31, 2010 
+New
+Britain, Connecticut 
+Service
+center 
+11,500 
+Leased 
+April
+1, 2012 
+Doncaster,
+United Kingdom 
+Sales
+office and service center 
+2,800 
+Leased 
+August
+1, 2009 
+Georgia
+and New York 
+Two
+regional sales offices 
+300 
+Leased 
+Various 
+113,300 
+We
+believe that our facilities generally are in good condition, adequately
+maintained and suitable for their present and currently contemplated
+uses. 
+Item 3. Legal Proceedings. 
+None. 
+Item 4. Submission of Matters to a Vote of Security
+Holders. 
+No
+matters were submitted to a vote of security holders during the last quarter of
+the year covered by this report. 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related
+Stockholder Matters and Issuer Purchases of Equity Securities. 
+Our
+common stock is traded on the NASDAQ Global Market under the symbol
+TACT. As of February 28, 2009, there were 575 holders of record of
+the common stock. The high and low sales prices of the common stock
+reported during each quarter of the years ended December 31, 2008 and 2007 were
+as follows: 
+Year
+Ended 
+Year
+Ended 
+December
+31, 2008 
+December
+31, 2007 
+High 
+Low 
+High 
+Low 
+First
+Quarter 
+$ 
+5.67 
+$ 
+3.58 
+$ 
+10.10 
+$ 
+6.75 
+Second
+Quarter 
+9.50 
+4.80 
+7.80 
+5.95 
+Third
+Quarter 
+13.75 
+6.84 
+6.80 
+5.70 
+Fourth
+Quarter 
+8.98 
+3.25 
+6.56 
+4.70 
+No
+dividends on common stock have been declared and we do not anticipate declaring
+dividends in the foreseeable future. Our credit agreement with TD
+Banknorth, N.A. prohibits the payment of cash dividends on our common stock
+for the term of the agreement. 
+Issuer
+Purchases of Equity Securities 
+On March
+25, 2005, the Board of Directors approved a stock repurchase program (“the Stock
+Repurchase Program”). Under the Stock Repurchase Program,
+we were authorized to repurchase up to $10 million of our outstanding
+shares of common stock from time to time in the open market over a three-year
+period ending on March 25, 2008, depending on market conditions, share price and
+other factors. 
+On
+November 1, 2007, our Board of Directors approved an increase in our stock
+repurchase authorization under the Stock Repurchase Program to $15 million from
+$10 million. In addition, the Board approved a two-year extension of
+the Stock Repurchase Program to March 31, 2010. 
+10 
+Table of Contents 
+The
+following table summarizes repurchases of our common stock in the quarter ended
+December 31, 2008: 
+Period 
+Total
+Number of Shares Purchased 
+Average
+Price Paid per Share 
+Total
+Number of Shares Purchased as Part of Publicly Announced Plans or
+Programs 
+Approximate
+Dollar Value of Shares that May Yet Be Purchased under
+the Plans or Programs 
+October
+1, 2008 – October 31, 2008 
+- 
+$ 
+- 
+- 
+$ 
+7,005,000 
+November
+1, 2008 – November 30, 2008 
+130,100 
+$ 
+4.17 
+130,100 
+$ 
+6,462,000 
+December
+1, 2008 – December 31, 2008 
+- 
+$ 
+- 
+- 
+$ 
+6,462,000 
+Total 
+130,100 
+$ 
+4.17 
+130,100 
+CORPORATE
+PERFORMANCE GRAPH 
+The
+following graph compares the cumulative total return on the Company’s Common
+Stock from December 31, 2003 through December 31, 2008, with the CRSP Total
+Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer
+Manufacturer Stocks Index. The graph assumes that $100 was invested on December
+31, 2003 in each of the Company’s common stock, the CRSP Total Return Index for
+the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks
+Index, and that all dividends were reinvested. 
+COMPARISON
+OF CUMULATIVE TOTAL RETURN AMONG 
+TRANSACT
+TECHNOLOGIES INCORPORATED COMMON STOCK, 
+THE
+CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.), 
+AND
+THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX 
+12/31/03 
+12/31/04 
+12/31/05 
+12/31/06 
+12/31/07 
+12/31/08 
+TransAct
+Technologies Incorporated Common Stock 
+$ 
+100.00 
+$ 
+131.58 
+$ 
+48.67 
+$ 
+51.13 
+$ 
+29.51 
+$ 
+28.28 
+CRSP
+Total Return Index for the Nasdaq Stock Market (U.S.) 
+$ 
+100.00 
+$ 
+108.83 
+$ 
+111.14 
+$ 
+122.12 
+$ 
+132.43 
+$ 
+63.87 
+Nasdaq
+Computer Manufacturer Stocks Index 
+$ 
+100.00 
+$ 
+130.76 
+$ 
+133.80 
+$ 
+137.02 
+$ 
+199.02 
+$ 
+83.60 
+11 
+Table of Contents 
+Item 6. Selected Financial Data (in thousands, except per share
+amounts) . 
+The
+following is summarized from our audited financial statements of the past five
+years: 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+2005 
+2004 
+Consolidated
+Statement of Operations Data: 
+Net
+sales 
+$ 
+62,207 
+$ 
+48,766 
+$ 
+64,328 
+$ 
+51,091 
+$ 
+59,847 
+Gross
+profit 
+20,950 
+15,996 
+22,365 
+15,590 
+22,042 
+Operating
+expenses 
+19,089 
+19,751 
+16,277 
+15,366 
+13,591 
+Operating
+income (loss) 
+1,861 
+(3,755 
+) 
+6,088 
+224 
+8,451 
+Net
+income (loss) 
+1,444 
+(2,274 
+) 
+3,916 
+377 
+5,458 
+Net
+income (loss) per share: 
+Basic 
+0.16 
+(0.24 
+) 
+0.41 
+0.04 
+0.55 
+Diluted 
+0.15 
+(0.24 
+) 
+0.40 
+0.04 
+0.51 
+December
+31, 
+2008 
+2007 
+2006 
+2005 
+2004 
+Balance
+Sheet Data: 
+Total
+assets 
+$ 
+32,234 
+$ 
+30,414 
+$ 
+33,706 
+$ 
+29,332 
+$ 
+34,099 
+Working
+capital 
+15,051 
+11,338 
+16,643 
+15,375 
+20,511 
+Shareholders’
+equity 
+23,282 
+21,608 
+24,290 
+21,257 
+23,715 
+Item 7. Management's Discussion and Analysis of Financial Condition
+and Results of Operations. 
+This
+discussion should be read in conjunction with the Consolidated Financial
+Statements and notes thereto. 
+Forward
+Looking Statements 
+Certain
+statements included in this report, including without limitation statements in
+this Management’s Discussion and Analysis of Financial Condition and Results of
+Operations, which are not historical facts are “forward-looking statements”
+within the meaning of Section 27A of the Securities Act of 1933, as amended, and
+Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking
+statements generally can be identified by the use of forward-looking
+terminology, such as “may”, “will”, “expect”, “intend”, ”estimate”,
+“anticipate”, “believe”, “project” or “continue” or the negative thereof or
+other similar words. All forward-looking statements involve risks and
+uncertainties, including, but not limited to those listed in Item 1A of this
+Annual Report. Actual results may differ materially from those
+discussed in, or implied by, the forward-looking statements. The
+forward-looking statements speak only as of the date of this report and we
+assume no duty to update them. 
+Overview 
+2008 was
+a year of positive achievements for TransAct as compared to
+2007. During 2008, we focused on and delivered sales growth and
+delivered across the majority of our sales units, both domestically and
+internationally. During 2008, we shipped a record 196,000 printers,
+led by record sales of our Epic 950® casino printer and significantly higher
+sales of our online thermal lottery printer. Our sales success was
+also complemented by improved gross margin, operating margin and earnings per
+share. 
+We
+continue to focus on sales growth in our core markets (banking and POS, casino
+and gaming, lottery, and in our TransAct Services Group) to drive increased
+profitability. During 2008, our total net sales increased by 28% to
+approximately $62,207,000. See the table below for a breakdown of our
+sales by market. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Banking
+and POS 
+$ 
+11,866 
+19.1 
+% 
+$ 
+11,046 
+22.6 
+% 
+$ 
+820 
+7.4 
+% 
+Casino
+and gaming 
+22,299 
+35.8 
+% 
+19,438 
+39.9 
+% 
+2,861 
+14.7 
+% 
+Lottery 
+15,731 
+25.3 
+% 
+5,900 
+12.1 
+% 
+9,831 
+166.6 
+% 
+TransAct
+Services Group 
+12,311 
+19.8 
+% 
+12,382 
+25.4 
+% 
+(71 
+) 
+(0.6 
+)% 
+Total
+net sales 
+$ 
+62,207 
+100.0 
+% 
+$ 
+48,766 
+100.0 
+% 
+$ 
+13,441 
+27.6 
+% 
+12 
+Table of Contents 
+We
+experienced an increase of approximately 7% in sales of Banking and POS printers
+in 2008. Sales of our Bankjet® line of inkjet bank teller printers
+increased due to incremental sales of our first generation BANKjet® 1500 bank
+teller printer as well as initial sales of our newly-launched, next generation
+BANKjet® 2500 bank teller printer. In addition to higher banking
+printer sales, we also experienced a slight increase in sales from our line of
+POS printers due primarily to sales of our two new printer products for
+McDonalds – (1) the Ithaca® 8000 thermal receipt/label printer which will be
+used to print either a receipt at the front counter or a label at the grill
+station and (2) the Ithaca ® 8040 label printer which will be used to print
+labels for McDonalds new combined beverage initiative. Sales of our
+legacy line of POS impact printers, as these printers continue to be replaced by
+our newer thermal and inkjet printers. We expect sales of our legacy
+POS impact printers to continue to decline during 2009, as these printers
+continue to be replaced by our newer thermal and inkjet
+printers. 
+In our
+casino and gaming market, our focus lies primarily in supplying printers for use
+in slot machines at casinos and racetracks, as well as in other gaming devices
+that print tickets or receipts, primarily in the United States, Europe and
+Australia, as well as in the emerging Asian market, including
+Macau. During 2008, despite a weak domestic casino market, our
+domestic casino and gaming printer sales increased by 12% from 2007 due largely
+to International Game Technologies (“IGT”) awarding us default status as default
+printer provider, which began in April of 2008. Internationally,
+casino and gaming printer sales increased by 20% to $7.9 million, largely due to
+sales growth of our off-premise gaming printers to Europe. 
+On the
+lottery side, we continue to hold a leading position based on our long-term
+purchase agreement with Lottomatica’s GTECH Corporation (“GTECH”), our largest
+customer and the world’s largest provider of lottery terminals, with
+approximately a 70% market share. GTECH has been our customer since
+1995, and we continue to maintain a good relationship with them. In
+fact, our contract with GTECH continues through 2012. Currently, we
+fulfill substantially all of GTECH’s printer requirements for lottery terminal
+installations and upgrades worldwide. During 2008, we experienced a
+record level of sales compared to historical sales levels from GTECH, with total
+printer sales increasing by approximately $9,987,000, or 189%, compared to
+2007. However, our sales to GTECH each year are directly dependent on
+the timing and number of new and upgraded lottery terminal installations GTECH
+performs. Our sales to GTECH are not indicative of GTECH’s overall
+business or revenue. 
+Our
+TransAct Services Group (“TSG”), which sells service, replacement parts and
+consumable products, including receipt paper, ribbons and inkjet cartridges,
+continues to offer a substantial growth opportunity and recurring revenue stream
+for TransAct. Even with declining sales of replacement parts for
+legacy impact printers as the installed base of these printers in the market
+declines, TSG domestic revenue continued to increase in 2008 by 17% from
+2007. During 2008, our domestic sales benefited from higher inkjet
+cartridge sales resulting from the previously signed agreement with a leading
+national office supply chain to supply inkjet cartridges in 2006 as well as
+expanding sales of paper and other consumable products through our e-commerce
+website, TransActSupplies.com. Internationally, TSG sales declined
+due to the decrease in maintenance and repair services revenue from a service
+contract with a single customer in the United Kingdom. The service
+contract, which represented a substantial portion of our U.K. subsidiary’s
+revenue in 2007, ended in November 2007 and was not renewed, as the customer
+replaced our printers with newer technology that we were unable to
+provide. 
+Operationally,
+both our gross margin and operating margin showed marked improvement from
+2007. During 2008, our gross margin increased to 33.7% compared to
+32.8% in 2007, due primarily to higher sales volume combined with lower product
+costs and increased absorption of certain manufacturing overhead expenses as we
+continue to transfer our domestic, in-house production of our products to a
+lower cost contract manufacturer in China. Our operating margin also
+increased to 3.0% in 2008 compared to (7.7%) in 2007, as our operating expenses
+decreased by 3% due to cost reduction programs we put in place at the end of
+2007 and our sales increased by 28%. 
+Overall,
+we reported net income of $1.4 million and net income per share (diluted) of
+$0.15 per share for 2008. We also utilized cash during 2008 to fund
+$979,000 of capital expenditures and repurchase $543,000 of our common stock,
+and we finished the year with $2.0 million of cash and no debt on our balance
+sheet as of December 31, 2008. 
+Critical
+Accounting Policies and Estimates 
+Our
+discussion and analysis of our financial condition and results of operations are
+based upon our consolidated financial statements, which have been prepared by us
+in accordance with accounting principles generally accepted in the United States
+of America. These principles require the use of estimates, judgments
+and assumptions. Such estimates and judgments are based upon
+historical experience and certain assumptions that are believed to be reasonable
+in the particular circumstances. Those judgments affect both balance
+sheet items and income statement categories. Our estimates include
+those related to revenue recognition, allowance for doubtful accounts, inventory
+obsolescence, the valuation of deferred tax assets and liabilities, goodwill
+impairment, warranty obligations, restructuring accruals, share-based
+compensation and contingent liabilities. We evaluate our assumptions
+on an ongoing basis by comparing actual results with our
+estimates. Actual results may differ from the original
+estimates. The following accounting policies are those that we
+believe to be most critical in the preparation of our financial
+statements. 
+13 
+Table of Contents 
+Revenue
+Recognition – Our typical contracts include the sale of printers, which
+are sometimes accompanied by separately-priced extended warranty
+contracts. We also sell spare parts, consumables, and other repair
+services (sometimes pursuant to multi-year product maintenance contracts), which
+are not included in the original printer sale and are ordered by the customer as
+needed. We recognize revenue pursuant to the guidance within SAB 104,
+“Revenue Recognition.” Specifically, revenue is recognized when
+evidence of an arrangement exists, delivery (based on shipping terms which are
+generally FOB shipping point) has occurred, the selling price is fixed and
+determinable, and collectablity is reasonably assured. We provide for
+an estimate of product returns and price protection based on historical
+experience at the time of revenue recognition. 
+Revenue
+related to extended warranty and product maintenance contracts is recognized
+pursuant to FASB Technical Bulletin 90-1 (“FTB 90-1”), “Accounting for
+Separately Priced Extended Warranty and Product Maintenance
+Contracts.” Pursuant to FTB 90-1, revenue related to separately
+priced product maintenance contracts is deferred and recognized over the term of
+the maintenance period. We record deferred revenue for advance
+payments received from customers for maintenance contracts. 
+Our
+customers have the right to return products that do not function properly within
+a limited time after delivery. We monitor and track product returns
+and record a provision for the estimated future returns based on historical
+experience. Returns have historically been within expectations and
+the provisions established, but we cannot guarantee that we will continue to
+experience return rates consistent with historical patterns. 
+We offer
+some of our customer’s price protection as an incentive to carry inventory of
+our product. These price protection plans provide that if we lower
+prices, we will credit them for the price decrease on inventory they
+hold. Our customers typically carry limited amounts of inventory, and
+we infrequently lower prices on current products. As a result, the
+amounts paid under these plans have not been material. However, we
+cannot guarantee that this minimal level will continue. 
+We charge
+our customers for shipping and handling services. The amounts billed
+to customers are recorded as revenue when the product ships. Any
+costs incurred related to these services are included in cost of
+sales. 
+Accounts
+Receivable – We
+have standardized credit granting and review policies and procedures for all
+customer accounts, including: credit reviews of all new customer accounts;
+ongoing credit evaluations of current customers; credit limits and payment terms
+based on available credit information; and adjustments to credit limits based
+upon payment history and the customer’s current creditworthiness. We
+also provide an estimate of doubtful accounts based on historical experience and
+specific customer collection issues. Our allowance for doubtful
+accounts as of December 31, 2008 was $55,000, or less than 1.0% of outstanding
+accounts receivable, which we feel is appropriate considering the overall
+quality of our accounts receivable. While credit losses have
+historically been within expectations and the reserves established, we cannot
+guarantee that our credit loss experience will continue to be consistent with
+historical experience. As of December 31, 2008, we had accounts
+receivable balances due from two customers of approximately 20% and 10%,
+respectively, of the total balance due, and no other customer accounts
+receivable balance exceeded 10%. As of December 31, 2007, we had
+accounts receivable balances due from three customers of 13%, 12% and 10% of the
+total balance due, respectively, and no other customer accounts receivable
+balance exceeded 10%. 
+Inventory – Our inventories are stated
+at the lower of cost (principally standard cost, which approximates actual cost
+on a first-in, first-out basis) or market. We review market value
+based on historical usage and estimates of future demand. Assumptions
+are reviewed at least quarterly and adjustments are made, as necessary, to
+reflect changing market conditions. Based on these reviews, inventory
+write-downs are recorded, as necessary, to reflect estimated obsolescence,
+excess quantities and market value. Should circumstances change and
+we determine that additional inventory is subject to obsolescence, additional
+write-downs of inventory could result in a charge to income. As of
+December 31, 2008, our net inventory included a reserve of $3,050,000, or 23.5%
+of gross inventory, to write inventory down to lower of cost or
+market. 
+Goodwill – We test the impairment of
+goodwill each year or more frequently if events or changes in circumstances
+indicate that the carrying value may not be recoverable. We completed
+our last assessment as of December 31, 2008. Factors considered that
+may trigger an impairment review are: significant underperformance relative to
+expected historical or projected future operating results; significant changes
+in the manner of use of acquired assets or the strategy for the overall
+business; significant negative industry or economic trends; and significant
+decline in market capitalization relative to net book value. Goodwill
+amounted to $1,469,000 at December 31, 2008 and we have determined that no
+goodwill impairment has occurred. 
+Income
+Taxes – In
+preparing our consolidated financial statements, we are required to estimate
+income taxes in each of the jurisdictions in which we operate. This
+involves estimating the actual current tax exposure together with assessing
+temporary differences between the tax basis of certain assets and liabilities
+and their reported amounts in the financial statements, as well as net operating
+losses, tax credits and other carryforwards. These differences result
+in deferred tax assets and liabilities, which are included within our
+consolidated balance sheets. We then assess the likelihood that the
+deferred tax assets will be realized from future taxable income, and to the
+extent that we believe that realization is not likely, we establish a valuation
+allowance. 
+14 
+Table of Contents 
+Significant
+judgment is required in determining the provision for income taxes and, in
+particular, any valuation allowance or tax reserves with respect to our deferred
+tax assets and uncertain tax positions. On a quarterly basis, we
+evaluate the recoverability of our deferred tax assets based upon historical
+results and forecasted taxable income over future years, and match this forecast
+against the basis differences, deductions available in future years and the
+limitations allowed for net operating loss and tax credit carryforwards to
+ensure that there is adequate support for the realization of the deferred tax
+assets. While we have considered future taxable income and ongoing prudent and
+feasible tax planning strategies in assessing the need for a valuation allowance
+or tax reserve, in the event we were to determine that we would not be able to
+realize all or part of our deferred tax assets in the future, an adjustment to
+the valuation allowance or tax reserves would be charged as a reduction to
+income in the period such determination was made. Likewise, should we
+determine that we would be able to realize future deferred tax assets in excess
+of its net recorded amount, an adjustment to the valuation allowance or tax
+reserves would increase net income in the period such determination was
+made. 
+In July
+2006, the Financial Accounting Standards Board (the “FASB”) issued
+Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an
+interpretation of FASB Statement No. 109, (“FIN 48”). Among other things, FIN 48
+prescribes a minimum recognition threshold that an income tax position must meet
+before it is recorded in the reporting entity’s financial statements. FIN 48
+requires that the effects of such income tax positions be recognized only if, as
+of the balance sheet reporting date, it is “more likely than not” (i.e., more
+than a 50% likelihood) that the income tax position will be sustained based
+solely on its technical merits. When making this assessment,
+management must assume that the responsible taxing authority will examine the
+income tax position and have full knowledge of all relevant facts and other
+pertinent information. The new accounting guidance also clarifies the
+method of accruing for interest and penalties when there is a difference between
+the amount claimed, or expected to be claimed, on a company’s income tax returns
+and the benefits recognized in the financial
+statements. Additionally, FIN 48 requires significant new and
+expanded footnote disclosures in all annual periods. 
+We
+adopted FIN 48 with an effective date of January 1,
+2007. Retrospective application of FIN 48 was
+prohibited. As a result of the implementation, we recognized a
+decrease to reserves for uncertain tax positions. This decrease was
+accounted for as a $318,000 adjustment to the beginning balance of retained
+earnings on the
+Consolidated Balance Sheet as of December 31, 2007 . 
+As of
+December 31, 2008, we recorded a net deferred tax asset of approximately
+$3,813,000 and a tax reserve of $44,000, primarily on portions of certain tax
+credits. We will need to recognize approximately $10.9 million in
+future taxable income in order to realize all of our deferred tax assets at
+December 31, 2008. In one of the last three years, we have had U.S.
+taxable losses and there is no assurance that we will generate future taxable
+income sufficient to realize all of our deferred tax assets. However,
+based on our current projection of future taxable income as of December 31,
+2008, no valuation allowance is considered necessary. Should
+circumstances change and we determine that some or all of the deferred taxes
+would not be realized, a valuation allowance would be recorded, resulting in a
+charge to income in the period such determination is made. 
+Restructuring 
+– In February 2001, we announced plans to establish a global engineering and
+manufacturing center at our Ithaca, NY facility. As part of this
+strategic decision, we undertook a plan to consolidate all manufacturing and
+engineering into our existing Ithaca, NY facility and close our Wallingford, CT
+manufacturing facility (the “Consolidation”). As of December 31,
+2001, we successfully transferred substantially all our Wallingford operations
+to Ithaca, NY, with the exception of our corporate headquarters and a service
+center that remains in Connecticut. The closing of the Wallingford
+manufacturing facility resulted in the termination of employment of
+approximately 70 production, administrative and management
+employees. 
+In
+connection with the Consolidation of manufacturing facilities in 2001, we
+recorded significant accruals. Through December 31,
+2007, we recognized approximately $5.5 million of expenses associated with the
+Consolidation, including severance pay, stay bonuses, employee benefits, moving
+expenses, non-cancelable lease payments, and other costs. Management has made
+reasonable estimates of such costs and expenses. During November
+2006, we executed an agreement, effective May 1, 2007, to terminate the lease
+agreement for our Wallingford, CT facility. As a result, we changed
+our estimate of the restructuring accrual and reversed approximately $479,000 of
+restructuring expenses in 2006. During the second quarter of 2007, we
+recorded an additional $12,000 of expense to finalize the termination of the
+lease agreement. As of September 30, 2007, all non-cancelable lease
+payments related to our Wallingford, CT facility have been made and we do not
+expect to incur any additional restructuring expenses related to the
+Consolidation. 
+Warranty – We generally warrant our
+products for up to 24 months and record the estimated cost of such product
+warranties at the time the sale is recorded. Estimated warranty costs
+are based upon actual past experience of product repairs and the related
+estimated cost of labor and material to make the necessary
+repairs. If actual future product repair rates or the actual costs of
+material and labor differ from the estimates, adjustments to the accrued
+warranty liability and related warranty expense would be made. 
+Contingencies – We record an estimated
+liability related to contingencies based on our estimates of the probable
+outcomes pursuant to FAS 5. On a quarterly basis, we assess the
+potential liability related to pending litigation, audits and other
+contingencies and confirm or revise estimates and reserves as
+appropriate. If the actual liabilities are settled in an amount
+greater than those recorded on the balance sheet, a change to income would be
+recorded. 
+15 
+Table of Contents 
+Share-Based
+Compensation –
+We calculate share-based compensation expense in accordance with SFAS
+123(R), “Share-Based Payment (as amended)” using the Black-Scholes
+option-pricing model to calculate the fair value of share-based
+awards. The key assumptions for this valuation method include the
+expected term of an option grant, and the stock price volatility, risk-free
+interest rate, dividend yield, and forfeiture rate. The determination
+of these assumptions is based on past history and future expectations, and is
+subject to a high level of judgment. To the extent any of the
+assumptions were to change from year to year, the fair value of new option
+grants may vary significantly. 
+Results
+of Operations: Year ended December 31, 2008 compared to year ended December 31,
+2007 
+Net
+Sales. Net sales, which include printer sales and sales of
+spare parts, consumables and repair services, by market for the years ended
+December 31, 2008 and 2007 were as follows: 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Banking
+and POS 
+$ 
+11,866 
+19.1 
+% 
+$ 
+11,046 
+22.6 
+% 
+$ 
+820 
+7.4 
+% 
+Casino
+and gaming 
+22,299 
+35.8 
+% 
+19,438 
+39.9 
+% 
+2,861 
+14.7 
+% 
+Lottery 
+15,731 
+25.3 
+% 
+5,900 
+12.1 
+% 
+9,831 
+166.6 
+% 
+TransAct
+Services Group 
+12,311 
+19.8 
+% 
+12,382 
+25.4 
+% 
+(71 
+) 
+(0.6 
+)% 
+$ 
+62,207 
+100.0 
+% 
+$ 
+48,766 
+100.0 
+% 
+$ 
+13,441 
+27.6 
+% 
+International* 
+$ 
+10,126 
+16.3 
+% 
+$ 
+10,795 
+22.1 
+% 
+$ 
+(669 
+) 
+(6.2 
+)% 
+* 
+International
+sales do not include sales of printers made to domestic distributors or
+other domestic customers who may in turn ship those printers to
+international destinations. 
+Net sales
+for 2008 increased $13,441,000, or 28%, from 2007 due to sales increases in
+three out of four of our markets: banking and point of sale (“POS”)
+(an increase of approximately $820,000, or 7%), casino and gaming (an increase
+of approximately $2,861,000, or 15%) and lottery (an increase of approximately
+$9,831,000 or 167%). Sales from our TransAct Services Group (“TSG”)
+decreased by approximately $71,000, or less than 1%. 
+Overall, international
+sales decreased by $669,000, or 6%. The decrease in international
+sales was due largely to the expiration in November 2007 of a service contract
+with a single customer in the United Kingdom. 
+Banking and point of
+sale : Revenue
+from the banking and POS market includes sales of printers used by banks, credit
+unions and other financial institutions to print and/or validate receipts at
+bank teller stations. Revenue from this market also includes sales of
+inkjet, thermal and impact printers used primarily by retailers in restaurant
+(including fine dining, casual dining and fast food), hospitality, and specialty
+retail stores to print receipts for consumers, validate checks, or print on
+other inserted media. Sales of our banking and POS printers worldwide
+increased approximately $820,000, or 7%, from 2007. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Domestic 
+$ 
+10,664 
+89.9 
+% 
+$ 
+9,775 
+88.5 
+% 
+$ 
+889 
+9.1 
+% 
+International 
+1,202 
+10.1 
+% 
+1,271 
+11.5 
+% 
+(69 
+) 
+(5.4 
+)% 
+$ 
+11,866 
+100.0 
+% 
+$ 
+11,046 
+100.0 
+% 
+$ 
+820 
+7.4 
+% 
+Domestic
+banking and POS printer sales increased to $10,664,000, representing an
+$889,000, or 9%, increase from 2007. Banking printer sales increased
+by approximately $610,000 due largely to incremental sales of our first
+generation BANKjet® 1500 bank teller printer as well as new product sales of our
+BANKjet® 2500 bank teller printer in 2008 compared to 2007. Although
+we are currently pursuing several banking opportunities, due to the
+project-oriented nature of these sales, and the current credit crisis that we
+believe is negatively impacting the banking industry’s level of capital
+expenditures, we cannot predict the level of future sales. Our
+increased banking printer sales were also complemented by new product sales of
+our new Ithaca® 8000 and Ithaca® 8040 thermal receipt/label printers for
+McDonalds. We also experienced lower sales of our legacy impact
+printers, as expected, during 2008 compared to 2007, as these printers continue
+to be replaced by our thermal and inkjet printers. 
+16 
+Table of Contents 
+International
+banking and POS printer shipments decreased by approximately $69,000, or 5%, to
+$1,202,000, due primarily to lower sales to our international POS
+distributors in Europe and Asia, largely offset by an increase in printer sales
+to our international POS distributors in Latin America. 
+Casino and gaming : Revenue
+from the casino and gaming market includes sales of printers used in slot
+machines, video lottery terminals (“VLTs”) and other gaming machines that print
+tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”)
+at casinos, racetracks (“racinos”) and other gaming venues
+worldwide. Sales of our casino and gaming printers increased by
+$2,861,000, or 15%, from 2007, due to increased sales of our thermal casino
+and gaming printers both domestically and internationally. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Domestic 
+$ 
+14,355 
+64.4 
+% 
+$ 
+12,798 
+65.8 
+% 
+$ 
+1,557 
+12.2 
+% 
+International 
+7,944 
+35.6 
+% 
+6,640 
+34.2 
+% 
+1,304 
+19.6 
+% 
+$ 
+22,299 
+100.0 
+% 
+$ 
+19,438 
+100.0 
+% 
+$ 
+2,861 
+14.7 
+% 
+Domestic
+sales of our casino and gaming printers increased by $1,557,000, or 12%, despite
+a weak domestic casino market, due largely to an increase in domestic sales
+of our thermal casino printers, including incremental sales beginning in
+the second quarter of 2008 resulting from our new status as default printer
+provider to International Game Technology (“IGT”). We expect the
+domestic casino and gaming market to continue to be weak into 2009 as we believe
+the current uncertain economic environment is negatively impacting the casino
+industry’s level of capital expenditures. In light of these negative
+market conditions, our future sales to the domestic casino and gaming market may
+be unpredictable and adversely affected. 
+International
+casino and gaming printer sales increased $1,304,000, or 20%, to $7,944,000 in
+2008 compared to 2007. International sales represented 36% and 34% of
+total sales into our casino and gaming market during 2008 and 2007,
+respectively. This increase was due primarily to increased sales
+of our casino and gaming printers in Europe, including growing sales of our new
+off-premise gaming printers, as well as increased international casino printer
+sales to Australia. 
+Lottery: Revenue
+from the lottery market includes sales of lottery printers to Lottomatica’s
+GTECH Corporation (“GTECH”), the world’s largest provider of lottery terminals,
+for various lottery applications. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Domestic 
+$ 
+15,283 
+97.2 
+% 
+$ 
+5,297 
+89.8 
+% 
+$ 
+9,986 
+188.5 
+% 
+International 
+448 
+2.8 
+% 
+603 
+10.2 
+% 
+(155 
+) 
+(25.7 
+)% 
+$ 
+15,731 
+100.0 
+% 
+$ 
+5,900 
+100.0 
+% 
+$ 
+9,831 
+166.6 
+% 
+Domestic
+and international lottery printer sales to GTECH, which include thermal on-line
+and other lottery printers, increased by approximately $9,831,000, or 167%, in
+2008 compared to 2007, with domestic sales increasing by approximately
+$9,986,000 and international sales declining by approximately
+$155,000. Our sales to GTECH are directly dependent on the timing and
+number of new and upgraded lottery terminal installations GTECH performs, and as
+a result, may fluctuate significantly quarter-to-quarter and
+year-to-year. Our sales to GTECH are not indicative of GTECH’s
+overall business or revenue. We expect total sales to GTECH for 2009
+to be lower than those reported during 2008. 
+TransAct Services
+Group : Revenue from the
+TransAct Services Group (“TSG”) includes sales of consumable products (inkjet
+cartridges, ribbons, receipt paper and other transaction-related supplies),
+replacement parts, maintenance and repair services, refurbished printers, and
+shipping and handling charges. Sales from TSG decreased by
+approximately $71,000, or less than 1% from 2007. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Domestic 
+$ 
+11,779 
+95.7 
+% 
+$ 
+10,101 
+81.6 
+% 
+$ 
+1,678 
+16.6 
+% 
+International 
+532 
+4.3 
+% 
+2,281 
+18.4 
+% 
+(1,749 
+) 
+(76.7 
+)% 
+$ 
+12,311 
+100.0 
+% 
+$ 
+12,382 
+100.0 
+% 
+$ 
+(71 
+) 
+(0.6 
+)% 
+17 
+Table of Contents 
+Domestic
+revenue from TSG increased by approximately $1,678,000, or 17%, to $11,779,000,
+largely due to increased sales of consumable products, including higher sales
+of inkjet cartridges as well as growing sales of paper and other
+consumable products through our new e-commerce website, www.TransActSupplies.com . 
+The increase in domestic TSG revenue was also due, to a lesser extent, to
+higher maintenance and repair services revenue for 2008 as we renewed and
+expanded existing contracts for our service products including extended
+warranty contracts and our 24-hour guaranteed replacement product service
+called TransAct Xpress™. These increases were partially offset by a
+decline in the sales of replacement parts for certain legacy printers,
+as the installed base of these legacy printers in the market continues to
+decline. 
+Internationally,
+TSG sales decreased by approximately $1,749,000, or 77%, to $532,000, due
+largely to a decrease in maintenance and repair services revenue from a
+service contract with a single customer in the United Kingdom. The service
+contract, which represented a substantial portion of our U.K. subsidiary’s
+revenue in 2007, ended in November 2007 and was not renewed, as the customer
+replaced our printers with newer technology that we were unable to
+provide. 
+Gross
+Profit. Gross profit information is summarized below (in thousands,
+except percentages): 
+December
+31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2008 
+2007 
+Change 
+Total
+Sales - 2008 
+Total
+Sales - 2007 
+Year
+ended 
+$ 
+20,950 
+$ 
+15,996 
+31.0 
+% 
+33.7 
+% 
+32.8 
+% 
+Gross
+profit is measured as revenue less cost of goods sold. Cost of goods
+sold includes primarily the cost of all raw materials and component parts,
+direct labor, and the associated manufacturing overhead
+expenses. Gross profit and gross margin increased due primarily to a
+higher volume of sales and lower component part and labor costs resulting
+from our initiatives to increasingly move production of our products to Asia,
+somewhat offset by a less favorable sales mix. Gross
+profit for 2008 was also favorably impacted by approximately
+$195,000 of increased absorption of certain manufacturing overhead
+expenses due to
+the transition of more of our production to China compared to 2007. 
+Gross profit for 2007 was negatively impacted by an incremental inventory
+reserve charge of approximately $528,000, or 1.1% of net sales in 2007,
+specifically related to certain obsolete electronic components and certain
+discontinued printer products. 
+Engineering and
+Product Development. Engineering and product development information
+is summarized below (in thousands, except percentages): 
+December
+31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2008 
+2007 
+Change 
+Total
+Sales - 2008 
+Total
+Sales – 2007 
+Year
+ended 
+$ 
+2,942 
+$ 
+3,129 
+(6.0 
+)% 
+4.7 
+% 
+6.4 
+% 
+Engineering,
+design and product development expenses primarily include salary and payroll
+related expenses for our engineering staff, depreciation and design expenses
+(including prototype printer expenses, outside design and testing services and
+supplies). Such expenses for 2008 decreased by $187,000 or 6.0%, due
+to lower outside design, prototype, development and professional consulting
+related expenses partially offset by higher employee compensation related
+expenses. Engineering and product development expenses decreased as a
+percentage of net sales due primarily to higher sales volume coupled with a
+lower level of expenses in 2008 compared to 2007. 
+Selling and
+Marketing. Selling and marketing information is summarized below (in
+thousands, except percentages): 
+December
+31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2008 
+2007 
+Change 
+Total
+Sales - 2008 
+Total
+Sales - 2007 
+Year
+ended 
+$ 
+6,078 
+$ 
+6,708 
+(9.4 
+)% 
+9.8 
+% 
+13.8 
+% 
+Selling
+and marketing expenses primarily include salaries and payroll related expenses
+for our sales and marketing staff, sales commissions, travel expenses, expenses
+associated with the lease of sales offices, advertising, trade show expenses and
+other promotional marketing expenses. Selling and marketing expenses
+decreased primarily due to a reduced level of sales staff related expenses
+resulting from the cost reduction actions we took in late 2007 as well as lower
+promotional marketing expenses. Selling and marketing expenses
+decreased as a percentage of net sales due primarily to higher sales volume
+coupled with a lower level of expenses in 2008 compared to 2007. 
+18 
+Table of Contents 
+General and
+Administrative. General and administrative information is summarized
+below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2008 
+2007 
+Change 
+Total
+Sales - 2008 
+Total
+Sales - 2007 
+Year
+ended 
+$ 
+7,040 
+$ 
+6,995 
+0.6 
+% 
+11.3 
+% 
+14.3 
+% 
+General
+and administrative expenses primarily include: salaries and payroll related
+expenses for our executive, accounting, human resource, business development and
+information technology staff, expenses for our corporate headquarters,
+professional and legal expenses, telecommunication expenses, and other expenses
+related to being a publicly-traded company. General and
+administrative expenses increased by $45,000, or less than 1%, due primarily to
+(1) higher incentive compensation expenses, (2) compensation and travel expenses
+related to the hiring of our new Vice President of Business Development in May
+2008 and (3) the full year effect of increased rent and facility-related
+expenses, including depreciation expense on purchases of office furniture
+and leasehold improvements for our new corporate headquarters in Hamden, CT that
+we moved into during the second quarter of 2007. These increases were
+partially offset by lower legal expenses related to general
+corporate matters, recruitment related expenses, and professional
+fees. General and administrative expenses decreased as a percentage of net
+sales due primarily to higher sales volume in 2008 compared to
+2007. 
+Legal Fees
+associated with lawsuit. During
+2008, we incurred approximately $3,029,000 of legal fees related to the settled
+lawsuit with FutureLogic, Inc. compared to $2,907,000 in 2007. The
+substantial increase was due to the settlement of our litigation with
+FutureLogic, Inc. in May 2008. As a result of the settlement, we do
+not expect to incur any additional legal fees related to the
+lawsuit. 
+Operating Income
+(Loss). Operating income (loss) information is summarized below (in
+thousands, except percentages): 
+December 31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2008 
+2007 
+Change 
+Total
+Sales - 2008 
+Total
+Sales - 2007 
+Year
+ended 
+$ 
+1,861 
+$ 
+(3,755 
+) 
+NM 
+3.0 
+% 
+(7.7 
+)% 
+During
+2008, the substantial increase in our operating income and operating margin was
+due largely to higher sales and the resulting higher gross profit and lower
+operating expenses in 2008 compared to that of 2007. 
+Interest. We
+recorded net interest expense of $11,000 in 2008 compared to net interest income
+of $76,000 in 2007. The decrease in our net interest income was
+largely due to a lower average cash balance in 2008 as compared to 2007, coupled
+with a lower overall rate of return on our invested cash balance due to the
+decreasing interest rate environment. See “Liquidity and Capital
+Resources” below for more information. 
+Other
+Income. We recorded other income of $368,000 in 2008 compared
+to other income of $21,000 in 2007. The increase was due primarily to
+transaction exchange gains recorded by our UK subsidiary resulting from the
+significant strengthening of the U.S. dollar against the British pound primarily
+in the third and fourth quarters of 2008. 
+Income
+Taxes. We recorded an income tax provision of $774,000, at an
+effective rate of 34.9% during 2008 compared to an income tax benefit of
+$1,384,000, at an effective rate of 37.8% in 2007. The effective tax
+rate for 2008 decreased compared to 2007 due largely to a decrease in the
+recognition of certain deferred tax credits. We expect our annual
+effective tax rate for 2009 to be approximately 35%. 
+Net Income
+(Loss) . We reported net
+income in 2008 of $1,444,000, or $0.15 per diluted share compared to a net loss
+of $(2,274,000), or $(0.24) per diluted share in 2007. 
+19 
+Table of Contents 
+Results
+of Operations: Year ended December 31, 2007 compared to year ended December 31,
+2006 
+Net
+Sales. Net
+sales, which include printer sales and sales of spare parts, consumables and
+repair services, by market for the years ended December 31, 2007 and 2006 were
+as follows: 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2007 
+December
+31, 2006 
+$ 
+% 
+Banking
+and POS 
+$ 
+11,046 
+22.6 
+% 
+$ 
+16,858 
+26.2 
+% 
+$ 
+(5,812 
+) 
+(34.5 
+)% 
+Casino
+and gaming 
+19,438 
+39.9 
+% 
+23,246 
+36.1 
+% 
+(3,808 
+) 
+(16.4 
+)% 
+Lottery 
+5,900 
+12.1 
+% 
+11,431 
+17.8 
+% 
+(5,531 
+) 
+(48.4 
+)% 
+TransAct
+Services Group 
+12,382 
+25.4 
+% 
+12,793 
+19.9 
+% 
+(411 
+) 
+(3.2 
+)% 
+$ 
+48,766 
+100.0 
+% 
+$ 
+64,328 
+100.0 
+% 
+$ 
+(15,562 
+) 
+(24.2 
+)% 
+International* 
+$ 
+10,795 
+22.1 
+% 
+$ 
+14,138 
+22.0 
+% 
+$ 
+(3,343 
+) 
+(23.6 
+)% 
+* 
+International
+sales do not include sales of printers made to domestic distributors or
+other domestic customers who may in turn ship those printers to
+international destinations. 
+Net sales
+for 2007 decreased $15,562,000, or 24%, from 2006 due to sales decreases in each
+of our four markets: banking and point of sale (“POS”) (a decrease of
+approximately $5,812,000, or 35%), casino and gaming (a decrease of
+approximately $3,808,000, or 16%), lottery (a decrease of approximately
+$5,531,000, or 48%), and TSG (a decrease of approximately $411,000, or 3%).
+Overall, international sales decreased by $3,343,000, or 24%, due largely to
+lower international shipments of our banking and POS, casino and gaming,
+and lottery printers, and to a lesser extent, decreased TSG
+sales internationally. 
+Banking and point of
+sale : Sales of our banking and POS printers worldwide
+decreased approximately $5,812,000, or 35%, from 2006. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2007 
+December
+31, 2006 
+$ 
+% 
+Domestic 
+$ 
+9,775 
+88.5 
+% 
+$ 
+15,410 
+91.4 
+% 
+$ 
+(5,635 
+) 
+(36.6 
+)% 
+International 
+1,271 
+11.5 
+% 
+1,448 
+8.6 
+% 
+(177 
+) 
+(12.2 
+)% 
+$ 
+11,046 
+100.0 
+% 
+$ 
+16,858 
+100.0 
+% 
+$ 
+(5,812 
+) 
+(34.5 
+)% 
+Domestic
+banking and POS printer sales decreased to $9,775,000, representing a
+$5,635,000, or 37%, decrease from 2006, due largely to the non-recurrence
+of significant sales (approximately $2.6 million) of our BANKjet® line of inkjet
+bank teller printers to two large banking customers that were made in 2006.
+In addition to lower banking printer sales, we also experienced a decline
+in sales from our line of POS thermal printers due primarily to a large
+hospitality customer that slowed and deferred equipment purchases while it
+implemented a new point-of-sale software system. We also experienced a
+decline in sales of our legacy line of POS impact printers as these
+printers are replaced by our newer thermal and inkjet printers. Our
+sales into the banking and POS market over the last several years have been
+impacted by a shift in technology in the market from impact
+printing technology to thermal and inkjet printing technology. This
+change in technology has resulted in declining sales of our impact printers that
+were at higher average selling prices and increasing sales of our thermal
+and inkjet printers that are at lower average selling prices. 
+International
+banking and POS printer shipments decreased by approximately $177,000, or 12%,
+to $1,271,000, due primarily to lower sales to our international POS
+distributors in Latin America and Europe. 
+Casino and
+gaming : Sales of our casino and gaming printers decreased by
+$3,808,000, or 16%, from 2006, primarily due to lower casino and other gaming
+printer sales, both domestically and internationally. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2007 
+December
+31, 2006 
+$ 
+% 
+Domestic 
+$ 
+12,798 
+65.8 
+% 
+$ 
+14,848 
+63.9 
+% 
+$ 
+(2,050 
+) 
+(13.8 
+)% 
+International 
+6,640 
+34.2 
+% 
+8,398 
+36.1 
+% 
+(1,758 
+) 
+(20.9 
+)% 
+$ 
+19,438 
+100.0 
+% 
+$ 
+23,246 
+100.0 
+% 
+$ 
+(3,808 
+) 
+(16.4 
+)% 
+20 
+Table of Contents 
+Domestic
+sales of our casino and gaming printers decreased by $2,050,000, or 14%, due
+primarily to a decrease in sales of our thermal casino printers due to continued
+softness in the domestic casino market during 2007 as compared to
+2006. 
+International
+casino and gaming printer sales decreased $1,758,000, or 21%, to $6,640,000 in
+2007 compared to 2006. Such sales represented 34% and 36% of total
+sales into our casino and gaming market during 2007 and 2006, respectively.
+This decrease was primarily due to lower international gaming printer
+sales, primarily in Australia due to a slower than anticipated conversion to
+ticket-in, ticket-out slot machines in that region, partially offset by
+higher sales in Europe and Asia. 
+Lottery: Sales of our
+lottery printers decreased by $5,531,000, or 48%, from 2006, primarily due
+to lower sales of lottery printers to GTECH, both domestically and
+internationally. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2007 
+December
+31, 2006 
+$ 
+% 
+Domestic 
+$ 
+5,297 
+89.8 
+% 
+$ 
+10,350 
+90.5 
+% 
+$ 
+(5,053 
+) 
+(48.8 
+)% 
+International 
+603 
+10.2 
+% 
+1,081 
+9.5 
+% 
+(478 
+) 
+(44.2 
+)% 
+$ 
+5,900 
+100.0 
+% 
+$ 
+11,431 
+100.0 
+% 
+$ 
+(5,531 
+) 
+(48.4 
+)% 
+Domestic
+and international printer sales to GTECH, which include thermal on-line and
+other lottery printers, decreased by approximately $5,531,000, or 48%, in
+2007 compared to 2006, with domestic sales declining approximately $5,053,000
+and international sales declining approximately $478,000. Our sales
+to GTECH are directly dependent on the timing and number of new and upgraded
+lottery terminal installations GTECH performs, and as a result, may
+fluctuate significantly quarter-to-quarter. Our sales to GTECH are not
+indicative of GTECH’s overall business or revenue. 
+TransAct Services
+Group : Sales by TSG decreased by approximately $411,000, or
+3%. 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2007 
+December
+31, 2006 
+$ 
+% 
+Domestic 
+$ 
+10,101 
+81.6 
+% 
+$ 
+9,582 
+74.9 
+% 
+$ 
+519 
+5.4 
+% 
+International 
+2,281 
+18.4 
+% 
+3,211 
+25.1 
+% 
+(930 
+) 
+(29.0 
+)% 
+$ 
+12,382 
+100.0 
+% 
+$ 
+12,793 
+100.0 
+% 
+$ 
+(411 
+) 
+(3.2 
+)% 
+Domestic
+TSG revenue increased by approximately $519,000, or 5%, to $10,101,000, largely
+due to increased sales of consumable products, including higher sales of
+inkjet cartridges as we benefited from the agreement we signed in August 2006 to
+supply inkjet cartridges to a leading national office supply chain. 
+The increase in domestic revenue was also due, to a lesser extent, to
+maintenance and repair services performed as we continue to win new service
+contracts and expand existing contracts for our service products including
+extended warranty contracts and our 24-hour guaranteed replacement product
+service called TransAct Xpress™. These increases were largely offset by
+a decline in the sale of refurbished printers and replacement parts for
+certain legacy printers, as the installed base of these legacy printers in
+the market continues to decline. 
+Internationally,
+TSG sales decreased by approximately $930,000, or 29%, to $2,281,000, due
+largely to a decrease in maintenance and repair services revenue from a
+service contract with a single customer in the United Kingdom, as well as a
+decline in sales of consumable products and replacement parts. The
+primary operations of our United Kingdom subsidiary, a European sales and
+service center, relate to revenue generated from a service contract with a
+single customer in the United Kingdom. The service contract, which
+represented a substantial portion of our U.K. subsidiary’s revenue, was
+renewed in April 2007 through November 2007 at a lower minimum sales value
+compared to the minimum sales value of the prior year’s contract. The
+contract ended in November 2007 and was not renewed, as the
+customer replaced our printers with newer technology that we were unable to
+provide. 
+Gross
+Profit. Gross profit information is summarized below (in thousands,
+except percentages): 
+December
+31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2007 
+2006 
+Change 
+Total
+Sales - 2007 
+Total
+Sales – 2006 
+Year
+ended 
+$ 
+15,996 
+$ 
+22,365 
+28.4 
+% 
+32.8 
+% 
+34.8 
+% 
+Gross
+profit and gross margin decreased due primarily to a lower volume of sales
+and a less favorable sales mix in 2007 compared to 2006, somewhat offset by
+lower component part and labor costs resulting from our initiatives to
+increasingly move production to Asia. In addition, gross profit for 2007
+was negatively impacted by an incremental inventory reserve charge of
+approximately $528,000, or 1.1% of net sales, specifically related to certain
+obsolete electronic components and certain discontinued printer
+products. 
+21 
+Table of Contents 
+Engineering and
+Product Development. Engineering and product development
+information is summarized below (in thousands, except percentages): 
+December
+31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2007 
+2006 
+Change 
+Total
+Sales - 2007 
+Total
+Sales – 2006 
+Year
+ended 
+$ 
+3,129 
+$ 
+2,824 
+10.8 
+% 
+6.4 
+% 
+4.4 
+% 
+Engineering,
+design and product development expenses increased as we incurred increased
+outside design, prototype and development expenses associated largely with new
+product development for the banking market, as well as increased
+professional consulting related expenses. These increases were somewhat
+offset by lower expenses related to engineering staffing and other employee
+compensation expenses. Engineering and product development expenses
+increased as a percentage of net sales due primarily to lower sales volume
+in proportion to a higher level of expenses in the 2007 compared to
+2006. 
+Selling and
+Marketing. Selling and marketing information is summarized below (in
+thousands, except percentages): 
+December
+31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2007 
+2006 
+Change 
+Total
+Sales - 2007 
+Total
+Sales - 2006 
+Year
+ended 
+$ 
+6,708 
+$ 
+6,892 
+(2.7 
+)% 
+13.8 
+% 
+10.7 
+% 
+Selling
+and marketing expenses decreased as we incurred lower employee sales commission
+expenses based on lower sales volume, lower demonstration printer expenses,
+and the non-recurrence of expenses incurred in 2006 related to the redesign of
+our website. These decreases were partly offset by increased trade show,
+advertising and other promotional marketing expenses compared with
+2006. Selling and marketing expenses increased as a percentage of net sales
+due primarily to lower sales volume in proportion to a lower level
+of expenses in 2007 compared to 2006. 
+General and
+Administrative. General and administrative information is summarized
+below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2007 
+2006 
+Change 
+Total
+Sales - 2007 
+Total
+Sales - 2006 
+Year
+ended 
+$ 
+6,995 
+$ 
+6,925 
+1.0 
+% 
+14.3 
+% 
+10.8 
+% 
+General
+and administrative expenses increased due primarily to (1) higher legal
+expense related to the expansion of our international patent portfolio, (2)
+higher depreciation and amortization expense associated with the completion
+of the implementation of new Oracle software at the beginning of 2007 and the
+purchase of office furniture and leasehold improvements for our new
+corporate headquarters in Hamden, CT, and (3) increased rent and
+facility-related expenses associated with our new corporate headquarters.
+These increases were somewhat offset by a decrease in incentive
+compensation expense and acquisition-related expenses, as we incurred
+approximately $220,000 of legal and consulting services related to a potential
+acquisition in the second quarter of 2006 that was not consummated.
+These expenses did not recur during 2007. General and administrative
+expenses for 2007 also included a charge of approximately $187,000 for
+severance resulting from the termination of certain employees as part of
+cost reduction actions. General and administrative expenses increased
+as a percentage of net sales due primarily to lower sales volume in proportion
+to a higher level of expenses in 2007 compared to 2006. 
+Legal
+Fees associated with lawsuit. During 2007,
+we incurred approximately $2,907,000 of legal fees related to our lawsuit
+with FutureLogic, Inc. compared to approximately $115,000 in 2006.
+The substantial increase was due primarily to our patent
+infringement counterclaim against FutureLogic, Inc. We
+settled out litigation with FutureLogic, Inc. in May 2008. 
+Business
+Consolidation and Restructuring. During the fourth quarter of
+2006, we executed an agreement, effective May 1, 2007, to terminate the lease
+agreement for our existing corporate headquarters and eastern region service
+center facility located in Wallingford, CT (the “Release
+Agreement”). Prior to the execution of the Release Agreement, we
+accrued for the remaining non-cancelable lease payments and other related costs
+for this facility through the expiration date of the lease (March 31,
+2008). As a result of the Release Agreement and the early termination
+of the old lease, we were released from the legal obligation for lease payments
+after May 1, 2007 and, accordingly, we reversed $479,000 of previously accrued
+expenses related to the Consolidation in the fourth quarter of
+2006. During the second quarter of 2007, we recorded an additional
+$12,000 in expense to finalize the termination of the lease agreement for our
+prior corporate headquarters and eastern region service center facility located
+in Wallingford, CT. 
+22 
+Table of Contents 
+Operating
+Income. Operating income (loss) information is summarized
+below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent
+of 
+Percent
+of 
+2007 
+2006 
+Change 
+Total
+Sales - 2007 
+Total
+Sales - 2006 
+Year
+ended 
+$ 
+(3,755 
+) 
+$ 
+6,088 
+(161.7 
+)% 
+(7.7 
+)% 
+9.5 
+% 
+During
+2007, the substantial decrease in our operating income and operating margin was
+due largely to lower sales and the resulting lower gross profit and higher
+operating expenses (largely legal expenses of approximately $2.9 million related
+to the FutureLogic lawsuit) in 2007 compared to that of 2006. 
+Interest. We
+recorded net interest income of $76,000 in 2007 compared to net interest income
+of $104,000 in 2006. The decrease in our net interest income was
+largely due to a lower average cash balance being lower in 2007 as compared to
+2006. 
+Other Income
+(Expense). We recorded other income of $21,000 in 2007 due
+primarily to gains recorded from the sale of certain assets from our prior
+corporate headquarters and Eastern Regional Service Center in Wallingford, CT,
+partially offset by transaction exchange losses recorded by our UK subsidiary
+resulting from the weakening of the U.S. dollar against the British
+pound. We recorded other expense of $159,000 in 2006 due primarily to
+transaction exchange losses recorded by our UK subsidiary resulting from the
+weakening of the U.S. dollar against the British pound during that
+period. 
+Income
+Taxes. We recorded an income tax benefit of $1,384,000, at an
+effective rate of 37.8% during 2007 compared to an income tax provision of
+$2,117,000, at an effective rate of 35.1% in 2006. The effective tax
+rate for 2007 increased compared to 2006, due largely to an increase in the
+recognition of certain deferred tax credits. 
+Net Income
+(Loss). We reported a net loss in 2007 of $2,274,000, or
+($0.24) per diluted share compared to net income of $3,916,000, or $0.40 per
+diluted share in 2006. 
+Liquidity
+and Capital Resources 
+During
+2008, our cash flows reflected the results of higher sales volume offset by
+legal fees related to the settled lawsuit with FutureLogic, Inc. and increases
+in working capital. After funding $979,000 of capital expenditures
+and incurring $3,029,000 of legal fees related to the settled lawsuit with
+FutureLogic, our cash balance decreased by $561,000 from December 31,
+2007. We ended 2008 with approximately $2,000,000 in cash and cash
+equivalents and no debt outstanding. 
+Operating acti vities : The
+following significant factors primarily affected our cash provided by operations
+of $701,000 in 2008 as compared to $2,610,000 in 2007. 
+During
+2008: 
+· 
+We
+reported net income of $1,444,000. 
+· 
+We
+recorded depreciation, amortization and non-cash compensation expense of
+$2,650,000. 
+· 
+We
+recorded a non-cash foreign currency exchange transaction gain of $368,000
+from our UK subsidiary due to the strengthening of the U.S. dollar against
+the British pound. 
+· 
+Deferred
+taxes decreased by $592,000 primarily due to the utilization of our net
+operating loss generated in
+2007. 
+· 
+Accounts
+receivable increased by $2,611,000 due primarily to higher sales volume in
+the fourth quarter of 2008 compared to the fourth quarter of
+2007. 
+· 
+Gross
+inventories increased by $1,457,000 due primarily to higher stocking
+levels resulting from our initiatives to move increased production to Asia
+and increased sales volume. 
+· 
+Accounts
+payable increased by $178,000 due to higher inventory purchases related to
+higher sales volumes during 2008. 
+· 
+Accrued
+liabilities and other liabilities increased by $19,000 due primarily to
+higher incentive compensation accruals largely offset by lower accrued
+legal fees related to our settled lawsuit with FutureLogic,
+Inc. 
+During
+2007: 
+· 
+We
+reported a net loss of $2,274,000. 
+· 
+We
+recorded depreciation, amortization and non-cash compensation expense of
+$2,559,000. 
+23 
+Table of Contents 
+· 
+Deferred
+taxes increased by $1,839,000 due to our net operating loss during
+2007. 
+· 
+Accounts
+receivable decreased by $5,294,000 due to lower sales during 2007 and
+improved collection efforts. 
+· 
+Inventory
+increased by $2,053,000 due primarily to an increase in consignment
+inventory programs with certain of our customers, higher stocking levels
+resulting from our initiatives to move increased production to Asia, and
+expected increased sales demand in the first quarter of
+2008. 
+· 
+Accounts
+payable increased by $691,000 due to higher inventory purchases and the
+timing of payments during the year. 
+· 
+Accrued
+liabilities and other liabilities decreased by $575,000 due to the
+following: (1) lower compensation related accruals and (2) a lower income
+tax accrual based on the decreased level of income before taxes. These
+decreases were somewhat offset by increases in accrued legal fees,
+primarily related to our lawsuit with FutureLogic, Inc. and deferred rent
+related to the lease of our new corporate headquarters in Hamden,
+CT. 
+· 
+As
+of December 31, 2007 and December 31, 2006, our restructuring accrual
+amounted to $0 and $315,000, respectively. The decrease of $315,000
+is related largely to final payments made on our Wallingford lease
+obligation. 
+Investi ng activities: Our
+capital expenditures were approximately $979,000 and $2,166,000 in 2008 and
+2007, respectively. Expenditures in 2008 included approximately
+$514,000 for the purchase of new product tooling, $329,000 for the purchase of
+computer, networking equipment, and software, $88,000 for the purchase of
+manufacturing equipment, and the remaining amount primarily for the purchase of
+engineering equipment and leasehold improvements. Expenditures in
+2007 included approximately $1,248,000 for the purchase of leasehold
+improvements and office furniture for our new corporate headquarters in Hamden,
+CT, approximately $135,000 for the purchase of leasehold improvements and office
+furniture for our new Eastern Region service center in New Britain, CT,
+approximately $338,000 for the purchase of new computer hardware and software
+including outside consulting costs related to our Oracle software
+implementation, and the remaining amount primarily for the purchase of new
+product tooling. We
+expect our capital expenditures for 2009 to be approximately $1.2
+million. 
+Financing
+activities: We used approximately $229,000 for financing
+activities during 2008, largely due to the repurchase of Company stock of
+approximately $543,000. The repurchases were offset by proceeds from
+stock option exercises of approximately $314,000 during 2008. During
+2007, we used approximately $1,360,000 for financing activities largely due to
+the repurchase of Company stock of approximately $1,503,000. The
+repurchases were offset by proceeds from stock option exercises of approximately
+$149,000 during 2007. 
+Working
+Capital 
+Our
+working capital increased to $15,051,000 at December 31, 2008 from $11,338,000
+at December 31, 2007. Our current ratio also increased to 2.9 to 1 at
+December 31, 2008, compared to 2.4 to 1 at December 31, 2007. The
+increase in both our working capital and current ratio was largely due to higher
+receivables and inventory balances resulting from higher sales. 
+Deferred
+Taxes 
+As of
+December 31, 2008, we had net deferred tax assets of approximately
+$3,813,000. In order to utilize these deferred tax assets, we will
+need to generate approximately $10.9 million of taxable income in future
+years. In one of the last three years, we have had U.S. taxable
+losses and there is no assurance that we will generate future taxable income
+sufficient to realize all of our deferred tax assets. However, based
+on our current projection of future taxable income as of December 31, 2008, we
+believe that it is more likely than not that the existing net deferred tax
+assets will be realized. However, if our future projections of
+taxable income are less than expected, we may need to establish a valuation
+allowance for all or a portion of our net deferred tax assets, which may have a
+material adverse effect on our results of operations and financial
+condition. 
+Credit
+Facility and Borrowings 
+On
+November 28, 2006, we signed a, five-year $20 million credit facility (the “TD
+Banknorth Credit Facility”) with TD Banknorth, N.A. (“TD
+Banknorth”). The credit facility provides for a $20 million revolving
+credit line expiring on November 28, 2011. Borrowings under the
+revolving credit line bear a floating rate of interest at the prime rate minus
+one percent and are secured by a lien on all of our assets. We also
+pay a fee of 0.25% on unused borrowings under the revolving credit
+line. The total deferred financing costs relating to expenses
+incurred to complete the TD Banknorth Credit Facility was
+$94,000. The TD Banknorth Credit Facility imposes certain quarterly
+financial covenants on us and prohibits the payment of dividends on our common
+stock and the creation of other liens. On November 7, 2007, we
+amended the TD Banknorth Credit Facility to revise a financial covenant
+effective September 30, 2007 through September 30, 2008. We were in
+compliance with all financial covenants of the TD Banknorth Credit Facility at
+December 31, 2008. The following table lists the financial covenants
+and the performance measurements at December 31, 2008. 
+Financial
+Covenant 
+Requirement/Restriction 
+Calculation
+at December 31, 2008 
+Operating
+cash flow / Total debt service 
+Minimum
+of 1.25 times 
+58.8
+times 
+Funded
+debt / EBITDA 
+Maximum
+of 3.25 
+0
+times 
+As of
+December 31, 2008, we had no balances outstanding on the revolving credit
+line. Undrawn commitments under the TD Banknorth Credit facility were
+approximately $20,000,000 at December 31, 2008. 
+24 
+Table of Contents 
+Stock
+Repurchase Program 
+On March
+25, 2005, our Board of Directors approved a stock repurchase program (the “Stock
+Repurchase Program”). Under the Stock Repurchase Program, we were
+authorized to repurchase up to $10 million of our outstanding shares of common
+stock from time to time in the open market over a three-year period ending on
+March 25, 2008, depending on market conditions, share price and other
+factors. 
+On
+November 1, 2007, our Board of Directors approved an increase in our stock
+repurchase authorization under the Stock Repurchase Program to $15 million from
+$10 million. In addition, the Board approved a two-year extension of
+the Stock Repurchase Program to March 31, 2010. During 2008, we
+repurchased a total of 130,100 shares of common stock for approximately $543,000
+at an average price of $4.17 per share. As of December 31, 2008, we
+have repurchased a total of 1,164,100 shares of common stock for approximately
+$8,538,000, at an average price of $7.33 per share, since the inception of the
+Stock Repurchase Program. 
+Shareholders’
+Equity 
+Shareholders’
+equity increased by $1,674,000 to $23,282,000 at December 31, 2008 from
+$21,608,000 at December 31, 2007. The increase was primarily due to
+net income of $1,444,000, proceeds of approximately $314,000 from the issuance
+of approximately 67,000 shares of common stock from stock option exercises, and
+compensation expense related to stock options and restricted stock of
+$803,000. These increases were offset by treasury stock purchases of
+130,100 shares of common stock for approximately $543,000, a decrease in
+additional paid-in capital of approximately $98,000 due to a tax charge
+resulting from employee stock transactions and foreign currency translation of
+approximately $246,000. 
+Consolidation
+Expenses 
+During
+2001 through 2007, we recognized approximately $5.5 million of business
+consolidation, restructuring and related expenses as a result of the
+Consolidation. These expenses primarily included employee severance
+and termination related expenses, facility closure and consolidation expenses
+(including moving expenses, estimated non-cancelable lease payments and other
+costs) and accelerated depreciation and asset disposal losses on certain
+leasehold improvements and other fixed assets. 
+In
+November 2006, we executed an agreement effective May 1, 2007 to terminate the
+lease agreement for our Wallingford, CT facility (the “Release
+Agreement”). Prior to the execution of the Release Agreement, we
+accrued the remaining non-cancelable lease payments and other related costs for
+the unused portion of this facility through the expiration date of the lease
+(March 31, 2008). As a result of the Release Agreement and the early termination
+of the lease, we were released from the legal obligation to make lease payments
+after May 1, 2007 and, accordingly, we reversed approximately $479,000 of
+previously accrued restructuring reserve in the fourth quarter of
+2006. During the second quarter of 2007, we recorded an additional
+$12,000 of expense to finalize the termination of the lease
+agreement. As of September 30, 2007, all remaining non-cancelable
+lease payments related to our Wallingford, CT facility were made. We
+paid approximately $327,000 and $399,000 of expenses related to the
+Consolidation in 2007 and 2006, respectively. 
+Contractual
+Obligations 
+TransAct’s
+contractual obligations as of December 31, 2008 were as follows: 
+(In
+thousands) 
+Total 
+<
+1 year 
+1-3
+years 
+3-5
+years 
+>
+5 years 
+Operating
+lease obligations 
+$ 
+4,051 
+$ 
+970 
+$ 
+1,626 
+$ 
+682 
+$ 
+773 
+Purchase
+obligations 
+22,056 
+21,488 
+568 
+- 
+- 
+Total 
+$ 
+26,107 
+$ 
+22,458 
+$ 
+2,194 
+$ 
+682 
+$ 
+773 
+Purchase
+obligations are for purchases made in the normal course of business to meet
+operational requirements, primarily of fully assembled printers and component
+part inventory. 
+Recently
+Issued Accounting Pronouncements 
+Fair Value
+Measurements: In September 2006, the Financial Accounting
+Standards Board (“FASB”) issued Statement of Financial Accounting Standards
+No. 157, “Fair Value Measurements” (“FAS 157”). This statement defines
+fair value, establishes a framework for measuring fair value in generally
+accepted accounting principles, and expands disclosures about fair value
+measurements. This Statement applies under other accounting
+pronouncements that require or permit fair value measurements. FAS 157
+defines fair value based upon an exit price model. A fair value
+measurement assumes that the transaction to sell an asset or transfer a
+liability occurs in the principal market for the asset or liability, or,
+in the absence of a principal market, the most advantageous market for the
+asset or liability. This Statement was effective for the
+Company beginning on January 1, 2008, except that FSP 157-2 delayed the
+effective date of FAS 157 for all nonfinancial assets and
+nonfinancial liabilities, except those that are recognized or disclosed at
+fair value in the financial statements on a recurring basis, until fiscal years
+beginning after November 15, 2008. The Company adopted FAS 157 on
+January 1, 2008, with the exception of the application of the Statement to
+nonrecurring nonfinancial assets and liabilities measured at fair value
+which include: (i) goodwill impairment testing, (ii) initial measurement of
+the fair value of asset retirement obligations and (iii) measurement of
+impairment of long-lived assets. The implementation of FAS 157 did not
+have an effect on the Company’s consolidated financial position, results of
+operations or cash flows during 2008, and is not expected to have a material
+effect on the Company upon full adoption in future periods. 
+25 
+Table of Contents 
+Fair Value Option
+for Financial Assets and Financial Liabilities: In February
+2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The
+Fair Value Option for Financial Assets and Financial Liabilities, including an
+amendment of FASB Statement No. 115” (“FAS 159”). This Statement permits
+entities to choose to measure many financial instruments and certain other items
+at fair value that are not currently required to be measured at fair value.
+The Company adopted FAS 159 on January 1, 2008 and elected not to measure
+any additional financial instruments and other items at fair value. The
+adoption did not have a material effect on the Company’s consolidated financial
+position, results of operations or cash flows during 2008. 
+Business
+Combinations: In December 2007, the FASB issued Statement of
+Financial Accounting Standards No. 141 (revised 2007), “Business Combinations”
+(“FAS 141(R)”). FAS 141(R) amends Statement of Financial Accounting
+Standards No. 141, “Business Combinations” and provides revised guidance
+requiring the acquirer to recognize and measure, at fair value on the
+acquisition date, identifiable assets and goodwill acquired, liabilities
+assumed, and any non-controlling interest in the
+acquiree. Transaction and restructuring costs generally will be
+expensed as incurred. The Statement also provides disclosure
+requirements to enable users of the financial statements to evaluate the nature
+and financial effects of the business combination. FAS 141(R) is
+effective for fiscal years beginning on or after December 15, 2008 and will be
+applied prospectively. This
+statement is not expected to have any effect on our financial statements until
+such time as we acquire a business and its effect on future periods will depend
+on the nature and significance of any acquisition. 
+Derivative
+Instruments and Hedging Activities: In March 2008, the FASB
+issued FAS No. 161, “Disclosures about Derivative Instruments and Hedging
+Activities—an amendment of FASB No. 133” (“FAS 161”). This statement
+amends FAS No. 133 by requiring enhanced qualitative, quantitative and
+credit-risk disclosures about an entity’s derivative instruments and hedging
+activities, but does not change FAS No. 133’s scope or
+accounting. FAS 161 is effective for fiscal years, and interim
+periods within those fiscal years, beginning after November 15, 2008, with
+earlier adoption permitted. As we do not currently engage in
+activities accounted for under the provision of FAS No. 133, the adoption of FAS
+No. 161 is not expected to have any impact on our financial
+statements. 
+Resource
+Sufficiency 
+We
+believe that our cash on hand, cash flows generated from operations and
+borrowings available under the TD Banknorth Credit Facility will provide
+sufficient resources to meet our working capital needs, finance our capital
+expenditures and meet our liquidity requirements through at least the next
+twelve months. 
+Impact
+of Inflation 
+We
+believe that our business has not been affected to a significant degree by
+inflationary trends during the past three years. However,
+inflation is still a factor in the worldwide economy and may increase the cost
+of certain raw materials, component parts and labor used in the manufacture of
+our products. It also may increase our operating expenses,
+manufacturing overhead expenses and the cost to acquire or replace fixed
+assets. Despite growing costs of oil, gas and freight over the recent
+year, we have generally been able to maintain or improve our profit margins
+through productivity and efficiency improvements, cost reduction programs and to
+a lesser extent, price increases, and we expect to be able to do the same during
+2009. As such, we do not believe that inflation will have a
+significant impact on our business during 2009. 
+Item 7A. Quantitative and Qualitative Disclosures about Market
+Risk. 
+Interest
+Rate Risk 
+Our
+exposure to market risk for changes in interest rates relates primarily to the
+investment of our available cash and cash equivalents. In accordance
+with our investment policy, we strive to achieve above market rates of return in
+exchange for accepting a prudent amount of incremental risk, which includes the
+risk of interest rate movements. Risk tolerance is constrained by an
+overriding objective to preserve capital. An effective increase or
+decrease of 10% in interest rates would not have a material effect on our
+results of operations or cash flows. 
+Foreign
+Currency Exchange Risk 
+A
+substantial portion of our sales are denominated in U.S. dollars and, as a
+result, we have relatively little exposure to foreign currency exchange risk
+with respect to sales made. This exposure may change over time as
+business practices evolve and could have a material adverse impact on our
+financial results in the future. We do not use forward exchange
+contracts to hedge exposures denominated in foreign currencies or any other
+derivative financial instruments for trading or speculative
+purposes. We 
+estimate that the combined translational and transactional impact of a 10%
+overall movement in exchange rates from December 31, 2008 (principally the UK
+Pound Sterling) is approximately $100,000 on a pre-tax
+basis. 
+Item 8. Financial Statements and Supplementary
+Data. 
+The
+financial statements and schedule of the Company are annexed to this report as
+pages F-2 through F-24. An index to such materials appears on page
+F-1. 
+Item 9. Changes in and Disagreements with Accountants on
+Accounting and Financial Disclosure. 
+None. 
+26 
+Table of Contents 
+Item 9A. Controls and Procedures . 
+Attached
+as exhibits to this Form 10-K are certifications of our Chief Executive Officer
+(“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance
+with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the
+Exchange Act). This “Controls and Procedures” section includes
+information concerning the controls and controls evaluation referred to in the
+certifications. Part II, Item 8 of this Form 10-K sets forth the
+report of PricewaterhouseCoopers LLP, our independent registered public
+accounting firm, regarding its audit of TransAct’s internal control over
+financial reporting as of December 31, 2008. This section should be read
+in conjunction with the CEO and CFO certifications and the
+PricewaterhouseCoopers LLP report for a more complete understanding of the
+topics presented. 
+Evaluation
+of Disclosure Controls and Procedures 
+As of
+December 31, 2008, the Company, with the participation of its CEO and CFO
+conducted an evaluation of the effectiveness of the design and operation of the
+Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the
+Securities Exchange Act of 1934 (the “Exchange Act”). Based on that
+evaluation, our CEO and CFO concluded that the Company’s disclosure controls and
+procedures (as defined in Rule 13a-15 of the Exchange Act) are
+effective. 
+Management’s
+Report on Internal Control Over Financial Reporting 
+Our
+management is responsible for establishing and maintaining adequate internal
+control over financial reporting to provide reasonable assurance regarding the
+reliability of our financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted
+accounting principles. 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. 
+Management
+assessed our internal control over financial reporting as of December 31, 2008.
+Management based its assessment on criteria established in Internal
+Control–Integrated Framework issued by the Committee of Sponsoring Organizations
+of the Treadway Commission (“COSO”). 
+Based on
+our assessment, management has concluded that our internal control over
+financial reporting was effective as of December 31, 2008. 
+The
+effectiveness of the Company’s internal control over financial reporting as of
+December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an
+independent registered public accounting firm, as stated in their report which
+appears herein. 
+Inherent
+Limitations on Effectiveness of Controls 
+A control
+system, no matter how well designed and operated, can provide only reasonable,
+not absolute, assurance that the control system’s objectives will be
+met. 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. Further, because of the inherent limitations
+in all control systems, no evaluation of controls can provide absolute assurance
+that misstatements due to error or fraud will not occur or that all control
+issues and instances of fraud, if any, within the 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 errors or mistakes. Controls
+can also be circumvented by the individual acts of some persons, by collusion of
+two or more people, or by management override of the controls. The
+design of any system of controls is based in part on 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. Projections of any evaluation of controls effectiveness to
+future periods are subject to risks. Over time, controls may become
+inadequate because of changes in conditions or deterioration in the degree of
+compliance with policies or procedures. 
+Item 9B. Other Information . 
+Not
+applicable. 
+PART III 
+Item 10. Directors, Executive Officers and
+Corporate Governance . 
+The
+information in response to this item is incorporated by reference from the Proxy
+Statement sections entitled “Election of Directors” and “Executive
+Officers.” 
+27 
+Table of Contents 
+Item 11. Executive Compensation . 
+The
+information in response to this item is incorporated by reference from the Proxy
+Statement sections entitled “Executive Compensation and Certain Transactions”
+and “Compensation Discussion and Analysis.” 
+Item 12. Security Ownership of Certain Beneficial Owners and
+Management and Related Stockholder Matters . 
+The
+information in response to this item is incorporated by reference from the Proxy
+Statement section entitled “Security Ownership of Certain Beneficial Owners and
+Management.” 
+Information
+regarding our equity compensation plans as of December 31, 2008 is as
+follows: 
+Plan
+category 
+(a) 
+Number
+of securities to be issued upon exercise of outstanding options, warrants
+and rights 
+(b) 
+Weighted
+average exercise price of outstanding options, warrants and
+rights 
+(c) 
+Number
+of securities remaining available for future issuance under equity
+compensation plans (excluding securities reflected in column
+(a)) 
+Equity
+compensation plans approved by security holders: 
+1996
+Stock Plan 
+333,838 
+$ 
+3.28 
+- 
+1996
+Non-Employee Director Plan 
+153,750 
+11.50 
+- 
+2005
+Equity Incentive Plan 
+392,250 
+7.18 
+187,250 
+Total 
+879,838 
+$ 
+6.46 
+187,250 
+Equity
+compensation plans not approved by security holders: 
+2001
+Employee Stock Plan 
+32,661 
+$ 
+5.18 
+- 
+912,499 
+$ 
+6.41 
+187,250 
+The
+TransAct Technologies Incorporated 2001 Employee Stock Plan (the “2001 Employee
+Plan”) was adopted by our Board of Directors, without approval of our security
+holders, effective February 26, 2001. Under the 2001 Employee Plan,
+we may issue non-qualified stock options, shares of restricted stock, restricted
+units to acquire shares of common stock, stock appreciation rights and limited
+stock appreciation rights to key employees of TransAct or any of our
+subsidiaries and to non-employees who provide services to TransAct or any of our
+subsidiaries. The 2001 Employee Plan is administered by our
+Compensation Committee, which has the authority to determine the vesting period
+and other similar restrictions and terms of awards, provided that the exercise
+price of options granted under the plan may not be less than the fair market
+value of the underlying shares on the date of grant. 
+In May
+2005, our shareholders approved the adoption of the 2005 Equity Incentive
+Plan. No new awards will be available for future issuance under any
+existing TransAct equity plan other than the 2005 Equity Incentive
+Plan. 
+Item 13. Certain Relationships and Related Transactions, and
+Director Independence. 
+The
+information in response to this item is incorporated by reference from the Proxy
+Statement section entitled “Certain Relationships and Related
+Transactions.” 
+Item 14. Principal Accounting Fees and Services. 
+The
+information in response to this item is incorporated by reference from the Proxy
+Statement section entitled “Independent Registered Public Accounting Firm’s
+Services and Fees.” 
+PART IV 
+Item 15. Exhibits and Financial Statement
+Schedules . 
+The
+financial statements and schedule filed as part of this report are listed in the
+accompanying Index to Financial Statements and Schedule. The exhibits filed as a
+part of this report are listed in the accompanying Index to
+Exhibits. 
+28 
+Table of Contents 
+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. 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+By: 
+/s/
+Bart C. Shuldman 
+Name: 
+Bart
+C. Shuldman 
+Title: 
+Chairman
+of the Board, President and Chief Executive
+Officer 
+Date:
+March 16 ,
+2009 
+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/ Bart C.
+Shuldman 
+Chairman
+of the Board, 
+March
+16 ,
+2009 
+Bart
+C. Shuldman 
+President
+and Chief Executive Officer, 
+(Principal
+Executive Officer) 
+/s/ Steven A.
+DeMartino 
+Executive
+Vice President, 
+March
+16 ,
+2009 
+Steven
+A. DeMartino 
+Chief
+Financial Officer, 
+Treasurer
+and Secretary 
+(Principal
+Financial and Accounting Officer) 
+/s/ Charles A.
+Dill 
+Director 
+March
+16 ,
+2009 
+Charles
+A. Dill 
+/s/
+Thomas R. Schwarz 
+Director 
+March
+16 ,
+2009 
+Thomas
+R. Schwarz 
+/s/
+Graham Y. Tanaka 
+Director 
+March
+16 ,
+2009 
+Graham
+Y. Tanaka 
+29 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX
+TO FINANCIAL STATEMENTS AND SCHEDULE 
+Financial
+Statements 
+Report of Independent
+Registered Public Accounting Firm 
+F-2 
+Consolidated balance
+sheets as of December 31, 2008 and 2007 
+F-3 
+Consolidated
+statements of operations for the years ended December 31, 2008, 2007 and
+2006 
+F-4 
+Consolidated
+statements of changes in shareholders' equity and comprehensive income
+(loss) for the years ended December 31, 2008, 2007 and
+2006 
+F-5 
+Consolidated
+statements of cash flows for the years ended December 31, 2008, 2007 and
+2006 
+F-6 
+Notes to consolidated
+financial statements 
+F-7 
+Financial
+Statement Schedule 
+The
+following financial statement schedule is included herein: 
+Schedule II -
+Valuation and Qualifying Accounts 
+F-22 
+All
+other financial statement schedules are omitted because they are not
+applicable or the required information is shown in the consolidated
+financial statements or notes thereto 
+F-1 
+Table of Contents 
+Report of Independent Registered Public Accounting
+Firm 
+To the
+Board of Directors and Stockholders of TransAct Technologies
+Incorporated: 
+In our
+opinion, the accompanying consolidated balance sheets and the related
+consolidated statements of operations, of changes in shareholders' equity and
+comprehensive income (loss) and of cash flows, present fairly, in all material
+respects, the financial position of TransAct Technologies Incorporated and its
+subsidiaries at December 31, 2008 and December 31, 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. In
+addition, in our opinion, the financial statement schedule listed in the index
+appearing under Item 15 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, 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 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
+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. 
+As
+discussed in Note 2 to the consolidated financial statements, the Company
+changed the manner in which it accounts for uncertain tax positions in
+2007. 
+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 
+/s/
+PricewaterhouseCoopers LLP 
+Hartford,
+Connecticut 
+March 16,
+2009 
+F-2 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED
+BALANCE SHEETS 
+(In
+thousands, except share data) 
+December
+31, 
+December
+31, 
+2008 
+2007 
+Assets: 
+Current
+assets: 
+Cash
+and cash equivalents 
+$ 
+2,000 
+$ 
+2,561 
+Receivables,
+net 
+8,734 
+6,128 
+Inventories,
+net 
+9,919 
+8,665 
+Refundable
+income taxes 
+35 
+51 
+Deferred
+tax assets 
+2,054 
+1,528 
+Other
+current assets 
+352 
+362 
+Total
+current assets 
+23,094 
+19,295 
+Fixed
+assets, net 
+5,563 
+6,338 
+Goodwill 
+1,469 
+1,469 
+Deferred
+tax assets 
+1,759 
+2,830 
+Intangible
+and other assets, net of accumulated amortization of $306 and $221,
+respectively 
+349 
+482 
+9,140 
+11,119 
+Total
+assets 
+$ 
+32,234 
+$ 
+30,414 
+Liabilities
+and Shareholders’ Equity: 
+Current
+liabilities: 
+Accounts
+payable 
+$ 
+4,863 
+$ 
+4,688 
+Accrued
+liabilities 
+2,847 
+2,747 
+Deferred
+revenue 
+333 
+522 
+Total
+current liabilities 
+8,043 
+7,957 
+Deferred
+revenue, net of current portion 
+259 
+211 
+Accrued
+warranty, net of current portion 
+133 
+91 
+Deferred
+rent 
+473 
+507 
+Other
+liabilities 
+44 
+40 
+909 
+849 
+Total
+liabilities 
+8,952 
+8,806 
+Commitments
+and contingencies (Note 11) 
+Shareholders’
+equity: 
+Preferred
+stock, $0.01 par value, 4,800,000 authorized, none issued and
+outstanding 
+- 
+- 
+Preferred
+stock, Series A, $0.01 par value, 200,000 authorized, none issued and
+outstanding 
+- 
+- 
+Common
+stock, $0.01 par value, 20,000,000 authorized at December 31, 2008 and
+2007; 10,465,588 and 10,399,866 shares issued; 9,301,488 and 9,365,866
+shares outstanding, at December 31, 2008 and 2007,
+respectively 
+105 
+104 
+Additional
+paid-in capital 
+20,890 
+19,872 
+Retained
+earnings 
+10,893 
+9,449 
+Accumulated
+other comprehensive income (loss), net of tax 
+(68 
+) 
+178 
+Treasury
+stock, 1,164,100 and 1,034,000 shares, at cost 
+(8,538 
+) 
+(7,995 
+) 
+Total
+shareholders’ equity 
+23,282 
+21,608 
+Total
+liabilities and shareholders’ equity 
+$ 
+32,234 
+$ 
+30,414 
+See
+accompanying notes to consolidated financial statements. 
+F-3 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED
+STATEMENTS OF OPERATIONS 
+(In
+thousands, except per share data) 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+Net
+sales 
+$ 
+62,207 
+$ 
+48,766 
+$ 
+64,328 
+Cost
+of sales 
+41,257 
+32,770 
+41,963 
+Gross
+profit 
+20,950 
+15,996 
+22,365 
+Operating
+expenses: 
+Engineering,
+design and product development 
+2,942 
+3,129 
+2,824 
+Selling
+and marketing 
+6,078 
+6,708 
+6,892 
+General
+and administrative 
+7,040 
+6,995 
+6,925 
+Legal
+fees associated with lawsuit (See Note 11) 
+3,029 
+2,907 
+115 
+Business
+consolidation and restructuring 
+- 
+12 
+(479 
+) 
+19,089 
+19,751 
+16,277 
+Operating
+income (loss) 
+1,861 
+(3,755 
+) 
+6,088 
+Interest
+and other income (expense): 
+Interest
+expense 
+(70 
+) 
+(69 
+) 
+(44 
+) 
+Interest
+income 
+59 
+145 
+148 
+Other,
+net 
+368 
+21 
+(159 
+) 
+357 
+97 
+(55 
+) 
+Income
+(loss) before income taxes 
+2,218 
+(3,658 
+) 
+6,033 
+Income
+tax provision (benefit) 
+774 
+(1,384 
+) 
+2,117 
+Net
+income (loss) 
+$ 
+1,444 
+$ 
+(2,274 
+) 
+$ 
+3,916 
+Net
+income (loss) per common share: 
+Basic 
+$ 
+0.16 
+$ 
+(0.24 
+) 
+$ 
+0.41 
+Diluted 
+$ 
+0.15 
+$ 
+(0.24 
+) 
+$ 
+0.40 
+Shares
+used in per-share calculation: 
+Basic 
+9,308 
+9,364 
+9,577 
+Diluted 
+9,489 
+9,364 
+9,870 
+See
+accompanying notes to consolidated financial statements. 
+F-4 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED
+STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
+(LOSS) 
+(In
+thousands, except share data) 
+Common
+Stock 
+Additional
+Paid-in 
+Retained 
+Unamortized
+Restricted Stock 
+Treasury 
+Accumulated
+Other Comprehensive 
+Total
+Comprehensive 
+Shares 
+Amount 
+Capital 
+Earnings 
+Compensation 
+Stock 
+Income
+(Loss) 
+Total 
+Income
+(Loss) 
+Balance,
+December 31, 2005 
+9,732,010 
+$ 
+102 
+$ 
+19,334 
+$ 
+7,489 
+$ 
+(1,837 
+) 
+$ 
+(3,867 
+) 
+$ 
+36 
+$ 
+21,257 
+Impact
+of adoption of new accounting pronouncements 
+- 
+- 
+(1,837 
+) 
+- 
+1,837 
+- 
+- 
+- 
+Cancellation
+of restricted stock 
+(11,750 
+) 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+Issuance
+of shares from exercise of stock options 
+136,157 
+2 
+685 
+- 
+- 
+- 
+- 
+687 
+Issuance
+of restricted stock 
+15,000 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+Tax
+benefit related to employee stock sales and vesting of restricted
+stock 
+- 
+- 
+342 
+- 
+- 
+- 
+- 
+342 
+Purchase
+of treasury stock 
+(296,300 
+) 
+- 
+- 
+- 
+- 
+(2,625 
+) 
+- 
+(2,625 
+) 
+Share-based
+compensation expense 
+- 
+- 
+581 
+- 
+- 
+- 
+- 
+581 
+Comprehensive
+income: 
+Foreign
+currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+- 
+132 
+132 
+$ 
+132 
+Net
+income 
+- 
+- 
+- 
+3,916 
+- 
+- 
+- 
+3,916 
+3,916 
+Balance,
+December 31, 2006 
+9,575,117 
+104 
+19,105 
+11,405 
+- 
+(6,492 
+) 
+168 
+24,290 
+4,048 
+Adoption
+of FASB Interpretation No. 48 
+- 
+- 
+- 
+318 
+- 
+- 
+- 
+318 
+Opening
+balance at January 1, 2007, as adjusted 
+9,575,117 
+104 
+19,105 
+11,723 
+- 
+(6,492 
+) 
+168 
+24,608 
+Cancellation
+of restricted stock 
+(9,750 
+) 
+- 
+- 
+- 
+- 
+- 
+- 
+- 
+Issuance
+of shares from exercise of stock options 
+33,199 
+- 
+149 
+- 
+- 
+- 
+- 
+149 
+Tax
+charge related to vesting of restricted stock 
+- 
+- 
+(97 
+) 
+- 
+- 
+- 
+- 
+(97 
+) 
+Purchase
+of treasury stock 
+(232,700 
+) 
+- 
+- 
+- 
+- 
+(1,503 
+) 
+- 
+(1,503 
+) 
+Share-based
+compensation expense 
+- 
+- 
+715 
+- 
+- 
+- 
+- 
+715 
+Comprehensive
+income (loss): 
+Foreign
+currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+- 
+10 
+10 
+10 
+Net
+loss 
+- 
+- 
+- 
+(2,274 
+) 
+- 
+- 
+- 
+(2,274 
+) 
+(2,274 
+) 
+Balance,
+December 31, 2007 
+9,365,866 
+104 
+19,872 
+9,449 
+- 
+(7,995 
+) 
+178 
+21,608 
+(2,264 
+) 
+Cancellation
+of restricted stock 
+(1,250 
+) 
+- 
+(4 
+) 
+- 
+- 
+- 
+- 
+(4 
+) 
+Issuance
+of shares from exercise of stock options 
+66,972 
+1 
+313 
+- 
+- 
+- 
+- 
+314 
+Tax
+charge related to vesting of restricted stock 
+- 
+- 
+(98 
+) 
+- 
+- 
+- 
+- 
+(98 
+) 
+Purchase
+of treasury stock 
+(130,100 
+) 
+- 
+- 
+- 
+- 
+(543 
+) 
+- 
+(543 
+) 
+Share-based
+compensation expense 
+- 
+- 
+807 
+- 
+- 
+- 
+- 
+807 
+Comprehensive
+income (loss): 
+Foreign
+currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+- 
+(246 
+) 
+(246 
+) 
+(246 
+) 
+Net
+income 
+- 
+- 
+- 
+1,444 
+- 
+- 
+- 
+1,444 
+1,444 
+Balance,
+December 31, 2008 
+9,301,488 
+$ 
+105 
+$ 
+20,890 
+$ 
+10,893 
+$ 
+- 
+$ 
+(8,538 
+) 
+$ 
+(68 
+) 
+$ 
+23,282 
+$ 
+1,198 
+See
+accompanying notes to consolidated financial statements. 
+F-5 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED
+STATEMENTS OF CASH FLOWS 
+(In
+thousands) 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+Cash
+flows from operating activities: 
+Net
+income (loss) 
+$ 
+1,444 
+$ 
+(2,274 
+) 
+$ 
+3,916 
+Adjustments
+to reconcile net income (loss) to net cash provided by operating
+activities: 
+Share-based
+compensation expense 
+803 
+715 
+581 
+Incremental
+tax benefits from stock options exercised 
+- 
+- 
+(342 
+) 
+Depreciation
+and amortization 
+1,847 
+1,844 
+1,568 
+Deferred
+income taxes 
+592 
+(1,839 
+) 
+583 
+Provision
+for excess and obsolete inventory 
+200 
+955 
+266 
+(Gain)
+loss on sale of fixed assets 
+3 
+(14 
+) 
+- 
+Foreign
+currency transaction (gain) loss 
+(368 
+) 
+6 
+159 
+Reversal
+of accrued restructuring expense 
+- 
+- 
+(479 
+) 
+Changes
+in operating assets and liabilities: 
+Receivables 
+(2,611 
+) 
+5,294 
+(3,063 
+) 
+Inventories 
+(1,457 
+) 
+(2,053 
+) 
+(1,797 
+) 
+Refundable
+income taxes 
+14 
+(9 
+) 
+253 
+Other
+current assets 
+8 
+144 
+(276 
+) 
+Other
+assets 
+29 
+40 
+(72 
+) 
+Accounts
+payable 
+178 
+691 
+1,138 
+Accrued
+liabilities and other liabilities 
+19 
+(575 
+) 
+1,423 
+Accrued
+restructuring expenses 
+- 
+(315 
+) 
+(399 
+) 
+Net
+cash provided by operating activities 
+701 
+2,610 
+3,459 
+Cash
+flows from investing activities: 
+Purchases
+of fixed assets 
+(979 
+) 
+(2,166 
+) 
+(2,891 
+) 
+Proceeds
+from sale of assets 
+- 
+37 
+- 
+Net
+cash used in investing activities 
+(979 
+) 
+(2,129 
+) 
+(2,891 
+) 
+Cash
+flows from financing activities: 
+Payment
+of deferred financing costs 
+- 
+(6 
+) 
+(88 
+) 
+Proceeds
+from stock option exercises 
+314 
+149 
+687 
+Purchases
+of common stock for treasury 
+(543 
+) 
+(1,503 
+) 
+(2,625 
+) 
+Incremental
+tax benefits from stock options exercised 
+- 
+- 
+342 
+Net
+cash used in financing activities 
+(229 
+) 
+(1,360 
+) 
+(1,684 
+) 
+Effect
+of exchange rate changes on cash 
+(54 
+) 
+4 
+(27 
+) 
+Decrease
+in cash and cash equivalents 
+(561 
+) 
+(875 
+) 
+(1,143 
+) 
+Cash
+and cash equivalents, beginning of period 
+2,561 
+3,436 
+4,579 
+Cash
+and cash equivalents, end of period 
+$ 
+2,000 
+$ 
+2,561 
+$ 
+3,436 
+Supplemental
+cash flow information: 
+Interest
+paid 
+$ 
+51 
+$ 
+51 
+$ 
+43 
+Income
+taxes paid 
+34 
+742 
+1,201 
+Non-cash
+financing activities: 
+Tax
+benefit related to employee stock sales and vesting of restricted
+stock 
+- 
+- 
+342 
+Issuance
+of restricted stock 
+- 
+- 
+207 
+See
+accompanying notes to consolidated financial statements. 
+F-6 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+1.
+Description of business 
+TransAct
+Technologies Incorporated (“TransAct” or the “Company”), which has its
+headquarters in Hamden, CT and its primary operating facility in Ithaca, NY,
+operates in one industry segment, market-specific printers for transaction-based
+industries. These industries include casino, gaming, lottery,
+banking, kiosk and point-of-sale. Our printers are designed based on
+market specific requirements and are sold under the Ithaca® and Epic product
+brands. We distribute our products through OEMs, value-added
+resellers, selected distributors, and directly to end-users. Our
+product distribution spans across the Americas, Europe, the Middle East, Africa,
+Asia, Australia, the Caribbean Islands and the South Pacific. We
+also generate revenue from the after-market side of the business, providing
+printer service, supplies and spare parts. 
+2.
+Summary of significant accounting policies 
+Principles of
+consolidation: The accompanying consolidated financial
+statements were prepared on a consolidated basis to include the accounts of
+TransAct and its wholly-owned subsidiaries. All intercompany
+accounts, transactions and unrealized profit were eliminated in
+consolidation. 
+Reclassifications: Certain
+amounts in the prior years’ financial statements have been reclassified to
+conform to the current year’s presentation. 
+Use of
+estimates: The accompanying consolidated financial statements were
+prepared using estimates and assumptions that affect the reported amounts of
+assets, liabilities, revenue and expenses, and disclosure of contingent assets
+and liabilities as of the date of the consolidated financial statements and the
+reported amounts of revenues and expenses during the reporting period. Actual
+results could differ from those estimates. 
+Segment
+reporting: We apply the provisions of Statement of Financial
+Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and
+Related Information” (“FAS 131”). We view our operations and manage
+our business as one segment: the design, development, manufacture and sale of
+transaction-based printers. Factors used to identify TransAct’s
+single operating segment include the organizational structure of the Company and
+the financial information available for evaluation by the chief operating
+decision-maker in making decisions about how to allocate resources and assess
+performance. We operate predominantly in one geographical area, the
+United States of America. See Note 17 for information regarding our
+international operations. We provide the following disclosures of
+revenues from products and services: 
+Year
+ended 
+Year
+ended 
+Change 
+(In
+thousands) 
+December
+31, 2008 
+December
+31, 2007 
+$ 
+% 
+Banking
+and POS 
+$ 
+11,866 
+19.1 
+% 
+$ 
+11,046 
+22.6 
+% 
+$ 
+820 
+7.4 
+% 
+Casino
+and gaming 
+22,299 
+35.8 
+% 
+19,438 
+39.9 
+% 
+2,861 
+14.7 
+% 
+Lottery 
+15,731 
+25.3 
+% 
+5,900 
+12.1 
+% 
+9,831 
+166.6 
+% 
+TransAct
+Services Group 
+12,311 
+19.8 
+% 
+12,382 
+25.4 
+% 
+(71 
+) 
+(0.6 
+)% 
+Total
+net sales 
+$ 
+62,207 
+100.0 
+% 
+$ 
+48,766 
+100.0 
+% 
+$ 
+13,441 
+27.6 
+% 
+Cash and cash
+equivalents: We consider all highly liquid investments with a
+maturity date of three months or less at date of purchase to be cash
+equivalents. 
+Accounts
+receivable and allowance
+for doubtful accounts : We
+have standardized credit granting and review policies and procedures for all
+customer accounts, including: 
+· 
+Credit
+reviews of all new customer
+accounts, 
+· 
+Ongoing
+credit evaluations of current
+customers, 
+· 
+Credit
+limits and payment terms based on available credit
+information, 
+· 
+Adjustments
+to credit limits based upon payment history and the customer’s current
+creditworthiness. 
+F-7 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+2.
+Summary of significant accounting policies (continued) 
+We
+establish an allowance for doubtful accounts to ensure trade receivables are
+valued appropriately. We maintain an allowance for doubtful accounts
+based on a variety of factors, including the length of time receivables are past
+due, significant one-time events and historical experience. We record
+a specific allowance for individual accounts when we become aware of a
+customer’s inability to meet its financial obligations, such as in the case of
+bankruptcy filings or deterioration in the customer’s operating results or
+financial position. If circumstances related to customers change, we
+would further adjust estimates of the recoverability of
+receivables. Allowances for doubtful accounts on accounts receivable
+balances were $55,000 and $62,000 as of December 31, 2008 and 2007,
+respectively. 
+Inventories: Inventories
+are stated at the lower of cost (principally standard cost, which approximates
+actual cost on a first-in, first-out basis) or market. We review
+market value based on historical usage and estimates of future
+demand. Based on these reviews, inventory write-downs are recorded,
+as necessary, to reflect estimated obsolescence, excess quantities and market
+value. Our net inventory included a reserve of $3,050,000 and
+$2,850,000 as of December 31, 2008 and 2007, respectively. 
+Fixed
+assets: Fixed assets are stated at cost. Depreciation is
+recorded using the straight-line method over the estimated useful
+lives. The estimated useful life of tooling is five years; machinery
+and equipment is ten years; furniture and office equipment is five to ten years;
+and computer software and equipment is three to seven
+years. Leasehold improvements are amortized over the shorter of the
+term of the lease or the useful life of the asset. Costs related to
+repairs and maintenance are expensed as incurred. The costs of sold or
+retired assets are removed from the related asset and accumulated depreciation
+accounts and any gain or loss is recognized. Depreciation expense was
+$1,744,000, $1,743,000 and $1,466,000 in 2008, 2007 and 2006,
+respectively. 
+Leases: Rent
+expense under non-cancelable operating leases with scheduled rent increases or
+free rent periods is accounted for on a straight-line basis over the lease term,
+beginning on the date of control of physical use of the asset or of initial
+possession. The amount of the excess of straight-line rent expense
+over scheduled payments is recorded as a deferred
+liability. Construction allowances and other such lease incentives
+are recorded as deferred credits, and are amortized on a straight-line basis as
+a reduction of rent expense beginning in the period they are deemed to be
+earned, which generally coincides with the occupancy date. 
+Goodwill: We
+account for goodwill in accordance with the provisions of Statement of Financial
+Accounting Standard No. 142, “Goodwill and Other Intangible Assets” (“FAS
+142”). We test goodwill annually for impairment, or whenever events
+or changes in circumstances indicate that the carrying value may not be
+recoverable. We have performed an impairment test as of December 31,
+2008 and determined that no impairment has occurred. 
+Revenue
+recognition: Our typical contracts
+include the sale of printers, which are sometimes accompanied by
+separately-priced extended warranty contracts. We also sell spare
+parts, consumables, and other repair services (sometimes pursuant to multi-year
+product maintenance contracts) which are not included in the original printer
+sale and are ordered by the customer as needed. We recognize revenue
+pursuant to the guidance within SAB 104, “Revenue
+Recognition.” Specifically, revenue is recognized when evidence of an
+arrangement exists, delivery (based on shipping terms, which are generally FOB
+shipping point) has occurred, the selling price is fixed and determinable, and
+collectability is reasonably assured. We provide for an estimate of
+product returns and price protection based on historical experience at the time
+of revenue recognition. 
+Revenue
+related to extended warranty and product maintenance contracts is recognized
+pursuant to FASB Technical Bulletin 90-1 (“FTB 90-1”), “Accounting for
+Separately Priced Extended Warranty and Product Maintenance
+Contracts.” Pursuant to FTB 90-1, revenue related to separately
+priced product maintenance contracts is deferred and recognized over the term of
+the maintenance period. We record deferred revenue for advance
+payments received from customers for maintenance contracts. 
+Our
+customers have the right to return products that do not function properly within
+a limited time after delivery. We monitor and track product returns
+and record a provision for the estimated future returns based on historical
+experience. Returns have historically been within expectations and
+the provisions established. 
+F-8 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+2.
+Summary of significant accounting policies (continued) 
+We offer
+some of our customer’s price protection as an incentive to carry inventory of
+our product. These price protection plans provide that if we lower
+prices, we will credit them for the price decrease on inventory they
+hold. Our customers typically carry limited amounts of inventory, and
+we infrequently lower prices on current products. As a result, the
+amounts paid under these plans have not been material. 
+Concentration of
+credit risk: Financial instruments that potentially expose
+TransAct to concentrations of credit risk are limited to cash and cash
+equivalents held by our banks in excess of insured limits and accounts
+receivable. 
+Accounts
+receivable from customers representing 10% or more of total accounts receivable
+were as follows: 
+December
+31, 
+2008 
+2007 
+Customer
+A 
+20 
+% 
+12 
+% 
+Customer
+B 
+* 
+13 
+% 
+Customer
+C 
+10 
+% 
+* 
+Customer
+D 
+* 
+10 
+% 
+* -
+customer balances were less than 10% of total accounts
+receivable 
+Sales to
+customers representing 10% or more of total net sales were as
+follows: 
+Year
+ended December 31, 
+2008 
+2007 
+2006 
+Customer
+A 
+28 
+% 
+14 
+% 
+20 
+% 
+Customer
+B 
+* 
+10 
+% 
+* 
+* -
+customer balances were less than 10% of total net sales 
+Prior to
+2008, the primary operations of our United Kingdom subsidiary, a European sales
+and service center, related to revenue generated from a service contract with a
+single customer in the United Kingdom. The service contract, which
+represented a substantial portion of our U.K. subsidiary’s revenue, was renewed
+in April 2007 through November 2007 at a lower minimum sales value compared to
+the minimum sales value of the prior year’s contract. The service
+contract ended in November 2007 and was not renewed, as the customer replaced
+our printers with a different technology that we were unable to
+provide. 
+Warranty: We
+generally warrant our products for up to 24 months and record the estimated cost
+of such product warranties at the time the sale is
+recorded. Estimated warranty costs are based upon actual past
+experience of product repairs and the related estimated cost of labor and
+material to make the necessary repairs. 
+The
+following table summarizes the activity recorded in the accrued product warranty
+liability: 
+Year
+ended December 31, 
+(In
+thousands) 
+2008 
+2007 
+2006 
+Balance,
+beginning of year 
+$ 
+500 
+$ 
+603 
+$ 
+644 
+Additions
+related to warranties issued 
+263 
+356 
+595 
+Warranty
+costs incurred 
+(370 
+) 
+(459 
+) 
+(636 
+) 
+Balance,
+end of year 
+$ 
+393 
+$ 
+500 
+$ 
+603 
+Approximately
+$133,000 and $91,000 of the accrued product warranty liability were classified
+as long-term at December 31, 2008 and 2007, respectively. 
+F-9 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+2.
+Summary of significant accounting policies (continued) 
+Research and
+development expenses: Research and development expenses
+include engineering, design and product development expenses incurred in
+connection with specialized engineering and design to introduce new products and
+to customize existing products, and are expensed as a component of operating
+expenses as incurred. We recorded approximately $2,942,000,
+$3,129,000 and $2,824,000 of research and development expenses in 2008, 2007 and
+2006, respectively. 
+Advertising: Advertising
+costs are expensed as incurred. Advertising expenses, which are
+included in selling and marketing expense on the accompanying consolidated
+statements of operations, for 2008, 2007 and 2006 totaled $289,000, $136,000 and
+$182,000, respectively. 
+Restructuring: In
+2001, we undertook a plan to consolidate all manufacturing and engineering into
+our existing Ithaca, NY facility and close our Wallingford, CT manufacturing
+facility. We applied the consensus set forth in EITF 94-3, “Liability
+Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
+Activity (Including Certain Costs Incurred in a Restructuring)” in recognizing
+restructuring expenses. For all future exit costs, we will apply the
+guidance set forth in Statement of Financial Accounting Standard No. 146,
+“Accounting for Costs Associated with Exit or Disposal Activities” (“FAS
+146”). See Note 8 for additional disclosures related to our
+restructuring and exit costs. 
+Income
+taxes: The income tax amounts reflected in the accompanying
+financial statements are accounted for under the liability method in accordance
+with FAS 109 “Accounting for Income Taxes” (“FAS 109”). Deferred tax
+assets and liabilities are recognized for the estimated future tax consequences
+attributable to differences between the financial statement carrying amounts of
+existing assets and liabilities and their respective tax bases and operating
+loss and tax credit carryforwards. Deferred tax assets and
+liabilities are measured using enacted tax rates in effect for the year in which
+those temporary differences are expected to be recovered or
+settled. We assess the likelihood that net deferred tax assets will
+be realized from future taxable income, and to the extent that we believe that
+realization is not likely, we establish a valuation allowance. On
+January 1, 2007, we adopted FASB Interpretation 48, Accounting for Uncertainty
+in Income Taxes (“FIN 48”). In accordance with FIN 48, we identified,
+evaluated and measured the amount of benefits to be recognized for our tax
+return positions. See Note 14 for information regarding our
+accounting for income taxes. 
+Foreign currency
+translation: The financial position and results of operations of our
+foreign subsidiary in the United Kingdom are measured using local currency as
+the functional currency. Assets and liabilities of such subsidiary
+have been translated into U.S. dollars at the year-end exchange rate, related
+revenues and expenses have been translated at the weighted average exchange rate
+for the year, and shareholders’ equity has been translated at historical
+exchange rates. The resulting translation gains or losses, net of
+tax, are recorded in stockholders’ equity as a cumulative translation
+adjustment, which is a component of accumulated other comprehensive
+income. Foreign currency transaction gains and losses, including
+those related to intercompany balances, are recognized in other income
+(expense). 
+Fair value of
+financial instruments: The carrying amount for
+cash and cash equivalents approximates fair value because of the short maturity
+of these instruments. The carrying amount of receivables, accounts
+payable and accrued liabilities is a reasonable estimate of fair value because
+of the short-term nature of these accounts. 
+Comprehensive
+income: Statement of Financial Accounting Standards No. 130,
+“Reporting Comprehensive Income” (“FAS 130”), requires that items defined as
+comprehensive income or loss be separately classified in the financial
+statements and that the accumulated balance of other comprehensive income or
+loss be reported separately from accumulated deficit and additional
+paid-in-capital in the equity section of the balance sheet. We
+include the foreign currency translation adjustment, net of tax, related to our
+subsidiary in the United Kingdom within our calculation of comprehensive
+income. 
+F-10 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+2.
+Summary of significant accounting policies (continued) 
+Share-based
+Payments: In
+December 2004, the Financial Accounting Standards Board (“FASB”) revised
+Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based
+Payment” (“FAS 123R”), which establishes accounting for share-based awards
+exchanged for employee services and requires companies to expense the estimated
+fair value of these awards over the requisite employee service
+period. We adopted the accounting provisions of FAS 123R beginning in
+the first quarter of 2006. 
+Share-based
+compensation expense is measured at the grant date, based on the estimated fair
+value of the award, and is recognized as expense over the employee’s requisite
+service period. We have no awards with market or performance
+conditions. 
+We use
+the Black-Scholes option-pricing model to calculate the fair value of share
+based awards. The key assumptions for this valuation method include
+the expected term of the option, stock price volatility, risk-free interest
+rate, dividend yield, market price of our underlying stock and exercise
+price. Many of these assumptions are judgmental and highly sensitive
+in the determination of compensation expense. In addition, we
+estimate forfeitures when recognizing compensation expense, and we adjust our
+estimate of forfeitures over the requisite service period based on the extent to
+which actual forfeitures differ, or are expected to differ, from such
+estimates. Changes in estimated forfeitures are recognized through a
+cumulative true-up adjustment in the period of change and also impacts the
+amount of compensation expense to be recognized in future
+periods. 
+Net income and
+loss per share: We report net income or loss per share in
+accordance with Statement of Financial Accounting Standards No. 128, “Earnings
+per Share (EPS)” (“FAS 128”). Under FAS 128, basic EPS, which
+excludes dilution, is computed by dividing income or loss available to common
+shareholders by the weighted average number of common shares outstanding for the
+period. Unvested restricted stock is excluded from the calculation of
+weighted average common shares for basic EPS. Diluted EPS reflects
+the potential dilution that could occur if securities or other contracts to
+issue common stock were exercised or converted into common
+stock. Diluted EPS includes restricted stock and in-the-money stock
+options using the treasury stock method. During a loss period, the
+assumed exercise of in-the-money stock options has an anti-dilutive effect, and
+therefore, these instruments are excluded from the computation of dilutive
+EPS. See Note 15 for EPS calculation. 
+3.
+Recently issued accounting pronouncements 
+Fair Value
+Measurements: In September 2006, the Financial Accounting
+Standards Board (“FASB”) issued Statement of Financial Accounting Standards
+No. 157, “Fair Value Measurements” (“FAS 157”). This statement defines
+fair value, establishes a framework for measuring fair value in generally
+accepted accounting principles, and expands disclosures about fair value
+measurements. This Statement applies under other accounting
+pronouncements that require or permit fair value measurements. FAS 157
+defines fair value based upon an exit price model. A fair value
+measurement assumes that the transaction to sell an asset or transfer a
+liability occurs in the principal market for the asset or liability, or,
+in the absence of a principal market, the most advantageous market for the
+asset or liability. This Statement was effective for the
+Company beginning on January 1, 2008, except that FSP 157-2 delayed the
+effective date of FAS 157 for all nonfinancial assets and
+nonfinancial liabilities, except those that are recognized or disclosed at
+fair value in the financial statements on a recurring basis, until fiscal years
+beginning after November 15, 2008. The Company adopted FAS 157 on
+January 1, 2008, with the exception of the application of the Statement to
+nonrecurring nonfinancial assets and liabilities measured at fair value
+which include: (i) goodwill impairment testing, (ii) initial measurement of
+the fair value of asset retirement obligations and (iii) measurement of
+impairment of long-lived assets. The implementation of FAS 157 did not
+have an effect on the Company’s consolidated financial position, results of
+operations or cash flows during 2008, and is not expected to have a material
+effect on the Company upon full adoption in future periods. 
+F-11 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+3.
+Recently issued accounting pronouncements (continued) 
+Fair Value Option
+for Financial Assets and Financial Liabilities: In February
+2007, the FASB issued Statement of Financial Accounting Standards No. 159, “The
+Fair Value Option for Financial Assets and Financial Liabilities, including an
+amendment of FASB Statement No. 115” (“FAS 159”). This Statement
+permits entities to choose to measure many financial instruments and certain
+other items at fair value that are not currently required to be measured at fair
+value. The Company adopted FAS 159 on January 1, 2008 and elected not
+to measure any additional financial instruments and other items at fair
+value. The adoption did not have a material effect on the Company’s
+consolidated financial position, results of operations or cash flows during
+2008. 
+Business
+Combinations: In December 2007, the FASB issued Statement of
+Financial Accounting Standards No. 141 (revised 2007), “Business Combinations”
+(“FAS 141(R)”). FAS 141(R) amends Statement of Financial Accounting
+Standards No. 141, “Business Combinations” and provides revised guidance
+requiring the acquirer to recognize and measure, at fair value on the
+acquisition date, identifiable assets and goodwill acquired, liabilities
+assumed, and any non-controlling interest in the
+acquiree. Transaction and restructuring costs generally will be
+expensed as incurred. The Statement also provides disclosure
+requirements to enable users of the financial statements to evaluate the nature
+and financial effects of the business combination. FAS 141(R) is
+effective for fiscal years beginning on or after December 15, 2008 and will be
+applied prospectively. This statement is not expected to have any
+effect on our financial statements until such time as we acquire a
+business and its
+effect on future periods will depend on the nature and significance of any
+acquisition . 
+Derivative
+Instruments and Hedging Activities: In March 2008, the FASB
+issued FAS No. 161, “Disclosures about Derivative Instruments and Hedging
+Activities—an amendment of FASB No. 133” (“FAS 161”). This statement
+amends FAS No. 133 by requiring enhanced qualitative, quantitative and
+credit-risk disclosures about an entity’s derivative instruments and hedging
+activities, but does not change FAS No. 133’s scope or
+accounting. FAS 161 is effective for fiscal years, and interim
+periods within those fiscal years, beginning after November 15, 2008, with
+earlier adoption permitted. As we do not currently engage in
+activities accounted for under the provision of FAS No. 133, the adoption of FAS
+No. 161 is not expected to have any impact on our financial
+statements. 
+4.
+Inventories 
+The
+components of inventories, net of allowances, are: 
+December
+31, 
+(In
+thousands) 
+2008 
+2007 
+Raw
+materials and purchased component parts 
+$ 
+7,207 
+$ 
+8,019 
+Work-in-process 
+27 
+57 
+Finished
+goods 
+2,685 
+589 
+$ 
+9,919 
+$ 
+8,665 
+5.
+Fixed assets 
+The
+components of fixed assets are: 
+December
+31, 
+(In
+thousands) 
+2008 
+2007 
+Tooling,
+machinery and equipment 
+$ 
+13,316 
+$ 
+12,697 
+Furniture
+and office equipment 
+1,694 
+1,730 
+Computer
+software and equipment 
+4,694 
+4,940 
+Leasehold
+improvements 
+1,872 
+1,867 
+21,576 
+21,234 
+Less:
+accumulated depreciation and amortization 
+(16,013 
+) 
+(14,896 
+) 
+$ 
+5,563 
+$ 
+6,338 
+F-12 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+6.
+Intangible assets 
+On June
+30, 2005, we acquired certain intangible assets related to casino ticket printer
+designs and technology from Bally Gaming, Inc. (“Bally”) for $475,000, plus the
+costs of effecting the acquisition (approximately $35,000). Prior to
+the acquisition, pursuant to the terms of a license agreement, we were required
+to pay Bally a royalty on sales of certain gaming printers utilizing the
+licensed technology. As a result of the acquisition, effective July
+1, 2005, we were no longer required to pay any future royalties to
+Bally. 
+The
+purchase price was allocated, based on management’s estimates, to intangible
+assets based on their relative fair value at the date of
+acquisition. The fair value of the intangibles, comprised of
+purchased technology and a covenant not to compete, was determined using the
+future discounted cash flows method. The intangible assets are being
+amortized on a straight-line basis over six and seven years, respectively, for
+the estimated life of the assets. 
+The
+following summarizes the allocation of the purchase price for the acquisition of
+certain intangible assets from Bally (in thousands): 
+Purchased
+technology 
+$ 
+364 
+Covenant
+not to compete 
+146 
+Consideration
+paid 
+$ 
+510 
+As of
+December 31, 2008 and 2007, the net intangible asset balance associated with the
+technology purchased from Bally was $226,000 and $307,000,
+respectively. Amortization expense associated with the technology
+purchased from Bally was $81,000 in 2008, 2007 and 2006,
+respectively. Amortization expense for each of the next four years
+ending December 31 is expected to be as follows: $81,000 in each of 2009 through
+2010; $54,000 in 2011; and $10,000 in 2012. 
+7.
+Accrued liabilities 
+The
+components of accrued liabilities (current portion) are: 
+December
+31, 
+(In
+thousands) 
+2008 
+2007 
+Payroll
+and fringe benefits 
+$ 
+1,771 
+$ 
+929 
+Income
+taxes 
+134 
+- 
+Warranty 
+260 
+409 
+Professional
+and consulting 
+114 
+782 
+Other 
+568 
+627 
+$ 
+2,847 
+$ 
+2,747 
+F-13 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+8.
+Accrued business consolidation and restructuring expenses 
+In
+February 2001, we announced plans to establish a global engineering and
+manufacturing center at our Ithaca, NY facility. As part of this
+strategic decision, we undertook a plan to consolidate all manufacturing and
+engineering into our existing Ithaca, NY facility and close our Wallingford, CT
+manufacturing facility (the “Consolidation”). As of December 31,
+2001, we successfully transferred substantially all our Wallingford operations
+to Ithaca, NY, with the exception of our corporate headquarters and a service
+center that remain in Connecticut. The closing of the Wallingford
+manufacturing facility resulted in the termination of employment of
+approximately 70 production, administrative and management
+employees. 
+During
+2001 through 2004, we recorded expenses of approximately $5,957,000 related to
+costs associated with the Consolidation, including severance pay, stay bonuses,
+employee benefits, moving expenses, non-cancelable lease payments, accelerated
+depreciation and other costs. 
+In
+November 2006, we executed an agreement effective May 1, 2007 to terminate the
+lease agreement for our Wallingford, CT facility (the “Release Agreement”).
+Prior to the execution of the Release Agreement, we accrued the remaining
+non-cancelable lease payments and other related costs for the unused portion of
+this facility through the expiration date of the lease (March 31, 2008). As a
+result of the Release Agreement and the early termination of the lease, we were
+released from the legal obligation to make lease payments after May 1, 2007 and,
+accordingly, we reversed approximately $479,000 of previously accrued
+restructuring reserve in the fourth quarter of 2006. During the
+second quarter of 2007, we recorded an additional $12,000 of expense to finalize
+the termination of the lease agreement. As of December 31, 2007, all
+non-cancelable lease payments related to our Wallingford, CT facility had
+been made. 
+The
+following table summarizes the activity recorded in the restructuring
+accrual: 
+Year
+ended December 31, 
+(In
+thousands) 
+2007 
+2006 
+Accrual
+balance, beginning of year 
+$ 
+315 
+$ 
+1,193 
+Business
+consolidation and restructuring expenses: 
+Facility
+closure and consolidation expenses 
+12 
+- 
+Reversal
+of lease obligation related to unused space 
+- 
+(479 
+) 
+12 
+(479 
+) 
+Cash
+payments 
+(327 
+) 
+(399 
+) 
+Accrual
+balance, end of year 
+$ 
+- 
+$ 
+315 
+9.
+Retirement savings plan 
+On April
+1, 1997, we established the TransAct Technologies Retirement Savings Plan (the
+“401(k) Plan”), a defined contribution plan under Section 401(k) of the Internal
+Revenue Code. All full-time employees are eligible to participate in
+the 401(k) Plan at the beginning of the calendar quarter immediately following
+their date of hire. We match employees’ contributions at a rate of
+50% of employees’ contributions up to the first 6% of the employees’
+compensation contributed to the 401(k) Plan. Our matching
+contributions were $244,000, $247,000 and $249,000 in 2008, 2007 and 2006,
+respectively. 
+10.
+Borrowings 
+On
+November 28, 2006, we signed a five-year $20 million credit facility (the “TD
+Banknorth Credit Facility”) with TD Banknorth, N.A. (“TD Banknorth”). The credit
+facility provides for a $20 million revolving credit line expiring on November
+28, 2011. Borrowings under the revolving credit line bear a floating
+rate of interest at the prime rate minus one-percent and are secured by a lien
+on all of our assets. We also pay a fee of 0.25% on unused borrowings
+under the revolving credit line. Deferred financing costs relating to
+expenses incurred to complete the TD Banknorth Credit Facility were
+$94,000. The TD Banknorth Credit Facility imposes certain quarterly
+financial covenants on us and prohibits the payment of dividends on our common
+stock and the creation of other liens. On November 7, 2007, we
+amended the TD Banknorth Credit Facility to revise a financial covenant
+effective September 30, 2007. We were
+in compliance with all financial covenants of the TD Banknorth Credit Facility
+at December 31, 2008. 
+As of
+December 31, 2008, we had no outstanding borrowings on the revolving credit
+line. Undrawn commitments under the TD Banknorth Credit Facility were
+$20,000,000 at December 31, 2008. 
+F-14 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+11.
+Commitments and contingencies 
+We had
+been involved in patent litigation with FutureLogic with respect to our patents
+U.S. Patent 6,924,903 and U.S. Patent 7,099,035. On May 13, 2008, we
+signed a Patent License and Settlement Agreement with FutureLogic that settled
+the current patent litigation and all other legal matters outstanding between
+the two parties. Under the Patent License and Settlement Agreement,
+FutureLogic agreed to license our dual port technology for printers and
+upgrade kits that utilize the patented technology. The license grants
+FutureLogic worldwide, perpetual rights for U.S. Patent 6,924,903, U.S. Patent
+7,099,035, related applications and patents, and foreign
+counterparts. 
+At
+December 31, 2008, we were lessee on operating leases for equipment and real
+property. Rent expense was approximately $1,030,000, $1,152,000 and
+$1,330,000 in 2008, 2007 and 2006, respectively. Minimum aggregate
+rental payments required under operating leases that have initial or remaining
+non-cancelable lease terms in excess of one year as of December 31, 2008 are as
+follows: $9 70 ,000 in 2009;
+$810 ,000 in 
+2010; $ 816 ,000 in 2011; $ 459 ,000 in 2012;
+$223,000 in 2013; and $ 773 ,000
+thereafter. 
+12.
+Stock incentive plans 
+Stock incentive
+plans . We currently
+have four primary stock incentive plans: the 1996 Stock Plan, which provided for
+the grant of awards to officers and other key employees of the Company; the 1996
+Directors’ Stock Plan, which provided for non-discretionary awards to
+non-employee directors; the 2001 Employee Stock Plan, which provided for the
+grant of awards to key employees of the Company and other non-employees who
+provided services to the Company; and the 2005 Equity Incentive Plan, which
+provides for awards to executives, key employees, directors and
+consultants. The plans generally provide for awards in the form of:
+(i) incentive stock options, (ii) non-qualified stock options, (iii) restricted
+stock, (iv) restricted stock units, (v) stock appreciation rights or (vi)
+limited stock appreciation rights. However, the 2001 Employee Stock
+Plan does not provide for incentive stock option awards. Options
+granted under these plans have exercise prices equal to 100% of the fair market
+value of the common stock at the date of grant. Options granted have
+a ten-year term and generally vest over a three- to five-year period, unless
+automatically accelerated for certain defined events. As of May 2005,
+no new awards will be made under the 1996 Stock Plan, the 1996 Directors’ Stock
+Plan or the 2001 Employee Stock Plan. At December 31, 2008,
+approximately 187,250 shares of common stock remained available for issuance
+under the 2005 Equity Incentive Plan. 
+Under the
+assumptions indicated below, the weighted-average fair value of stock option
+grants for the years ended December 31, 2008, 2007 and 2006 was $5.85,
+$5.81 and $5.91, respectively. The table below indicates the key
+assumptions used in the option valuation calculations for options granted in the
+years ended December 31, 2008, 2007 and 2006 and a discussion of our methodology
+for developing each of the assumptions used in the valuation model: 
+Year
+ended December 31, 
+2008 
+2007 
+2006 
+Expected
+option term 
+5.7
+years 
+6.0
+years 
+5.2
+years 
+Expected
+volatility 
+61.7 
+% 
+71.2 
+% 
+78.4 
+% 
+Risk-free
+interest rate 
+3.0 
+% 
+4.5 
+% 
+4.5 
+% 
+Dividend
+yield 
+0 
+% 
+0 
+% 
+0 
+% 
+Expected
+Option Term - This is the weighted average period of time over which the options
+granted are expected to remain outstanding giving consideration to our
+historical exercise patterns. Options granted have a maximum term of
+ten years. An increase in the expected term will increase
+compensation expense. 
+Expected
+Volatility – The stock volatility for each grant is measured using the weighted
+average of historical daily price changes of our common stock over the most
+recent period approximately equal to the expected option term of the
+grant. An increase in the expected volatility factor will increase
+compensation expense. 
+Risk-Free
+Interest Rate - This is the U.S. Treasury rate in effect at the time of grant
+having a term approximately equal to the expected term of the
+option. An increase in the risk-free interest rate will increase
+compensation expense. 
+Dividend
+Yield - We have not made any dividend payments on our common stock, and we have
+no plans to pay dividends in the foreseeable future. An increase in
+the dividend yield will decrease compensation expense. 
+F-15 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+12.
+Stock incentive plans (continued) 
+Prior to
+adopting the provisions of FAS 123R, we recorded estimated compensation expense
+for employee stock options based upon their intrinsic value on the date of grant
+pursuant to APB 25 and provided the required pro forma disclosures of FAS
+123. Because we established the exercise price based on the fair
+market value of our common stock at the date of grant, the stock options had no
+intrinsic value upon grant, and therefore no expense was recorded prior to
+adopting FAS 123R. We recorded compensation expense for restricted
+stock at the fair value of the stock at the date of grant, recognized over the
+service period. Each accounting period, we reported the potential
+dilutive impact of stock options in our diluted earnings per common share using
+the treasury-stock method. Out-of-the-money stock options (i.e., the
+average stock price during the period was below the exercise price of the
+stock option) were not included in diluted earnings per common share as their
+effect was anti-dilutive. 
+We
+recognize compensation expense associated with awards granted after January 1,
+2006, and the unvested portion of previously granted restricted stock awards
+that were outstanding as of January 1, 2006 in our consolidated statement of
+operations. During 2006, we recognized compensation expense of
+$111,000 for stock options and $470,000 for restricted stock, which was recorded
+in our consolidated statement of operations in accordance with
+FAS123R. The income tax benefits from share-based payments recorded
+in our consolidated statement of operations totaled $204,000 for
+2006. 
+During
+2007, we recognized compensation expense of $225,000 for stock options and
+$490,000 for restricted stock, which was recorded in our consolidated statement
+of operations in accordance with FAS123R. The income tax benefits
+from share-based payments recorded in our consolidated statement of operations
+totaled $270,000 for 2007. 
+During
+2008, we recognized compensation expense of
+$335,000 for stock
+options and $468,000 for restricted stock, which was recorded in our
+consolidated statement of operations in accordance with FAS123R. The
+income tax benefits from share-based payments recorded in our consolidated
+statement of operations totaled $280,000 for
+2008. 
+The 1996
+Stock Plan, 1996 Directors’ Stock Plan, 2001 Employee Stock Plan and 2005 Equity
+Incentive Plan option activity is summarized below: 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+Shares 
+Weighted
+Average Exercise Price 
+Shares 
+Weighted
+Average Exercise Price 
+Shares 
+Weighted
+Average Exercise Price 
+Outstanding
+at beginning of period 
+764,696 
+$ 
+6.95 
+707,344 
+$ 
+6.67 
+741,501 
+$ 
+6.10 
+Granted 
+167,500 
+5.85 
+144,500 
+8.82 
+115,000 
+8.83 
+Exercised 
+(66,972 
+) 
+4.68 
+(33,199 
+) 
+4.49 
+(136,157 
+) 
+5.05 
+Forfeited 
+(3,000 
+) 
+5.24 
+(29,500 
+) 
+9.23 
+(10,000 
+) 
+8.83 
+Expired 
+(10,575 
+) 
+11.25 
+(24,449 
+) 
+10.25 
+(3,000 
+) 
+16.62 
+Outstanding
+at end of period 
+851,649 
+$ 
+6.87 
+764,696 
+$ 
+6.95 
+707,344 
+$ 
+6.67 
+Options
+exercisable at end of period 
+530,149 
+$ 
+6.62 
+565,696 
+$ 
+6.32 
+602,344 
+$ 
+6.29 
+Options
+vested or expected to vest 
+828,348 
+$ 
+6.87 
+755,468 
+$ 
+6.94 
+704,530 
+$ 
+6.66 
+Options
+Outstanding 
+Options
+Exercisable 
+Range
+of Exercise Prices 
+Number
+Outstanding at December 31, 2008 
+Weighted-Average
+Exercise Price 
+Weighted-Average
+Remaining Contractual Life 
+Number
+Exercisable at December 31, 2008 
+Weighted-Average
+Exercise Price 
+(In
+years) 
+$2.00
+- $5.00 
+340,149 
+$ 
+3.63 
+3.1 
+340,149 
+$ 
+3.63 
+$5.01
+- $7.50 
+253,250 
+5.90 
+6.6 
+102,750 
+6.57 
+$7.51
+- $10.00 
+221,000 
+8.93 
+7.9 
+50,000 
+9.06 
+$10.01
+- $25.00 
+2,500 
+18.33 
+5.0 
+2,500 
+18.33 
+$25.01
+- $35.00 
+34,750 
+31.66 
+5.4 
+34,750 
+31.66 
+851,649 
+6.87 
+5.5 
+530,149 
+6.62 
+F-16 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+12.
+Stock incentive plans (continued) 
+At
+December 31, 2008 and 2007, outstanding options had an intrinsic value of
+$325,000 and $447,000 with a weighted average remaining contractual life of 5.5
+and 5.3 years, respectively. At December 31, 2008 and 2007, options
+vested or expected to vest had an intrinsic value of $325,000 and $447,000 with
+a weighted average remaining contractual life of 5.4 and 5.3 years,
+respectively. In addition, exercisable options at December 31, 2008
+and 2007 had an intrinsic value of $325,000 and $447,000 with a weighted average
+remaining contractual life of 3.6 and 4.1 years, respectively. Shares
+that are issued upon exercise of employee stock options are newly issued shares
+and not issued from treasury stock. As of December 31, 2008,
+unrecognized compensation cost related to stock options totaled $1,147,000,
+which is expected to be recognized over a weighted average period of 3.7
+years. 
+The total
+intrinsic value of stock options exercised was $402,000, $61,000 and $825,000
+and the total fair value of stock options vested was $247,000, $124,000, and $0
+during the year ended December 31, 2008, 2007 and 2006, respectively. As a
+result of the exercise of non-qualified stock options, we have net operating
+loss carry forwards of approximately $114,000 attributable to excess tax
+benefits from stock compensation deductions, which can be used to offset future
+taxable income, if any. If and when realized, the related tax
+benefits of these net operating losses carry forwards will be credited directly
+to paid-in capital. 
+Restricted
+stock: Under
+the 1996 Stock Plan, 2001 Employee Stock Plan
+and 2005 Equity Incentive Plan, we have granted shares of restricted
+common stock, for no consideration, to our officers, directors and certain key
+employees. R estricted stock activity
+for the 1996 Stock Plan , 2001 Employee Stock Plan
+and 2005 Equity Incentive Plan is summarized
+below: 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+Shares 
+Weighted
+Average Grant Date Fair Values 
+Shares 
+Weighted
+Average Grant Date Fair Values 
+Shares 
+Weighted
+Average Grant Date Fair Values 
+Nonvested
+shares at beginning of period 
+106,683 
+$ 
+12.10 
+154,116 
+$ 
+12.22 
+187,550 
+$ 
+12.23 
+Granted 
+- 
+- 
+- 
+- 
+15,000 
+13.78 
+Vested 
+(44,583 
+) 
+12.15 
+(37,683 
+) 
+13.01 
+(36,684 
+) 
+12.78 
+Canceled 
+(1,250 
+) 
+7.58 
+(9,750 
+) 
+10.49 
+(11,750 
+) 
+12.64 
+Nonvested
+shares at end of period 
+60,850 
+$ 
+12.15 
+106,683 
+$ 
+12.10 
+154,116 
+$ 
+12.22 
+As of
+December 31, 2008, unrecognized compensation cost related to restricted stock
+totaled $363,000, which is expected to be recognized over a weighted average
+period of 1.6 years. The total
+intrinsic value of restricted stock that vested during 2008, 2007 and 2006 was
+$205,000, $180,000 and $338,000, respectively. 
+13.
+Stockholder rights plan 
+In
+December 1997, our Board of Directors adopted a Stockholder Rights Plan
+declaring a distribution of one right (the “Rights”) for each outstanding share
+of our common stock to shareholders of record at December 15,
+1997. Initially, each of the Rights entitled the registered holder to
+purchase from the Company one one-thousandth of a share of Series A Preferred
+Stock, $0.01 par value, at a price of $69 per one one-thousandth of a
+share. The Rights, however, would not become exercisable unless and
+until, among other things, any person or group of affiliated persons acquired
+beneficial ownership of 15 percent or more of the then outstanding shares of the
+Company’s Common Stock. If a person, or group of persons, acquired 15
+percent or more of the outstanding Common Stock of the Company (subject to
+certain conditions and exceptions more fully described in the Rights Agreement),
+each Right entitled the holder (other than the person, or group of persons, who
+acquired 15 percent or more of the outstanding Common Stock) to purchase
+Preferred Stock of the Company having a market value equal to twice the exercise
+price of the Right. The Rights were redeemable, under certain
+circumstances, for $0.0001 per Right and expired on December 2,
+2007. 
+F-17 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+14.
+Income taxes 
+The
+components of the income tax provision (benefit) are as follows: 
+Year
+Ended December 31, 
+(In
+thousands) 
+2008 
+2007 
+2006 
+Current: 
+Federal 
+$ 
+- 
+$ 
+(32 
+) 
+$ 
+952 
+State 
+16 
+35 
+41 
+Foreign 
+166 
+452 
+541 
+Deferred: 
+Federal 
+386 
+(1,693 
+) 
+552 
+State 
+207 
+(144 
+) 
+31 
+Foreign 
+(1 
+) 
+(2 
+) 
+- 
+Income
+tax provision (benefit) 
+$ 
+774 
+$ 
+(1,384 
+) 
+$ 
+2,117 
+At
+December 31, 2008, we have $2,119,000 of state net operating loss carryforwards
+that begin to expire in 2009, and $393,000 of federal net operating loss
+carryforwards that begin to expire in 2027. We also have
+approximately $641,000 in federal research and development tax credit
+carryforwards that begin to expire in 2024, $118,000 in state tax credit
+carryforwards that begin to expire in 2009, and foreign tax credit carryforwards
+of approximately $834,000 that begin to expire in 2014. We had
+foreign income before taxes of $541,000, $1,486,000 and $1,813,000 in 2008, 2007
+and 2006, respectively. 
+Deferred
+income taxes arise from temporary differences between the tax basis of assets
+and liabilities and their reported amounts in the financial
+statements. Our gross deferred tax assets and liabilities were
+comprised of the following: 
+December
+31, 
+(In
+thousands) 
+2008 
+2007 
+Gross
+deferred tax assets: 
+Net
+operating losses 
+$ 
+96 
+$ 
+1,549 
+Capitalized
+research and development 
+413 
+494 
+Inventory
+reserves 
+1,081 
+1,034 
+Deferred
+revenue 
+139 
+186 
+Warranty
+reserve 
+139 
+181 
+FAS
+123R stock compensation expense 
+360 
+147 
+Foreign
+tax and other credits 
+1,437 
+781 
+Other
+liabilities and reserves 
+456 
+306 
+Net
+deferred tax assets 
+4,121 
+4,678 
+Gross
+deferred tax liabilities: 
+Depreciation 
+269 
+236 
+Other 
+39 
+84 
+Net
+deferred tax liabilities 
+308 
+320 
+Net
+deferred tax assets 
+$ 
+3,813 
+$ 
+4,358 
+During
+2008, we recorded a full valuation allowance of $27,000 on the foreign net
+operating loss from our Macau subsidiary. The valuation allowance is
+included in other liabilities and reserves in the net deferred tax assets table
+above. 
+In order
+to utilize our deferred tax assets, we will need to generate approximately $10.9
+million of taxable income in future years. In one of the last three
+years, we have had U.S. taxable losses and there is no assurance that we will
+generate future taxable income sufficient to realize all of our deferred tax
+assets. During 2008, we recorded a full valuation allowance of
+$27,000 on the foreign net operating loss from our Macau
+subsidiary. We have determined that it is more likely than not that
+the remaining net deferred tax assets will be realized, and therefore no
+additional valuation allowance is considered necessary, as of December 31,
+2008. However, if our future projections of taxable income are less
+than expected, we may need to establish an additional valuation allowance for
+all or a portion of our net deferred tax assets, which may have a material
+adverse effect on our results of operations and financial
+condition. 
+F-18 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+14.
+Income taxes (continued) 
+Differences
+between the U.S. statutory federal income tax rate and our effective income tax
+rate are analyzed below: 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+Federal
+statutory tax rate 
+34.0 
+% 
+(34.0 
+)% 
+34.0 
+% 
+State
+income taxes, net of federal income taxes 
+6.6 
+(2.0 
+) 
+1.1 
+Tax
+benefit from tax credits, net of valuation allowance 
+(5.6 
+) 
+(4.0 
+) 
+(0.7 
+) 
+Foreign
+rate differential 
+(2.4 
+) 
+0.2 
+- 
+Valuation
+allowance and tax accruals 
+1.2 
+- 
+0.4 
+Permanent
+items 
+1.4 
+0.9 
+0.6 
+Other 
+(0.3 
+) 
+1.1 
+(0.3 
+) 
+Effective
+tax rate 
+34.9 
+% 
+(37.8 
+)% 
+35.1 
+% 
+We
+adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes (“FIN
+48”), at the beginning of 2007. As a result of the implementation, we
+recognized a decrease to reserves for uncertain tax positions. This
+decrease was accounted for as a $318,000 adjustment to the beginning balance of
+retained earnings on the Consolidated Balance Sheet. Including the
+cumulative effect decrease, at the beginning of 2007 we had approximately
+$79,000 of total gross unrecognized tax benefits that, if recognized, would
+favorably affect the effective income tax rate in any future
+periods. 
+The total gross
+unrecognized tax benefits at December 31, 2008 are $160,000, of which $116,000
+is recorded as a reduction of the related deferred tax asset, and $44,000 is
+recorded as a long term liability. At December 31, 2008 and
+2007, we had approximately $160,000 and $125,000 of total gross unrecognized tax
+benefits that, if recognized, would favorably affect the effective income tax
+rate in any future periods. We are not aware of any events that could
+occur within the next twelve months that could cause a significant change in the
+total amount of unrecognized tax benefits. A tabular reconciliation
+of the gross amounts of unrecognized tax benefits excluding interest and
+penalties at the beginning and end of the year is as follows: 
+2008 
+2007 
+Unrecognized
+tax benefits as of January 1 
+$ 
+125 
+$ 
+79 
+Tax
+positions taken during prior periods 
+- 
+33 
+Tax
+positions taken during the current period 
+36 
+21 
+Settlements 
+- 
+- 
+Lapse
+of statute of limitations 
+(1 
+) 
+(8 
+) 
+Unrecognized
+tax benefits as of December 31 
+$ 
+160 
+$ 
+125 
+We are
+subject to U.S. federal income tax as well as income tax of certain state and
+foreign jurisdictions. We have substantially concluded all U.S.
+federal income tax, state and local, and foreign tax matters through
+2002. During 2008, a limited scope examination of our 2005 and 2006
+federal tax returns was completed. However, our federal tax returns
+for the years 2003 through 2007 remain open to examination. Various
+state and foreign tax jurisdiction tax years remain open to examination as well,
+though we believe that any additional assessment would be immaterial to the
+consolidated financial statements. No federal, state or foreign tax
+jurisdiction income tax returns are currently under examination. 
+We do not
+anticipate that the total unrecognized tax benefits will significantly change
+due to the settlement of audits and the expiration of statute of limitations
+prior to December 31, 2009. 
+We
+recognize interest and penalties related to uncertain tax positions in income
+tax expense. As of December 31, 2008 and 2007, we have approximately
+$7,000 and $2,000 of accrued interest and penalties related to uncertain tax
+positions. 
+F-19 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+15.
+Earnings per share 
+For 2008,
+2007 and 2006, earnings per share were computed as follows (in thousands, except
+per share amounts): 
+Year
+Ended December 31, 
+2008 
+2007 
+2006 
+Net
+income (loss) 
+$ 
+1,444 
+$ 
+(2,274 
+) 
+$ 
+3,916 
+Shares: 
+Basic: Weighted
+average common shares outstanding 
+9,308 
+9,364 
+9,577 
+Add: Dilutive
+effect of outstanding options as determined by the treasury stock
+method 
+181 
+- 
+293 
+Diluted: Weighted
+average common and common equivalent shares
+outstanding 
+9,489 
+9,364 
+9,870 
+Net
+income (loss) per common share: 
+Basic 
+$ 
+0.16 
+$ 
+(0.24 
+) 
+$ 
+0.41 
+Diluted 
+0.15 
+(0.24 
+) 
+0.40 
+For the
+year ended December 31, 2008, potentially dilutive shares that were excluded
+from the earnings per share calculation, consisting of out-of-the-money stock
+options, were 258,250 shares. 
+For the
+year ended December 31, 2007, there were 871,379 potentially dilutive shares
+(prior to consideration of the treasury stock method), consisting of stock
+options and nonvested restricted stock, that were excluded from the earnings per
+share calculation, because such shares would be anti-dilutive due to our net
+loss in the period. 
+For the
+year ended December 31, 2006, potentially dilutive shares that were excluded
+from the earnings per share calculation, consisting of out-of-the-money stock
+options, were 101,750 shares. 
+16.
+Stock repurchase program 
+On March
+25, 2005, our Board of Directors approved a stock repurchase program (“the Stock
+Repurchase Program”). Under the Stock Repurchase Program, we were
+authorized to repurchase up to $10 million of our outstanding shares of common
+stock from time to time in the open market over a three-year period ending on
+March 25, 2008, depending on market conditions, share price and other
+factors. 
+On
+November 1, 2007, our Board of Directors approved an increase in our stock
+repurchase authorization under the Stock Repurchase Program to $15 million from
+$10 million. In addition, the Board approved a two-year extension of
+the Stock Repurchase Program to March 31, 2010. As of December 31,
+2008, we repurchased a total of 1,164,100 shares of common stock for
+approximately $8,538,000 under this program, at an average price of $7.33 per
+share. We use the cost method to account for treasury stock
+purchases, under which the price paid for the stock is charged to the treasury
+stock account. 
+17.
+International operations 
+We have
+foreign operations primarily from TransAct Technologies Ltd., a wholly-owned
+subsidiary in the United Kingdom, which had sales to its customers of
+approximately $120,000, $2,121,000 and $2,722,000 in 2008, 2007 and 2006,
+respectively. Tangible assets at foreign locations are not
+material. We had sales from the United States to our customers
+outside of the United States of approximately $10,006,000, $8,674,000 and
+$11,416,000 in 2008, 2007 and 2006, respectively. International sales
+do not include sales of printers made to domestic distributors or other domestic
+customers who in turn may ship those printers to international
+destinations. 
+F-20 
+Table of Contents 
+TRANSACT
+TECHNOLOGIES INCORPORATED 
+NOTES
+TO CONSOLIDATED FINANCIAL STATEMENTS 
+18.
+Quarterly results of operations (unaudited) 
+Our
+quarterly results of operations for 2008 and 2007 are as follows: 
+Quarter
+Ended 
+(In
+thousands, except per share amounts) 
+March
+31 
+June
+30 
+September
+30 
+December
+31 
+2008: 
+Net
+sales 
+$ 
+14,285 
+$ 
+16,319 
+$ 
+17,326 
+$ 
+14,277 
+Gross
+profit 
+4,779 
+5,460 
+5,894 
+4,817 
+Net
+income (loss) 
+(692 
+) 
+290 
+1,210 
+636 
+Net
+income (loss) per share: 
+Basic 
+(0.07 
+) 
+0.03 
+0.13 
+0.07 
+Diluted 
+(0.07 
+) 
+0.03 
+0.13 
+0.0 7 
+2007: 
+Net
+sales 
+$ 
+11,468 
+$ 
+13,947 
+$ 
+11,737 
+$ 
+11,614 
+Gross
+profit 
+3,753 
+4,940 
+3,885 
+3,418 
+Net
+income (loss) 
+(223 
+) 
+284 
+(1,016 
+) 
+(1,319 
+) 
+Net
+income (loss) per share: 
+Basic 
+(0.02 
+) 
+0.03 
+(0.11 
+) 
+(0.14 
+) 
+Diluted 
+(0.02 
+) 
+0.03 
+(0.11 
+) 
+(0.14 
+) 
+F-21 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+Schedule
+II 
+Valuation
+and Qualifying Accounts 
+(Amounts
+in thousands) 
+Description 
+Balance
+at Beginning of Period 
+Provision 
+Write-offs,
+net of recoveries 
+Balance
+at End of Period 
+Valuation
+account for accounts receivable: 
+Year
+ended December 31, 2008 
+$ 
+62 
+$ 
+- 
+$ 
+(7 
+) 
+$ 
+55 
+Year
+ended December 31, 2007 
+$ 
+204 
+$ 
+- 
+$ 
+(142 
+) 
+$ 
+62 
+Year
+ended December 31, 2006 
+$ 
+240 
+$ 
+- 
+$ 
+(36 
+) 
+$ 
+204 
+Valuation
+account for inventories: 
+Year
+ended December 31, 2008 
+$ 
+2,850 
+$ 
+200 
+$ 
+- 
+$ 
+3,050 
+Year
+ended December 31, 2007 
+$ 
+1,900 
+$ 
+955 
+$ 
+(5 
+) 
+$ 
+2,850 
+Year
+ended December 31, 2006 
+$ 
+2,165 
+$ 
+266 
+$ 
+(531 
+) 
+$ 
+1,900 
+F-22 
+Table of Contents 
+Index to Exhibits 
+3.1(a) 
+Certificate
+of Incorporation of TransAct Technologies Incorporated (“TransAct” or the
+“Company”), filed with the Secretary of State of Delaware on June 17,
+1996. 
+(2) 
+3.1(b) 
+Certificate
+of Amendment of Certificate of Incorporation of the Company, filed with
+the Secretary of State of Delaware on June 4, 1997. 
+(4) 
+3.1(c) 
+Certificate
+of Designation, Series A Preferred Stock, filed with the Secretary of
+State of Delaware on December 2, 1997. 
+(5) 
+3.1(d) 
+Certificate
+of Designation, Series B Preferred Stock, filed with the Secretary of
+State of Delaware on April 6, 2000. 
+(8) 
+3.2 
+Amended
+and Restated By-laws of the Company. 
+(6) 
+4.1 
+Specimen
+Common Stock Certificate. 
+(2) 
+10.1(x) 
+1996
+Stock Plan, effective July 30, 1996. 
+(3) 
+10.2(x) 
+Non-Employee
+Directors’ Stock Plan, effective August 22, 1996. 
+(3) 
+10.3(x) 
+2001
+Employee Stock Plan. 
+(10) 
+10.4(x) 
+2005
+Equity Incentive Plan. 
+(15) 
+10.5(x) 
+Employment
+Agreement, dated July 31, 1996, by and between TransAct and Bart C.
+Shuldman. 
+(2) 
+10.6(x) 
+Severance
+Agreement by and between TransAct and Michael S. Kumpf, dated September 4,
+1996. 
+(3) 
+10.7(x) 
+Severance
+Agreement by and between TransAct and Steven A. DeMartino, dated June 1,
+2004. 
+(14) 
+10.8(x) 
+Severance
+Agreement by and between TransAct and James B. Stetson, dated January 24,
+2001. 
+(9) 
+10.9(x) 
+Severance
+Agreement by and between TransAct and Tracey S. Chernay, dated July 29,
+2005. 
+(19) 
+10.10(x) 
+Amendment
+to Employment Agreement, effective
+January 1, 2008 , by and between TransAct and Bart C.
+Shuldman. 
+(1) 
+10.11(x) 
+Amendment
+to Severance Agreement by and between TransAct and Michael S. Kumpf, effective
+January 1, 2008 . 
+(1) 
+10.12(x) 
+Amendment
+to Severance Agreement by and between TransAct and Steven A. DeMartino,
+effective
+January 1, 2008 . 
+(1) 
+10.13(x) 
+Amendment
+to Severance Agreement by and between TransAct and James B. Stetson, effective
+January 1, 2008 . 
+(1) 
+10.14(x) 
+Amendment
+to Severance Agreement by and between TransAct and Tracey S. Chernay,
+effective
+January 1, 2008 . 
+(1) 
+10.15 
+Lease
+Agreement by and between Bomax Properties and Ithaca, dated as of March
+23, 1992. 
+(2) 
+10.16 
+Second
+Amendment to Lease Agreement by and between Bomax Properties and Ithaca,
+dated December 2, 1996. 
+(4) 
+10.17 
+Agreement
+regarding the Continuation and Renewal of Lease by and between Bomax
+Properties, LLC and TransAct, dated July 18, 2001. 
+(12) 
+10.18 
+Lease
+Agreement by and between Las Vegas Airport Properties LLC and TransAct
+dated December 2, 2004. 
+(14) 
+10.19 
+Lease
+Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated
+November 27, 2006. 
+(17) 
+10.20 
+OEM
+Purchase Agreement by and between GTECH Corporation, TransAct and Magnetec
+Corporation commencing July 14, 1999. (Pursuant to Rule 24-b-2
+under the Exchange Act, the Company has requested confidential treatment
+of portions of this exhibit deleted from the filed copy.) 
+(7) 
+10.21 
+OEM
+Purchase Agreement by and between GTECH Corporation and TransAct
+commencing July 2, 2002. (Pursuant to Rule 24-b-2 under the
+Exchange Act, the Company has requested confidential treatment of portions
+of this exhibit deleted from the filed copy.) 
+(11) 
+10.22 
+Amendment
+to OEM Purchase Agreement by and between GTECH Corporation and TransAct,
+dated February 17, 2006. (Pursuant to Rule 24-b-2 under the
+Exchange Act, the Company has requested confidential treatment of portions
+of this exhibit deleted from the filed copy.) 
+(16) 
+10.23 
+Amended
+and Restated Revolving Credit and Security Agreement between TransAct and
+TD Banknorth, N.A. dated November 28, 2006 
+(17) 
+10.24 
+First
+Amendment to Amended and Restated Revolving Credit and Security Agreement
+between TransAct and TD Banknorth, N.A. effective September 30,
+2007. 
+(18) 
+10.25 
+License
+Agreement between Seiko Epson Corporation and TransAct dated May 17, 2004
+(Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested
+confidential treatment of portions of this exhibit deleted from the filed
+copy.) 
+(13) 
+23.1 
+Consent
+of PricewaterhouseCoopers LLP. 
+(1) 
+31.1 
+Certification
+of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
+Act of 2002. 
+(1) 
+31.2 
+Certification
+of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
+Act of 2002. 
+(1) 
+32.1 
+Certification
+of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted
+pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.2 
+Certification
+of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted
+pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+Table of Contents 
+(1) 
+These
+exhibits are filed herewith. 
+(2) 
+These
+exhibits, which were previously filed with the Company’s Registration
+Statement on Form S-1 (No. 333-06895), are incorporated by
+reference. 
+(3) 
+These
+exhibits, which were previously filed with the Company’s Quarterly Report
+on Form 10-Q for the period ended September 30, 1996, are incorporated by
+reference. 
+(4) 
+These
+exhibits, which were previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 1997, are incorporated by
+reference. 
+(5) 
+This
+exhibit, which was previously filed with the Company’s Current Report on
+Form 8-K filed February 18, 1999, is incorporated by
+reference. 
+(6) 
+This
+exhibit, which was previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 1998, is incorporated by
+reference. 
+(7) 
+This
+exhibit, which was previously filed with the Company’s Quarterly Report on
+Form 10-Q for the period ended September 25, 1999, is incorporated by
+reference. 
+(8) 
+These
+exhibits, which were previously filed with the Company’s Quarterly Report
+on Form 10-Q for the period ended March 25, 2000, are incorporated by
+reference. 
+(9) 
+This
+exhibit, which was previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 2000, is incorporated by
+reference. 
+(10) 
+This
+exhibit, which was previously filed with the Company’s Registration
+Statement on Form S-8 (No. 333-59570), is incorporated by
+reference. 
+(11) 
+This
+exhibit, which was previously filed with the Company’s Quarterly Report on
+Form 10-Q for the period ended June 30, 2002, is incorporated by
+reference. 
+(12) 
+This
+exhibit, which was previously filed with the Company’s Quarterly Report on
+Form 10-Q for the period ended June 30, 2003, is incorporated by
+reference. 
+(13) 
+This
+exhibit, which was previously filed with the Company’s Quarterly Report on
+Form 10-Q for the period ended June 30, 2004, is incorporated by
+reference. 
+(14) 
+These
+exhibits, which were previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 2004, are incorporated by
+reference. 
+(15) 
+This
+exhibit, which was previously filed with the Company’s Current Report on
+Form 8-K filed June 1, 2005, is incorporated by
+reference. 
+(16) 
+This
+exhibit, which was previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 2005, is incorporated by
+reference. 
+(17) 
+These
+exhibits, which were previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 2006, are incorporated by
+reference. 
+(18) 
+This
+exhibit, which was previously filed with the Company’s Quarterly Report on
+Form 10-Q for the period ended September 30, 1997, is incorporated by
+reference. 
+(19) 
+This
+exhibit, which was previously filed with the Company’s Annual Report on
+Form 10-K for the year ended December 31, 2007, is incorporated by
+reference. 
+(x) 
+Management
+contract or compensatory plan or
+arrangement. 
+Table of Contents 
+EXHIBIT
+LIST 
+The
+following exhibits are filed herewith. 
+Exhibit 
+10.10(x) 
+Amendment
+to Employment Agreement, effective
+January 1, 2008 , by and between TransAct and Bart C.
+Shuldman. 
+10.11(x) 
+Amendment
+to Severance Agreement by and between TransAct and Michael S. Kumpf, effective
+January 1, 2008 . 
+10.12(x) 
+Amendment
+to Severance Agreement by and between TransAct and Steven A. DeMartino,
+effective
+January 1, 2008 . 
+10.13(x) 
+Amendment
+to Severance Agreement by and between TransAct and James B. Stetson, effective
+January 1, 2008 . 
+10.14(x) 
+Amendment
+to Severance Agreement by and between TransAct and Tracey S. Chernay,
+effective
+January 1, 2008 . 
+23.1 
+Consent
+of PricewaterhouseCoopers LLP. 
+31.1 
+Certification
+of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
+Act of 2002. 
+31.2 
+Certification
+of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
+Act of 2002. 
+32.1 
+Certification
+of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted
+pursuant to Section 906 of the Sarbanes-Oxley Act of
+2002. 
+32.2 
+Certification
+of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted
+pursuant to Section 906 of the Sarbanes-Oxley Act of
+2002.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2008/0001017303-09-000003/filing_metadata.csv b/raw/filings/0001017303/2008/0001017303-09-000003/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..aec0f5f60e35d1e162e79671a11a2743348f31e2
--- /dev/null
+++ b/raw/filings/0001017303/2008/0001017303-09-000003/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
+0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2009-03-16,2008-12-31,2009-03-16T15:49:32.000Z,0001017303-09-000003,form10-k.htm,FORM 10-K,2378099,0,0,https://www.sec.gov/Archives/edgar/data/1017303/000101730309000003/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730309000003/,2008,2008,1
diff --git a/raw/filings/0001017303/2008/0001017303-09-000003/item1.txt b/raw/filings/0001017303/2008/0001017303-09-000003/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..c0d8f757c02ce3f502fe6ac0e643f65a47a75861
--- /dev/null
+++ b/raw/filings/0001017303/2008/0001017303-09-000003/item1.txt
@@ -0,0 +1,435 @@
+Item 1. Business. 
+The
+Company 
+TransAct
+Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June
+1996 and began operating as a stand-alone business in August 1996 as a spin-off
+of the printer business that was formerly conducted by certain subsidiaries of
+Tridex Corporation. We completed an initial public offering on August
+22, 1996. 
+TransAct
+designs, develops, assembles, markets and services world-class transaction
+printers under the Epic and Ithaca® brand
+names. Known and respected worldwide for innovative designs and
+real-world service reliability, our thermal, inkjet and impact printers generate
+top-quality transaction records such as receipts, tickets, coupons, register
+journals and other documents. We focus on three core markets: (1)
+banking and point-of-sale (“POS”), (2) casino and gaming and (3)
+lottery. We sell our products to original equipment manufacturers
+("OEMs"), value-added resellers ("VARs"), selected distributors, as well as
+directly to end-users. Our product distribution spans across the
+Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean
+Islands and the South Pacific. In addition, we have a strong focus on
+the after-market side of the business, through
+our TransAct Services Group, with a growing commitment to printer
+service, supplies and spare parts. We have one primary operating
+facility located in Ithaca, NY, our printer sales headquarters and western
+region service center in Las Vegas, NV, an eastern region service center located
+in New Britain, CT, a European sales and service center in the United Kingdom,
+and a sales office located in Macau and two other sales offices located in the
+United States. Our executive offices are located at
+One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518,
+with a telephone number of (203) 859-6800. 
+Financial
+Information about Segments 
+We have
+determined that we operate in one reportable segment, the design, development,
+assembly and marketing of transaction printers and printer-related service,
+supplies and spare parts. 
+Products
+and Services 
+Printers 
+TransAct
+designs, develops, assembles and markets a broad array of transaction-based
+printers utilizing inkjet, thermal and impact printing technology for
+applications requiring up to 60 character columns, primarily in the banking,
+POS, casino, gaming and lottery markets. Our printers are
+configurable and offer customers the ability to choose from a variety of
+features and functions. Options typically include interface
+configuration, paper cutting devices, paper handling capacities and cabinetry
+color. In addition to our configurable printers, we design and
+assemble custom printers for certain OEM customers. In collaboration
+with these customers, we provide engineering and manufacturing expertise for the
+design and development of specialized printers. 
+Banking
+and POS: Our banking and POS printers include hundreds of optional
+configurations that can be selected to meet particular customer
+needs. We believe that this is a significant competitive strength, as
+it allows us to satisfy a wide variety of printing applications that our
+customers request. In the banking market, we sell printers that are
+used by banks, credit unions and other financial institutions to print and/or
+validate receipts at bank teller stations. In the POS market, we sell
+several models of printers utilizing inkjet, thermal and impact printing
+technology. Our printers are used primarily by retailers in the
+restaurant (including fine dining, casual dining, and fast food), hospitality,
+and specialty retail industries to print receipts for consumers, validate
+checks, or print on other inserted media. 
+Lottery: We
+supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”),
+our largest customer and the world’s largest provider of lottery
+terminals, with an approximate 70% market share. These printers are
+designed for high-volume, high-speed printing of lottery tickets for various
+lottery applications. 
+Casino
+and gaming: We sell several models of printers used in slot machines
+and video lottery terminals that print tickets or receipts instead of issuing
+coins at casinos, racetracks and other gaming establishments
+worldwide. These printers utilize thermal printing technology and can
+print tickets or receipts in monochrome or two-color (depending upon the model),
+and offer various other features such as jam resistant bezels and a dual port
+interface that will allow casinos to print coupons/promotions. In
+addition, we sell printers using thermal and impact printing technology for use
+in non-casino establishments, including game types such as Amusements with
+Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”),
+Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines
+around the world. 
+TransAct
+Services Group 
+Through
+our TransAct Services Group, we proactively market the sale of consumable
+products (including inkjet cartridges, ribbons,
+receipt paper and other transaction supplies ), replacement parts and
+maintenance services for all of our products and certain competitor’s
+products. Our maintenance services include the sale of extended
+warranties, multi-year maintenance contracts, 24-hour guaranteed replacement
+product service TransAct Xpress SM ,
+and other repair services for our printers. Within the United States,
+we provide repair services through our eastern region service center in New
+Britain, CT and our western region service center in Las Vegas,
+NV. Internationally, we provide repair services through our European
+service center located in Doncaster, United Kingdom, and through partners
+strategically located around the world. 
+1 
+Table of Contents 
+We also
+provide customers with telephone sales and technical support, and a personal
+account representative to handle orders, shipping and general
+information. Technical and sales support personnel receive training
+on all of our manufactured products and our services. 
+In
+addition to personalized telephone and technical support, we also market and
+sell consumable products 24 hours a day, seven days a week, via our online
+webstore www.transactsupplies.com . 
+Product
+Warranty 
+Our
+printers generally carry up to a two-year limited warranty against defects in
+material and workmanship. Defective equipment may be returned to any
+of our service centers, or our assembly facility in Ithaca, NY for
+newly-released printers only, for repair or replacement during the applicable
+warranty period. 
+Production,
+Manufacturing and Sources and Availability of Raw Materials 
+We design
+our products to optimize product performance, quality, reliability and
+durability. These designs combine cost efficient materials, sourcing
+and assembly methods with high standards of workmanship. During 2008,
+we began a program to transfer final assembly for approximately 70% of our total
+printer production to a third-party contract manufacturer in China by the end of
+2009. As of December 31, 2008, we had transferred approximately
+30% of our total production to this contract manufacturer, and we expect the
+remaining 40% to be transferred during 2009. Over the remainder of
+2009, we will continue to finalize assembly for some of our products in our
+Ithaca, NY facility largely on a configure-to-order basis using components and
+subassemblies that have been sourced from vendors or contract manufacturers
+around the world. However, we plan to decrease in-house printer
+production in Ithaca, NY by printer model as the assembly of that printer model
+is transferred to our contract manufacturer. 
+We
+procure component parts and subassemblies for use in the assembly of our
+products in Ithaca, NY. Critical component parts and subassemblies
+include inkjet, thermal and impact printheads, printing/cutting mechanisms,
+power supplies, motors, injection molded plastic parts, circuit boards and
+electronic components, which are obtained from domestic and foreign suppliers at
+competitive prices. With the transition of 70% of our production to
+our contract manufacturer, during 2009 we expect purchases of component parts
+will decline, while purchases of fully-assembled printers will increase, as
+in-house printer assembly in Ithaca, NY declines and assembly by our contract
+manufacturer increases. Furthermore, during this transition, we
+expect inventories to temporarily rise, as we plan to increase our stocking
+levels to ensure product availability to meet our customers’
+demands. We typically strive to maintain more than one source for our
+component parts, subassemblies and fully assembled printers to reduce the risk
+of parts shortages or unavailability. However, we could experience
+temporary disruption if certain suppliers ceased doing business with us, as
+described below. 
+We
+currently buy substantially all of our thermal print mechanisms, an important
+component of our thermal printers, and fully assembled printers for several of
+our printer models, from one foreign contract manufacturer. Although
+we believe that other contract manufacturers could provide similar thermal print
+mechanisms or fully assembled printers, on comparable terms, a change in
+contract manufacturers could cause a delay in manufacturing and possible loss of
+sales, which may have a material adverse effect on our operating
+results. 
+Hewlett-Packard
+Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of
+our inkjet printers. The loss of the supply of HP inkjet cartridges
+would have a material adverse effect on the sale of our inkjet
+printers. Prior to February 2006, we had a supply agreement with HP
+to purchase inkjet cartridges at fixed prices. This agreement expired
+on February 1, 2006 and was not renewed, as HP informed us that they no longer
+maintain supply agreements for these inkjet cartridges; however, we continue to
+purchase inkjet cartridges from HP. Although we no longer have a
+supply agreement with HP, our relationship with HP remains strong and we have no
+reason to believe that HP will discontinue its supply of inkjet cartridges to
+us. The inkjet cartridges we purchase from HP are used not only in
+our inkjet printers for the banking and POS market, but also in other
+manufacturer’s printing devices across several other markets. 
+Okidata
+Americas, Inc. (“Okidata”) is the sole supplier for an impact printer component
+kit consisting of a printhead, control board and carriage (the “Oki Kit”) that
+is used in all of our Ithaca â brand impact
+printers. The loss of the supply of Oki Kits would have a material
+adverse effect on TransAct. However, sales of impact printers
+continue to decline as sales of these printers are replaced by sales of thermal
+and inkjet printers. As such,
+we believe that any possible loss of supply of Oki Kits will continue to have
+less of an impact on TransAct in 2009 and beyond. Although we do not
+have a supply agreement with Okidata, our relationship with Okidata remains
+strong and we have no reason to believe that Okidata will discontinue its supply
+of Oki Kits to us during 2009 or that their terms to us will be any less
+favorable than they have been historically. 
+2 
+Table of Contents 
+Patents
+and Proprietary Information 
+We have
+significantly expanded our patent portfolio since 2002, and expect to continue
+to do so in the future. We also believe our patent portfolio could
+provide additional opportunities to license our intellectual property in the
+future. We hold 23 United States and 19 foreign patents and have 8
+United States and 72 foreign patent applications pending pertaining to our
+products. The duration of these patents range from 10 to 18
+years. The expiration of any individual patent would not have a
+significant negative impact on our business. We regard certain
+manufacturing processes and designs to be proprietary and attempt to protect
+them through employee and third-party nondisclosure agreements and similar
+means. It may be possible for unauthorized third parties to copy
+certain portions of our products or to reverse engineer or otherwise obtain and
+use, to our detriment, information that we regard as
+proprietary. Moreover, the laws of some foreign countries do not
+afford the same protection to our proprietary rights as do United States laws.
+There can be no assurance that legal protections relied upon by the Company to
+protect our proprietary position will be adequate or that our competitors will
+not independently develop technologies that are substantially equivalent or
+superior to our technologies. 
+Seasonality 
+Retailers
+typically reduce purchases of new POS equipment in the fourth quarter, due to
+the increased volume of consumer transactions in that holiday period, and our
+sales of printers in the POS market historically have increased in the third
+quarter and decreased in the fourth quarter. Similarly, installations
+of lottery terminals are typically reduced in the fourth quarter, resulting in
+decreased sales of lottery printers. 
+Certain
+Customers 
+We
+currently have an ongoing OEM purchase agreement, as amended in February 2006
+(the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of
+thermal on-line lottery printers and spare parts, at fixed prices, through June
+28, 2012. During 2008, sales to GTECH accounted for 28% of our net
+sales, and no other customer individually accounted for more than 10% of total
+net product sales. Firm purchase orders for printers under the GTECH
+Thermal Printer Agreement may be placed as required by GTECH. Prior
+to this agreement, we had a purchase agreement with GTECH that provided for the
+sale of impact on-line lottery printers and spare parts through December 31,
+2004. Because our new thermal on-line lottery printer is a
+replacement for our impact on-line printer, we do not expect any further
+shipments of impact on-line lottery printers. However, we do expect
+to continue to sell spare parts to GTECH for the remaining installed base of
+impact on-line lottery printers, although we expect such sales to decline as the
+installed base of impact on-line lottery printers are replaced with our thermal
+printer. 
+Backlog 
+Our
+backlog of firm orders was approximately $9,994,000 as of February 28,
+2009, compared to $9,123,000 as of February 29, 2008. Based on
+customers’ current delivery requirements, we expect to ship our entire current
+backlog during 2009. 
+Competition 
+The
+market for transaction-based printers is extremely competitive, and we expect
+such competition to continue in the future. We compete with a number of
+companies, many of which have greater financial, technical and marketing
+resources than us. We believe our ability to compete successfully depends on a
+number of factors both within and outside our control, including durability,
+reliability, quality, design capability, product customization, price, customer
+support, success in developing new products, manufacturing expertise and
+capacity, supply of component parts and materials, strategic relationships with
+suppliers, the timing of new product introductions by us and our competitors,
+general market, economic and political conditions and, in some cases, the
+uniqueness of our products. 
+In the
+banking and POS market, our major competitor is Epson America, Inc., which holds
+a dominant market position of the POS markets into which we sell. We
+also compete, to a much lesser extent, with Transaction Printer Group, Star
+Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources,
+Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours
+have greater financial resources, lower costs attributable to higher volume
+production and sometimes offer lower prices than us. 
+In the
+lottery market (consisting principally of on-line lottery transaction printing),
+we hold a leading position, based largely on our long-term purchase agreement
+with GTECH, which holds approximately 70% market share of the worldwide on-line
+lottery market. We compete in this market based solely on our ability
+to provide specialized, custom-engineered products to GTECH. 
+In the
+casino and gaming market (consisting principally of slot machine and video
+lottery terminal transaction printing), we compete with several companies
+including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and
+others. Certain of our products sold for casino and gaming
+applications compete based upon our ability to provide highly specialized
+products, custom engineering and ongoing technical support. 
+The
+TransAct Services Group business is highly fragmented, and we compete with
+numerous competitors of various sizes depending on the geographic
+area. 
+3 
+Table of Contents 
+Our
+strategy for competing in our markets is to continue to develop new products and
+product line extensions, to increase our geographic market penetration, to take
+advantage of strategic relationships, and to lower product costs by sourcing
+certain products overseas. Although we believe that our products,
+operations and relationships provide a competitive foundation, there can be no
+assurance that we will compete successfully in the future. In
+addition, our products utilize certain inkjet, thermal and impact printing
+technology. If other technologies, or variations to existing
+technologies were to evolve or become available to us, it is possible that we
+would incorporate these technologies into our
+products. Alternatively, if such technologies were to evolve or
+become available to our competitors, our products could become obsolete, which
+would have a significant negative impact on our business. 
+Research
+and Development Activities 
+We spent
+approximately $2,942,000, $3,129,000 and $2,824,000 in 2008, 2007 and 2006,
+respectively, on engineering, design and product development efforts in
+connection with specialized engineering and design to introduce new products and
+to customize existing products. 
+Environment 
+We are
+not aware of any material noncompliance with federal, state and local provisions
+that have been enacted or adopted regulating the discharge of materials into the
+environment, or otherwise relating to the protection of the
+environment. 
+Employees 
+As of
+February 28, 2009, TransAct and our subsidiaries employed 151 persons, of whom
+150 were full-time and 1 was a temporary employee. None of our
+employees are unionized, and we consider our relationships with our employees to
+be good. 
+Financial
+Information About Geographic Areas 
+We have
+foreign operations primarily from TransAct Technologies Ltd., a wholly-owned
+subsidiary located in the United Kingdom, which had sales to its customers of
+$120,000, $2,121,000 and $2,722,000 in 2008, 2007 and 2006,
+respectively. We had export sales from our domestic operations of
+approximately $10,006,000, $8,674,000 and $11,416,000 in 2008, 2007 and 2006,
+respectively. Total international sales, which include sales from our
+foreign subsidiary and export sales from our domestic operations, were
+approximately $10,126,000, $10,795,000 and $14,138,000 in 2008, 2007 and 2006,
+respectively. 
+Additional
+Information 
+We make
+available free of charge through our internet website, www.transact-tech.com ,
+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 as soon as reasonably
+practicable after such material is electronically filed with or furnished to the
+SEC. 
+We
+maintain a Code of Business Conduct that includes our code of ethics that is
+applicable to all employees, including our Chief Executive Officer, Chief
+Financial Officer and Controller. This Code, which requires continued
+observance of high ethical standards such as honesty, integrity and compliance
+with the law in the conduct of our business, is available for public access on
+our internet website. Any person may request a copy of our Code of
+Business Conduct free of charge by calling (203) 859-6800. 
+Executive
+Officers of the Registrant 
+The
+following list is included as an unnumbered item in Part I of this Report in
+lieu of being included in the Proxy Statement for the Annual Meeting of
+Stockholders to be held on May 28 , 2009 . 
+The
+following is a list of the names and ages of all executive officers of the
+registrant, indicating all positions and offices with the registrant held by
+each such person and each person’s principal occupations and employment during
+at least the past five years. 
+Name 
+Age 
+Position 
+Bart
+C. Shuldman 
+51 
+Chairman
+of the Board, President and Chief Executive Officer 
+Steven
+A. DeMartino 
+39 
+Executive
+Vice President, Chief Financial Officer, Treasurer and
+Secretary 
+Michael
+S. Kumpf 
+59 
+Executive
+Vice President-Engineering 
+James
+B. Stetson 
+52 
+Senior
+Vice President and Business Manager of the TransAct Services
+Group 
+Tracey
+S. Chernay 
+49 
+Senior
+Vice President-Sales and Marketing 
+Andrew
+Hoffman 
+51 
+Senior
+Vice
+President-Operations 
+Bart C.
+Shuldman has been Chief Executive Officer, President and a Director of the
+Company since its formation in June 1996. In February 2001, Mr.
+Shuldman was elected Chairman of the Board. 
+Steven A.
+DeMartino was named as TransAct’s Executive Vice President, Chief Financial
+Officer, Treasurer and Secretary on June 1, 2004. Previously, Mr.
+DeMartino served as Senior Vice President, Finance and Information Technology
+from October 2001 to May 2004, Vice President and Corporate Controller from
+January 1998 to October 2001, and Corporate Controller from August 1996 to
+December 1997. Mr. DeMartino is a certified public
+accountant. 
+4 
+Table of Contents 
+Michael
+S. Kumpf was appointed Executive Vice President of Engineering in March
+2002. He served as Senior Vice President, Engineering from June 1996
+to March 2002. 
+James B.
+Stetson was appointed Senior Vice President and Business Manager of TransAct
+Services Group in January 2005. Previously, Mr. Stetson held the
+position of Executive Vice President of Sales and Marketing from February 2000
+to December 2004, and Vice President of Latin American Sales from October 1997
+to February 2000. 
+Tracey S.
+Chernay was appointed Senior Vice President, Sales and Marketing in June 2007,
+with responsibility for the sales and marketing of all TransAct printer products
+worldwide. Previously Ms. Chernay served as Sr. Vice President,
+Marketing & Sales, POS & Banking with the Company from July 2006 to June
+2007, and joined TransAct in May of 2005 as Senior Vice President,
+Marketing. Prior to joining TransAct, Ms. Chernay was employed with
+Xerox Corporation where she held the role of Manager, Worldwide Marketing since
+2003, and Manager, Sales Operations from 2000 to 2002. She joined
+Xerox Corporation in 1983. 
+Andrew
+Hoffman was appointed Senior Vice President, Operations for TransAct worldwide
+in November 2004. He served as Vice President, Operations from
+September 1994 to November 2004.
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@@ -0,0 +1,6 @@
+Item 13. Certain Relationships and Related Transactions, and
+Director Independence. 
+The
+information in response to this item is incorporated by reference from the Proxy
+Statement section entitled “Certain Relationships and Related
+Transactions.”
\ No newline at end of file
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@@ -0,0 +1,79 @@
+Item 9A. Controls and Procedures . 
+Attached
+as exhibits to this Form 10-K are certifications of our Chief Executive Officer
+(“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance
+with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the
+Exchange Act). This “Controls and Procedures” section includes
+information concerning the controls and controls evaluation referred to in the
+certifications. Part II, Item 8 of this Form 10-K sets forth the
+report of PricewaterhouseCoopers LLP, our independent registered public
+accounting firm, regarding its audit of TransAct’s internal control over
+financial reporting as of December 31, 2008. This section should be read
+in conjunction with the CEO and CFO certifications and the
+PricewaterhouseCoopers LLP report for a more complete understanding of the
+topics presented. 
+Evaluation
+of Disclosure Controls and Procedures 
+As of
+December 31, 2008, the Company, with the participation of its CEO and CFO
+conducted an evaluation of the effectiveness of the design and operation of the
+Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the
+Securities Exchange Act of 1934 (the “Exchange Act”). Based on that
+evaluation, our CEO and CFO concluded that the Company’s disclosure controls and
+procedures (as defined in Rule 13a-15 of the Exchange Act) are
+effective. 
+Management’s
+Report on Internal Control Over Financial Reporting 
+Our
+management is responsible for establishing and maintaining adequate internal
+control over financial reporting to provide reasonable assurance regarding the
+reliability of our financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted
+accounting principles. 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. 
+Management
+assessed our internal control over financial reporting as of December 31, 2008.
+Management based its assessment on criteria established in Internal
+Control–Integrated Framework issued by the Committee of Sponsoring Organizations
+of the Treadway Commission (“COSO”). 
+Based on
+our assessment, management has concluded that our internal control over
+financial reporting was effective as of December 31, 2008. 
+The
+effectiveness of the Company’s internal control over financial reporting as of
+December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an
+independent registered public accounting firm, as stated in their report which
+appears herein. 
+Inherent
+Limitations on Effectiveness of Controls 
+A control
+system, no matter how well designed and operated, can provide only reasonable,
+not absolute, assurance that the control system’s objectives will be
+met. 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. Further, because of the inherent limitations
+in all control systems, no evaluation of controls can provide absolute assurance
+that misstatements due to error or fraud will not occur or that all control
+issues and instances of fraud, if any, within the 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 errors or mistakes. Controls
+can also be circumvented by the individual acts of some persons, by collusion of
+two or more people, or by management override of the controls. The
+design of any system of controls is based in part on 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. Projections of any evaluation of controls effectiveness to
+future periods are subject to risks. Over time, controls may become
+inadequate because of changes in conditions or deterioration in the degree of
+compliance with policies or procedures.
\ No newline at end of file
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@@ -0,0 +1,53 @@
+approval of related party transactions. As part of a review of
+possible related person transactions, the Company annually distributes and
+collects questionnaires that solicit information about any direct or indirect
+transactions with the Company from each of our directors and
+officers. 
+Our
+Standards of Business Conduct require all directors, officers and employees to
+avoid any situation that involves an actual or apparent conflict of interest in
+personal and professional relationships or with their duty to, or with any
+interest of, the Company. Under the Standards of Business Conduct,
+situations that involve, or may reasonably be inferred to involve, a conflict
+between a director, officer or employee’s personal interests and the interests
+of the Company should be disclosed to the Chair of the Audit
+Committee. The Audit Committee is then
+responsible for reviewing the related party transaction. No
+related party transaction shall be approved or ratified if such transaction is
+contrary to the best interests of the Company. In determining whether to approve or ratify a related
+party transaction, the Audit Committee takes into account such factors as it
+deems appropriate, which may include whether the interested transaction is on
+terms no less favorable than terms generally available to an unaffiliated third
+party under the same or similar circumstances and the extent of the related
+person’s interest in the transaction . 
+From
+January 1, 2008 to the date of this proxy statement, there have not been any
+transactions of the type described in Item 404 of Regulation S-K, and currently
+no such transactions are proposed. 
+CORPORATE
+GOVERNANCE 
+The
+Company strives to maintain corporate governance practices that benefit the
+long-term interests of the Company’s stockholders by clearly outlining the
+Company’s duties and responsibilities, providing a framework for active and
+fruitful discussions among the members of the Board of Directors and between the
+Board and management, and avoiding conflicts of interest and other legal and
+ethical problems. Accordingly, the Company’s corporate governance practices are
+designed not only to satisfy regulatory requirements, but also to provide for
+effective management of the Company. 
+3 
+Information
+on the Company’s corporate governance practices is available to the public under
+“Corporate Governance” on the Company’s website at www.transact-tech.com. The
+information on the website includes the Company’s Corporate Governance
+Principles, the charters of each of the Company’s Committees, and the Company’s
+Standards of Business Conduct, which includes a code of ethics applicable to the
+officers responsible for financial reporting, the Chief Executive Officer, Chief
+Financial Officer and Controller. The Company encourages its
+directors to attend all Board meetings as well as the Annual
+Meeting. One of the directors attended the Company’s 2008 Annual
+Meeting. Each director attended at least 90% of the Company’s Board
+meetings held in 2008 and 100% of applicable Committee meetings. 
+Board
+Size 
+The
\ No newline at end of file
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@@ -0,0 +1,3491 @@
+10-K
+1
+form10-k.htm
+FORM 10-K
+form10-k.htm 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2009 
+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: 0-21121 
+______________________________________________________________________ 
+______________________________________________________________________ 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+06-1456680 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT 
+06518 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code 203-859-6800 
+______________________________________________________________________ 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Exchange on which Registered 
+Common Stock, par value $.01 per share 
+NASDAQ Global 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 o 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 o 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 o 
+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 (§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  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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer  
+Accelerated filer  
+Non-accelerated filer  (Do not check if a smaller reporting company) 
+Smaller reporting company ý 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý 
+The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the Registrant was approximately $43,500,000 based on the last sale price on June 30, 2009. 
+As of February 26, 2010, the registrant had outstanding 9,364,858 shares of common stock, $0.01 par value. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the TransAct Technologies Incorporated Proxy Statement to be filed with the Securities and Exchange Commission within 120 days after the year covered by this Form 10-K with respect to the 2010 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX 
+PART I. 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+4 
+Item 1B. 
+Unresolved Staff Comments 
+9 
+Item 2. 
+Properties 
+9 
+Item 3. 
+Legal Proceedings 
+9 
+Item 4. 
+Submission of Matters to a Vote of Security Holders 
+9 
+PART II. 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+9 
+Item 6. 
+Selected Financial Data 
+11 
+Item 7. 
+Management's Discussion and Analysis of Financial Condition and Results of Operations 
+11 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+24 
+Item 8. 
+Financial Statements and Supplementary Data 
+24 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+24 
+Item 9A. 
+Controls and Procedures 
+25 
+Item 9B. 
+Other Information 
+25 
+PART III. 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+25 
+Item 11. 
+Executive Compensation 
+26 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+26 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+27 
+Item 14. 
+Principal Accountant Fees and Services 
+27 
+PART IV. 
+Item 15. 
+Exhibits and Financial Statement Schedules 
+27 
+SIGNATURES 
+Signatures 
+28 
+CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE 
+Index to Consolidated Financial Statements and Schedule 
+F-1 
+EXHIBITS 
+Index to Exhibits 
+Table of Contents 
+PART I 
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops, assembles, markets and services world-class transaction printers under the Epic and Ithaca® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers generate top-quality transaction records such as receipts, tickets, coupons, register journals and other documents. We focus on the following core markets: banking and point-of-sale (“POS”), casino and gaming, and lottery. We sell our products to original equipment manufacturers ("OEMs"), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. Beyond printers, TransAct provides printing supplies to the full transaction printer market. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables items used in the printing and scanning activities of customers in the hospitality, banking, retail, gaming, and government markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating facility and eastern region service center located in Ithaca, NY, our printer sales headquarters and western region service center in Las Vegas, NV, a printhead manufacturing and repair center located in New Britain, CT, a European sales and service center in the United Kingdom, a sales office located in Macau and two other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518, with a telephone number of (203) 859-6800. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction printers and printer-related service, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers 
+TransAct designs, develops, assembles and markets a broad array of transaction-based printers utilizing inkjet, thermal and impact printing technology for applications requiring up to 60 character columns, primarily in the banking, POS, casino, gaming and lottery markets. Our printers are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Banking and POS: Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We us an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of a dedicated internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals, with an approximate 70% market share. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals that print tickets or receipts instead of issuing coins at casinos, racetracks and other gaming establishments worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that will allow casinos to print coupons/promotions. In addition, we sell printers using thermal and impact printing technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through three regional distributors (one in the United States and Asia, one in Europe and Africa, and one in Australia). We also maintain a dedicated sales force to solicit sales from slot manufacturers and casinos, as well as manage sales through our distributors. 
+1 
+Table of Contents 
+TSG 
+Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper and other transaction supplies), replacement parts and maintenance services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. During 2009, we completed a program to transfer final assembly for approximately 70% of our total printer production to a third-party contract manufacturer in China. We continue to perform final assembly for the remaining 30% of our products in our Ithaca, NY facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY. Critical component parts and subassemblies include inkjet, thermal and impact printheads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of transitioning 70% of our production to our contract manufacturer, 2009 purchases of component parts declined, while purchases of fully-assembled printers increased, due to the decline of in-house printer assembly in Ithaca, NY and the increase of assembly by our contract manufacturer. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturer, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2010 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. The loss of the supply of HP inkjet cartridges would have a material adverse effect on both the sale of our inkjet printers and TSG consumable products. Our relationship with HP remains strong and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be any less favorable than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+Okidata Americas, Inc. (“Okidata”) is the sole supplier for an impact printer component kit consisting of a printhead, control board and carriage (the “Oki Kit”) that is used in all of our Ithaca â brand impact printers. The loss of the supply of Oki Kits would have a material adverse effect on us. However, sales of impact printers continue to decline as sales of these printers are replaced by sales of thermal and inkjet printers. As such, we believe that any possible loss of supply of Oki Kits will continue to have less of an impact on us in 2010 and beyond. Although we do not have a supply agreement with Okidata, our relationship with Okidata remains strong and we have no reason to believe that Okidata will discontinue its supply of Oki Kits to us during 2010 or that their terms to us will be any less favorable than they have been historically. 
+Patents and Proprietary Information 
+We have significantly expanded our patent portfolio since 2002, and expect to continue to do so in the future. We also believe our patent portfolio could provide additional opportunities to license our intellectual property in the future. We hold 24 United States and 27 foreign patents and have 9 United States and 54 foreign patent applications pending pertaining to our products. The duration of these patents range from 8 to 16 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain 
+manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise 
+2 
+Table of Contents 
+obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+Seasonality 
+Retailers typically reduce purchases of new POS equipment in the fourth quarter due to the increased volume of consumer transactions in that holiday period, and our sales of printers in the POS market historically have increased in the third quarter and decreased in the fourth quarter. Similarly, installations of lottery terminals are typically reduced in the fourth quarter, resulting in decreased sales of lottery printers. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH is our most significant customer. We currently have an ongoing OEM purchase agreement, as amended in February 2006 (the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of thermal on-line lottery printers and spare parts, at fixed prices, through June 28, 2012. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH New Thermal Printer Agreement”). Under the terms of the new agreement, we will provide GTECH with their next generation thermal lottery printers for various lottery applications. The terms of the new agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH. The exclusivity period will extend for four years from the start of production of the new printer, which is expected to commence in the fall of 2010. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2009 
+2008 
+2007 
+GTECH 
+19 
+% 
+28 
+% 
+14 
+% 
+Customer A 
+10 
+% 
+* 
+10 
+% 
+Customer B 
+12 
+% 
+* 
+* 
+* Customers represented less than 10% of total net sales 
+Backlog 
+Our backlog of firm orders was approximately $6,976,000 as of February 26, 2010, compared to $9,994,000 as of February 28, 2009. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2010. 
+Competition 
+The market for transaction-based printers is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group, Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreements with GTECH, which holds approximately 70% market share of the worldwide on-line lottery market. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+3 
+Table of Contents 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including internet resellers, depending on the geographic area. 
+Our strategy for competing in our markets is to continue to develop new products and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $2,788,000, $2,942,000 and $3,129,000 in 2009, 2008 and 2007, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new products and to customize or improve existing products. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of February 26, 2010, TransAct and our subsidiaries employed 143 persons, of whom 140 were full-time and 3 were temporary employees. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 16 – Geographic Area Information in the Notes to the Consolidated Financial Statements. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. You may read and copy any materials filed with the Securities and Exchange Commission at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the Securities and Exchange Commission at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800. 
+Item 1A. Risk Factors 
+Investors should carefully consider the risks, uncertainties and other factors described below, as well as other disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, because they could have a material adverse effect on our business, financial condition, operating results, and growth prospects. The risks described below are not the only ones facing our Company. Additional risks not known to us now or that we currently deem immaterial may also impair our business operations. 
+We assume no obligation (and specifically disclaim any such obligation) to update these Risk Factors or any other forward-looking statements contained in this Annual Report to reflect actual results, changes in assumptions or other factors affecting such forward-looking statements, except as required by law. 
+Current economic conditions and market disruptions may adversely affect our business and results of operations. 
+As widely reported, financial markets throughout the world experienced extreme disruption in 2008 and 2009, including, among other things, extreme volatility in security prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, failure and potential failures of major financial institutions and unprecedented government support of financial institutions. The financial, casino and gaming industries have been more severely impacted by the current economic downturn than other industries and this 
+4 
+Table of Contents 
+may lead our customers in these industries to reduce, or discontinue, spending on our products which could adversely impact our business. A recurrence of these developments or a continuation of the general economic downturn may adversely impact our business and financial condition in a number of additional ways, including impacts beyond those typically associated with other recent downturns in the U.S. and foreign economies. The slowdown could lead to reduced capital spending by end users, which could adversely affect our product sales. A tightening of credit in financial markets and the general economic downturn may adversely affect the ability of our customers, suppliers, outsource manufacturer and channel partners (e.g., distributors and resellers) to obtain financing for significant purchases and operations and to perform their obligations with the Company. The tightening could result in a decrease in or cancellation of orders for our products and services, could negatively impact our ability to collect our accounts receivable on a timely basis, could result in additional reserves for uncollectible accounts receivable being required, and in the event of the contraction in our sales, could lead to excess inventory and require additional reserves for obsolescence. Significant volatility and fluctuations in the rates of exchange for the U.S. dollar against foreign currencies could negatively impact our customer pricing and adversely affect our results. 
+We are unable to predict the duration and severity of the current economic downturn and disruption in financial markets or their effects on our business and results of operations, but the consequences may be materially adverse and more severe than other recent economic slowdowns. 
+Our success will depend on our ability to sustain and manage growth. 
+As part of our business strategy, we intend to pursue an aggressive growth strategy. Assuming this growth occurs, it will require the expansion of distribution relationships in international markets, the successful development and marketing of new products, expanded customer service and support, and the continued implementation and improvement of our operational, financial and management information systems. 
+To the extent that we seek growth through acquisitions, our ability to manage our growth will also depend on our ability to integrate businesses that have previously operated independently. We may not be able to achieve this integration without encountering difficulties or experiencing the loss of key employees, customers or suppliers. It may be difficult to design and implement effective financial controls for combined operations and differences in existing controls for each business may result in weaknesses that require remediation when the financial controls and reporting functions are combined. As we pursue acquisitions, we may incur legal, accounting and other transaction related expenses for unsuccessful acquisition attempts that could adversely affect our results of operations in the period in which they are incurred. 
+There can be no assurance that we will be able to successfully implement our growth strategy, or that we can successfully manage expanded operations. As the Company expands, we may from time to time experience constraints that will adversely affect our ability to satisfy customer demand in a timely fashion. Failure to manage growth effectively could adversely affect our results of operations and financial condition. 
+In the lottery market, we have been dependent on sales to one large customer; the loss of this customer or reduction in orders from this customer could materially affect our sales. 
+We expect that sales to one large customer will continue to represent a significant percentage of our net sales for the foreseeable future. A reduction, delay or cancellation in orders from this customer, including reductions or delays due to market, economic, or competitive conditions in the industries in which we serve, could have a material adverse effect upon our results of operations. 
+We rely on resellers to sell our products and services. 
+We use a variety of distribution channels, including OEMs and distributors, to market our products. We may be adversely impacted by any conflicts that could arise between and among our various sales channels. 
+Our dependence upon resellers exposes us to numerous risks, including: 
+· 
+loss of channel and the ability to bring new products to market; 
+· 
+concentration of credit risk, including disruption in distribution should the resellers’ financial condition deteriorate; 
+· 
+reduced visibility to end user demand and pricing issues which makes forecasting more difficult; 
+· 
+resellers leveraging their buying power to change the terms of pricing, payment and product delivery schedules; and 
+· 
+direct competition should a reseller decide to manufacture printers internally or source printers from a competitor. 
+We cannot guarantee that resellers will not reduce, delay or eliminate purchases from us, which could have a material adverse effect upon the business, consolidated results of operations and financial condition. 
+Our operating results and financial condition may fluctuate. 
+Our operating results and financial condition may fluctuate from quarter to quarter and year to year and are likely to continue to vary due to a number of factors, many of which are not within our control. If our operating results do not meet the expectations of securities analysts or investors, who may derive their expectations by extrapolating data from recent historical operating results, the market price of our common stock will likely decline. Fluctuations in our operating results and financial condition may be due to a number of factors, including, but not limited to, those identified throughout this “Risk Factors” section: 
+5 
+Table of Contents 
+· 
+market acceptance of our products, both domestically and internationally; 
+· 
+development of new competitive printers by others; 
+· 
+our responses to price competition; 
+· 
+our level of research and development activities; 
+· 
+changes in the amount that we spend to develop, acquire or license new products, consumables, technologies or businesses; 
+· 
+changes in the amount we spend to promote our products and services; 
+· 
+changes in the cost of satisfying our warranty obligations and servicing our installed base of printers; 
+· 
+delays between our expenditures to develop and market new or enhanced printers and consumables and the generation of sales from those products; 
+· 
+the geographic distribution of our sales; 
+· 
+availability of third-party components at reasonable prices; 
+· 
+general economic and industry conditions, including changes in interest rates affecting returns on cash balances and investments, that affect customer demand; 
+· 
+severe weather events (such as hurricanes) that can disrupt or interrupt the operation of our customers or suppliers facilities; and 
+· 
+changes in accounting rules. 
+Due to all of the foregoing factors, and the other risks discussed in this report, quarter-to-quarter comparisons of our operating results may not be an indicator of future performance. 
+We depend on key personnel, the loss of which could materially impact our business. 
+Our future success will depend in significant part upon the continued service of certain key management and other personnel and our continuing ability to attract and retain highly qualified managerial, technical and sales and marketing personnel. There can be no assurance that we will be able to recruit and retain such personnel. The loss of either Bart C. Shuldman, the Company's Chairman of the Board, President and Chief Executive Officer, or Steven A. DeMartino, Executive Vice President, Chief Financial Officer, Treasurer and Secretary, or the loss of certain groups of key employees, could have a material adverse effect on our results of operations. 
+Our stock price may fluctuate significantly. 
+The market price of our common stock could fluctuate significantly in response to variations in quarterly operating results and other factors, such as: 
+· 
+changes in our business, operations or prospects; 
+· 
+developments in our relationships with our customers; 
+· 
+announcements of new products or services by us or by our competitors; 
+· 
+announcement or completion of acquisitions by us or by our competitors; 
+· 
+changes in existing or adoption of additional government regulations; 
+· 
+unfavorable or reduced analyst coverage; and 
+· 
+prevailing domestic and international market and economic conditions. 
+In addition, the stock market has experienced significant price fluctuations in recent years. Broad market fluctuations, general economic conditions and specific conditions in the industries in which we operate may adversely affect the market price of our common stock. 
+Limited trading volume of our capital stock may contribute to its price volatility. 
+Our common stock is traded on the NASDAQ Global Market. During the twelve months ended December 31, 2009, the average daily trading volume for our common stock as reported by the NASDAQ Global Market was approximately 28,000 shares. We are uncertain whether a more active trading market in our common stock will develop. In addition, many investment banks no longer find it profitable to provide securities research on micro-cap and small-cap companies. If any analyst were to discontinue coverage of our common stock, our trading volume may be further reduced. As a result, relatively small trades may have a significant impact on the market price of our common stock, which could increase the volatility and depress the price of our common stock. 
+Future sales of our common stock may cause our stock price to decline. 
+In the future, we may sell additional shares of our common stock in public or private offerings, and we may also issue additional shares of our common stock to finance future acquisitions. Shares of our common stock are also available for future sale pursuant to stock options that we have granted to our employees, and in the future we may grant additional stock options and other forms of equity compensation to our employees. Sales of our common stock or the perception that such sales could occur may adversely affect prevailing market prices for shares of our common stock and could impair our ability to raise capital through future offerings. 
+If we are unable to enforce our patents or if it is determined that we infringe patents held by others it could damage our business. Prosecuting and defending patent lawsuits is very expensive. We are committed to aggressively asserting and defending our technology and 
+6 
+Table of Contents 
+related intellectual property, which we have spent a significant amount of money to develop. These factors could cause us to become involved in new patent litigation in the future. The expense of prosecuting or defending these future lawsuits could also have a material adverse effect on our business, financial condition and results of operations. 
+If we were to lose a patent lawsuit in which another party is asserting that our products infringe its patents, we would likely be prohibited from marketing those products and could also be liable for significant damages. Either or both of these results may have a material adverse effect on our business, financial condition and results of operations. If we lose a patent lawsuit in which we are claiming that another party’s products are infringing our patents and thus, are unable to enforce our patents, it may have a material adverse effect on our business, financial condition and results of operations. In addition to disputes relating to the validity or alleged infringement of other parties' rights, we may become involved in disputes relating to our assertion of our own intellectual property rights. Whether we are defending the assertion of intellectual property rights against us or asserting our intellectual property rights against others, intellectual property litigation can be complex, costly, protracted, and highly disruptive to business operations by diverting the attention and energies of management and key technical personnel. Plaintiffs in intellectual property cases often seek injunctive relief, and the measures of damages in intellectual property litigation are complex and often subjective or uncertain. Thus, any adverse determinations in this type of litigation could subject us to significant liabilities and costs. During the course of these lawsuits there may be public announcements of the results of hearings, motions, and other interim proceedings or developments in the litigation. If securities analysts or investors perceive these results to be negative, it could harm the market price of our stock. 
+The inability to protect intellectual property could harm our reputation, and our competitive position may be materially damaged. 
+Our intellectual property is valuable and provides us with certain competitive advantages. Copyrights, patents, trade secrets and contracts are used to protect these proprietary rights. Despite these precautions, it may be possible for third parties to copy aspects of our products or, without authorization, to obtain and use information which we regard as trade secrets. 
+Infringement on the proprietary rights of others could put us at a competitive disadvantage, and any related litigation could be time consuming and costly. 
+Third parties may claim that we violated their intellectual property rights. To the extent of a violation of a third party’s patent or other intellectual property right, we may be prevented from operating our business as planned and may be required to pay damages, to obtain a license, if available, or to use a non-infringing method, if possible, to accomplish our objectives. Any of these claims, with or without merit, could result in costly litigation and divert the attention of key personnel. If such claims are successful, they could result in costly judgments or settlements. 
+We compete in highly competitive markets, which are likely to become more competitive. Competitors may be able to respond more quickly to new or emerging technology and changes in customer requirements. 
+We face significant competition in developing and selling our printers, transaction supplies and services. Principal competitors have substantial marketing, financial, development and personnel resources. To remain competitive, we believe we must continue to provide: 
+· 
+Technologically advanced printers that satisfy the user demands, 
+· 
+Superior customer service, 
+· 
+High levels of quality and reliability, and 
+· 
+Dependable and efficient distribution networks. 
+We cannot ensure we will be able to compete successfully against current or future competitors. Increased competition in printers or supplies may result in price reductions, lower gross profit margins and loss of market share, and could require increased spending on research and development, sales and marketing and customer support. Some competitors may make strategic acquisitions or establish cooperative relationships with suppliers or companies that produce complementary products. Any of these factors could reduce our earnings. 
+We have outsourced a large portion of the assembly of our printers to a contract manufacturer and will be dependent on them for the manufacturing of such printers. A failure by this contract manufacturer, or any disruption in such manufacturing, may adversely affect our business results. 
+In an effort to achieve additional cost savings and operation benefits, we have continued to outsource the manufacturing and assembly of our printers to a contract manufacturer in China. 
+However, to the extent we rely on a third party service provider for manufacturing services, we may incur increased business continuity risks. We will no longer be able to exercise control over the assembly of certain of our printers or any related operations or processes, including the internal controls associated with operations and processes conducted and the quality of our products assembled by the contract manufacturer. If we are unable to effectively develop and implement our outsourcing strategy, we may not realize cost structure efficiencies and our operating and financial results could be materially adversely affected. 
+In addition, if the contract manufacturer experiences business difficulties or fails to meet our manufacturing needs, then we may be unable to meet production requirements, may lose revenue and may not be able to maintain relationships with our customers. Without the contract 
+7 
+Table of Contents 
+manufacturer continuing to manufacture our products and the continuing operation of the contract manufacturer’s facility, we will have limited means for the final assembly of a majority of our printers until we are able to secure the manufacturing capability at another facility or develop an alternative manufacturing facility, which could be costly and time consuming and have a material adverse effect on our operating and financial results. 
+The increased elements of risk that arise from conducting certain operating processes in foreign jurisdictions may lead to an increase in reputational risk. 
+Although we carry business interruption insurance to cover lost revenue and profits in an amount we consider adequate, this insurance does not cover all possible situations. In addition, the business interruption insurance would not compensate us for the loss of opportunity and potential adverse impact, both short-term and long-term, on relations with our existing customers resulting from our inability to produce products for them. 
+The contract manufacturer has access to our intellectual property, which increases the risk of infringement or misappropriation of this intellectual property. 
+We source some of our component parts and consumable products from sole source suppliers; any disruptions may impact our ability to manufacture and sell our products. 
+A disruption in the supply of such component parts and consumable products could have a material adverse effect on our operations and financial results. 
+We sell a significant portion of our products internationally and purchase important components from foreign suppliers. These circumstances create a number of risks. 
+We sell a significant amount of our products to customers outside the United States. Shipments to international customers are expected to continue to account for a material portion of net sales. Risks associated with sales and purchases outside the United States include: 
+· 
+Fluctuating foreign currency rates could restrict sales, or increase costs of purchasing, in foreign countries. 
+· 
+Foreign governments may impose burdensome tariffs, quotas, taxes, trade barriers or capital flow restrictions. 
+· 
+Political and economic instability may reduce demand for our products or put our foreign assets at risk. 
+· 
+Restrictions on the export or import of technology may reduce or eliminate the ability to sell in or purchase from certain markets. 
+· 
+Potentially limited intellectual property protection in certain countries, such as China, may limit recourse against infringing products or cause us to refrain from selling in certain geographic territories. 
+If market conditions deteriorate or future results of operations are less than expected, a valuation allowance may be required for all or a portion of our deferred tax assets. 
+We currently have significant deferred tax assets, which may be used to reduce taxable income in the future. We assess the realization of these deferred tax assets on a quarterly basis, and if we determine that it is more likely than not that some portion of these assets will not be realized, an income tax valuation allowance is recorded. If market conditions deteriorate or future results of operations are less than expected, or there is a change to applicable tax rules, future assessments may result in a determination that it is more likely than not that some or all of our net deferred tax assets are not realizable. As a result, we may need to establish a valuation allowance for all or a portion of our net deferred tax assets, which may have a material adverse effect on our business, results of operations and financial condition. 
+We cannot provide any assurance that current laws, or any laws enacted in the future, will not have a material adverse effect on our business. 
+Our operations are subject to laws, rules, regulations, including environmental regulations, government policies and other requirements in each of the jurisdictions in which we conduct business. Changes in laws, rules, regulations, policies or requirements could result in the need to modify our products and could affect the demand for our products, which may have an adverse impact on our future operating results. If we do not comply with applicable laws, rules and regulations we could be subject to costs and liabilities and our business may be adversely impacted. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. It is possible that terrorist attacks could be directed at important locations for the gaming industry. Heightened security measures and other efforts to combat terrorism may also have an adverse effect on the gaming industry by reducing tourism. Any of these developments could also negatively affect the general economy and consumer confidence. Any downturn in the economy or in the gaming industry in particular could reduce demand for our products and adversely affect our business and results of operations. In addition, heightened security measures may cause certain governments to restrict the import/export of goods, which may have an adverse effect on our ability to buy/sell goods. 
+8 
+Table of Contents 
+Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial also may adversely impact our business. Should any risks or uncertainties develop into actual events, these developments could have material adverse effects on our business, financial condition, and results of operations. 
+Item 1B. Unresolved Staff Comments. 
+Not applicable. 
+Item 2. Properties. 
+Our corporate headquarters is currently located in Hamden, CT. Our global engineering, assembly and eastern region service facility is located in Ithaca, NY. We also maintain a facility in Las Vegas, NV that serves as our global printer sales headquarters and western region service center. Our eastern region service center is currently located in New Britain, CT. We believe that our facilities generally are in good condition, adequately maintained and suitable for their present and currently contemplated uses. 
+Our principal facilities as of December 31, 2009 are listed below: 
+Location 
+Operations Conducted 
+Size 
+(Approx. Sq. Ft.) 
+Owned or 
+Leased 
+Lease Expiration 
+Date 
+Hamden, Connecticut 
+Executive offices and TSG sales office 
+11,100 
+Leased 
+April 23, 2017 
+Ithaca, New York 
+Research, design, assembly and service facility 
+73,900 
+Leased 
+June 30, 2012 
+Las Vegas, Nevada 
+Service center and printer sales headquarters 
+13,700 
+Leased 
+December 31, 2016 
+New Britain, Connecticut 
+Printhead manufacturing and repair facility 
+11,500 
+Leased 
+April 1, 2012 
+Doncaster, United Kingdom 
+Sales office and service center 
+2,800 
+Leased 
+August 1, 2016 
+Georgia and New York 
+Two regional sales offices 
+300 
+Leased 
+Various 
+113,300 
+Item 3. Legal Proceedings. 
+None. 
+Item 4. Submission of Matters to a Vote of Security Holders. 
+No matters were submitted to a vote of security holders during the last quarter of the year covered by this report. 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+Our common stock is traded on the NASDAQ Global Market under the symbol TACT. As of February 26, 2010, there were 553 holders of record of the common stock. The high and low sales prices of the common stock reported during each quarter of the years ended December 31, 2009 and 2008 were as follows: 
+Year Ended 
+Year Ended 
+December 31, 2009 
+December 31, 2008 
+High 
+Low 
+High 
+Low 
+First Quarter 
+$ 
+4.74 
+$ 
+1.60 
+$ 
+5.67 
+$ 
+3.58 
+Second Quarter 
+5.96 
+2.35 
+9.50 
+4.80 
+Third Quarter 
+5.96 
+3.80 
+13.75 
+6.84 
+Fourth Quarter 
+6.94 
+4.75 
+8.98 
+3.25 
+No dividends on common stock have been declared and we do not anticipate declaring dividends in the foreseeable future. Our credit agreement with TD Bank prohibits the payment of cash dividends on our common stock for the term of the agreement. 
+Issuer Purchases of Equity Securities 
+On March 25, 2005, the Board of Directors approved a stock repurchase program (“the Stock Repurchase Program”). Under the Stock Repurchase Program, we were authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending on March 25, 2008, depending on market conditions, share price and other factors. 
+On November 1, 2007, our Board of Directors approved an increase in our stock repurchase authorization under the Stock Repurchase Program to $15,000,000 from $10,000,000. In addition, the Board approved a two-year extension of the Stock Repurchase Program to March 31, 2010. 
+9 
+Table of Contents 
+During 2009, we made no repurchases of common stock. As of December 31, 2009, we have repurchased a total of 1,164,100 shares of common stock for approximately $8,538,000, at an average price of $7.33 per share, since the inception of the Stock Repurchase Program. 
+CORPORATE PERFORMANCE GRAPH 
+The following graph compares the cumulative total return on the Company’s Common Stock from December 31, 2004 through December 31, 2009, with the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index. The graph assumes that $100 was invested on December 31, 2004 in each of the Company’s common stock, the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index, and that all dividends were reinvested. 
+COMPARISON OF CUMULATIVE TOTAL RETURN AMONG 
+TRANSACT TECHNOLOGIES INCORPORATED COMMON STOCK, 
+THE CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.), 
+AND THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX 
+12/31/04 
+12/31/05 
+12/31/06 
+12/31/07 
+12/31/08 
+12/31/09 
+TransAct Technologies Incorporated Common Stock 
+$ 
+100.00 
+$ 
+36.99 
+$ 
+38.86 
+$ 
+22.43 
+$ 
+21.49 
+$ 
+32.49 
+CRSP Total Return Index for the Nasdaq Stock Market (U.S.) 
+$ 
+100.00 
+$ 
+102.13 
+$ 
+112.19 
+$ 
+121.68 
+$ 
+58.64 
+$ 
+84.28 
+Nasdaq Computer Manufacturer Stocks Index 
+$ 
+100.00 
+$ 
+102.31 
+$ 
+104.49 
+$ 
+152.86 
+$ 
+64.21 
+$ 
+141.03 
+10 
+Table of Contents 
+Item 6. Selected Financial Data (in thousands, except per share amounts) 
+The following is summarized from our audited financial statements of the past five years: 
+Year Ended December 31, 
+2009 
+2008 
+2007 
+2006 
+2005 
+Consolidated Statement of Operations Data: 
+Net sales 
+$ 
+58,346 
+$ 
+62,207 
+$ 
+48,766 
+$ 
+64,328 
+$ 
+51,091 
+Gross profit 
+18,829 
+20,950 
+15,996 
+22,365 
+15,590 
+Operating expenses 
+15,533 
+19,089 
+19,751 
+16,277 
+15,366 
+Operating income (loss) 
+3,296 
+1,861 
+(3,755 
+) 
+6,088 
+224 
+Net income (loss) 
+2,140 
+1,444 
+(2,274 
+) 
+3,916 
+377 
+Net income (loss) per share: 
+Basic 
+0.23 
+0.16 
+(0.24 
+) 
+0.41 
+0.04 
+Diluted 
+0.23 
+0.15 
+(0.24 
+) 
+0.40 
+0.04 
+December 31, 
+2009 
+2008 
+2007 
+2006 
+2005 
+Balance Sheet Data: 
+Total assets 
+$ 
+34,899 
+$ 
+32,234 
+$ 
+30,414 
+$ 
+33,706 
+$ 
+29,332 
+Working capital 
+20,474 
+15,051 
+11,338 
+16,643 
+15,375 
+Shareholders’ equity 
+26,354 
+23,282 
+21,608 
+24,290 
+21,257 
+Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 
+This discussion should be read in conjunction with the Consolidated Financial Statements and notes thereto. 
+Forward Looking Statements 
+Certain statements included in this report, including without limitation statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, which are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements generally can be identified by the use of forward-looking terminology, such as “may”, “will”, “expect”, “intend”, ”estimate”, “anticipate”, “believe”, “project” or “continue” or the negative thereof or other similar words. All forward-looking statements involve risks and uncertainties, including, but not limited to those listed in Item 1A of this Annual Report. Actual results may differ materially from those discussed in, or implied by, the forward-looking statements. The forward-looking statements speak only as of the date of this report and we assume no duty to update them. 
+Overview 
+2009 was a year of solid performance for TransAct, especially given the unprecedented worldwide economic recession we faced throughout the year. Our focus on market diversity along with prudent cost reduction initiatives led us to achieve positive financial results during one of most difficult economic times ever. We shipped over 160,000 printers during 2009 and our financial results included improved operating margin, net income and earnings per share as compared to 2008. We also generated solid positive cash flow during 2009, as we increased our cash balance from $2,000,000 at the end of 2008 to over $10,000,000 at the end of 2009. 
+We continue to focus on sales growth in our core markets (banking and POS, casino and gaming, lottery, and in our TSG) to drive increased profitability. During 2009, our total net sales decreased 6% to approximately $58,346,000. See the table below for a breakdown of our sales by market. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Banking and POS 
+$ 
+16,695 
+28.6 
+% 
+$ 
+11,866 
+19.1 
+% 
+$ 
+4,829 
+40.7 
+% 
+Casino and gaming 
+17,526 
+30.0 
+% 
+22,299 
+35.8 
+% 
+(4,773 
+) 
+(21.4 
+%) 
+Lottery 
+9,551 
+16.4 
+% 
+15,731 
+25.3 
+% 
+(6,180 
+) 
+(39.3 
+%) 
+TSG 
+14,574 
+25.0 
+% 
+12,311 
+19.8 
+% 
+2,263 
+18.4 
+% 
+Total net sales 
+$ 
+58,346 
+100.0 
+% 
+$ 
+62,207 
+100.0 
+% 
+$ 
+(3,861 
+) 
+(6.2 
+%) 
+Sales of our Banking and POS printers increased 41% in 2009 compared to 2008. In the banking market we focus mainly on supplying printers for use in bank teller stations at banks and financial institutions primarily in the U.S. In the banking market, opportunities are project oriented and as a result, our banking printer sales can fluctuate significantly year-to-year. During 2009, we won a significant follow-on order from our largest banking customer. As a result of this order, our banking printer sales increased more than fivefold (443%) from 2008 and we completed shipments for this customer’s project during 2009. In the POS market, we focus primarily on supplying printers that print receipts or linerless 
+11 
+Table of Contents 
+labels for customers in the restaurant, hospitality and specialty retail markets. Sales of our POS printers declined 14% in 2009 largely due to a 34% decline in sales of our legacy line of POS impact printers as these printers continue to be replaced by our newer thermal and inkjet printers. Despite the decrease in sales from legacy POS printers, we experienced a 48% increase in sales of our two new printer products for McDonalds – (1) the Ithaca® 8000 thermal receipt/label printer which is used at the POS terminal to print either a receipt at the front counter or a label at the grill station and (2) the Ithaca® 8040 label printer which is used to print labels for McDonalds new combined beverage initiative. During 2009, we benefited from increasing sales of printers for both of these McDonald’s initiatives, with the majority related to the rollout of printers for the combined beverage initiative that is currently nearing completion. Looking ahead, we expect to continue to benefit from our relationship with McDonalds as McDonalds increases the pace of its rollout of a new POS system in all 32,000 of its stores which we expect to result in increasing sales of our Ithaca® 8000 printer throughout 2010. 
+In our casino and gaming market, our focus lies primarily in supplying printers for use in slot machines at casinos and racetracks, as well as in other gaming devices that print tickets or receipts, worldwide. During 2009, worldwide casino and gaming printer sales decreased 21% compared to 2008. On the positive side, our early attention to the international casino and gaming market is paying off, as these sales grew for the second consecutive year in 2009. In fact, our international sales increased 26% from 2008, representing more than half – or 57% - of our total worldwide casino and gaming sales for the first time during 2009. This increase was led by a 66% increase in our line of off-premise gaming printers used primarily in Europe in various gaming machines that print receipts instead of tickets. However, even with the increase in our international sales, we could not overcome continued weakness in the domestic casino market, where we experienced a 48% decline in sales as the replacement rate of slot machines in North American casinos plummeted to a historically low level in 2009. 
+In the lottery market, we continue to hold a leading position based on our long-term purchase agreement with GTECH, our largest customer and the world’s largest provider of lottery terminals, with approximately a 70% market share. GTECH has been our customer since 1995, and we continue to maintain a good relationship with them. In fact, during 2009 we expanded our long-standing relationship with GTECH by executing a new exclusive purchase agreement to develop and supply them with their next generation online thermal lottery printer. Pursuant to the new agreement, GTECH will exclusively purchase all of its requirements for thermal on-line lottery printers from us and we will exclusively sell such printers to GTECH for four years from the start of production of the new printer, which is expected to commence in the fall of 2010. This new agreement will now extend our relationship with GTECH through at least 2014. Currently, we fulfill substantially all of GTECH’s printer requirements for lottery terminal installations and upgrades worldwide. During 2009, total printer sales to GTECH decreased approximately 39%, compared to 2008, a year of record level sales compared to historical levels from GTECH. Our sales to GTECH each year are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. 
+Our TransAct Services Group, which sells service, replacement parts and consumable products, including receipt paper, ribbons and inkjet cartridges, continues to offer a substantial growth opportunity and recurring revenue stream for TransAct. TSG revenue continued to increase in 2009, rising 18% from 2008. During 2009, our sales benefited from significantly higher inkjet cartridge sales to a large banking customer. During 2009, this large customer purchased approximately two years worth of inkjet cartridges based on their annual average consumption rate. As a result, we expect sales of inkjet cartridges to this customer to be significantly lower in 2010 compared to 2009. We also expect this customer to resume purchases of inkjet cartridges at their annual average consumption rate beginning in 2011. In addition, during 2009 we experienced expanding sales of paper and other consumable products through our e-commerce website, www.transactsupplies.com . We plan to continue to focus on enhancing our e-commerce efforts throughout 2010. 
+Operationally, we made a substantial change to our printer production operations during 2009, as we transitioned from assembling printers domestically in our Ithaca, NY facility to sourcing fully-built printers from our contract manufacturer in China. We completed this transition during the fourth quarter of 2009 and we now will source more than 70% of our printer production to China. This transition did impact our gross margin for 2009, which decreased to 32.3% from 33.7% in 2008, as we incurred higher material and labor costs by depleting a substantial portion of our higher cost domestic inventory in the second half of 2009 as we completed the transition to China. Although our gross margin declined in 2009, our operating margin showed marked improvement from 2008. Our operating margin increased to 5.6% in 2009 compared to 3.0% in 2008, as our operating expenses decreased 19% due largely to legal fees incurred in 2008 related to our settled lawsuit with FutureLogic, Inc. that did not recur in 2009. However, excluding these legal fees during 2008, operating expenses still declined 3% from 2008 to 2009, as a result of cost reduction programs implemented during 2009. 
+We reported net income of $2,140,000 and net income per share (diluted) of $0.23 for 2009, compared to net income of $1,444,000 and net income per share of $0.15 in 2008. In terms of cash flow for 2009, we generated $8,373,000 of cash from operations, utilized $643,000 of cash for capital expenditures and we finished the year with $10,017,000 of cash and no debt on our balance sheet as of December 31, 2009. Overall, we exited 2009 financially stronger than we entered it, with $10,000,000 of cash, no debt outstanding and over $20,000,000 of working capital which should position us well to begin 2010. 
+12 
+Table of Contents 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect both balance sheet items and income statement categories. Such estimates and judgments are based upon historical experience and certain assumptions that are believed to be reasonable in the particular circumstances. We evaluate our assumptions on an ongoing basis by comparing actual results with our estimates. Actual results may differ from the original estimates. 
+The following accounting policies are those that we believe to be most critical in the preparation of our financial statements. These items utilize assumptions and estimates about the effect of future events that are inherently uncertain and are therefore based on our judgment. Please refer 
+to Note 2 – “Summary of significant accounting policies” in the accompanying Consolidated Financial Statements for a complete listing of our accounting policies. 
+Revenue Recognition – Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within ASC 605, “Revenue Recognition.” Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We account for all revenue arrangements involving multiple deliverables in accordance with ASC 605, Revenue Recognition (ASC 605), 605-25, Multiple-Element Arrangements . For these arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established, but we cannot guarantee that we will continue to experience return rates consistent with historical patterns. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. However, we cannot guarantee that this minimal level will continue. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Accounts Receivable – We have standardized credit granting and review policies and procedures for all customer accounts, including: credit reviews of all new customer accounts; ongoing credit evaluations of current customers; credit limits and payment terms based on available credit information; and adjustments to credit limits based upon payment history and the customer’s current creditworthiness. We also provide an estimate of doubtful accounts based on historical experience and specific customer collection issues. Our allowance for doubtful accounts as of December 31, 2009 was $57,000, or less than 1.0% of outstanding accounts receivable, which we feel is appropriate considering the overall quality of our accounts receivable. While credit losses have historically been within expectations and the reserves established, we cannot guarantee that our credit loss experience will continue to be consistent with historical experience. 
+13 
+Table of Contents 
+Inventory – Our inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Assumptions are reviewed at least quarterly and adjustments are made, as necessary, to reflect changing market conditions. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. Should circumstances change and we determine that additional inventory is subject to obsolescence, additional write-downs of inventory could result in a charge to income. 
+Goodwill – We test the impairment of goodwill each year or more frequently if events or changes in circumstances indicate that the carrying value may not be recoverable. We completed our last assessment as of December 31, 2009. Factors considered that may trigger an impairment review are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Goodwill amounted to $1,469,000 at December 31, 2009 and we have determined that no goodwill impairment has occurred. 
+Income Taxes – In preparing our consolidated financial statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. This involves estimating the actual current tax exposure together with assessing temporary differences between the tax basis of certain assets and liabilities and their reported amounts in the financial statements, as well as net operating losses, tax credits and other carryforwards. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheets. We then assess the likelihood that the deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. 
+Significant judgment is required in determining the provision for income taxes and, in particular, any valuation allowance or tax reserves with respect to our deferred tax assets and uncertain tax positions. On a quarterly basis, we evaluate the recoverability of our deferred tax assets based upon historical results and forecasted taxable income over future years, and match this forecast against the basis differences, deductions available in future years and the limitations allowed for net operating loss and tax credit carryforwards to ensure that there is adequate support for the realization of the deferred tax assets. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance or tax reserve, in the event we were to determine that we would not be able to realize all or part of our deferred tax assets in the future, an adjustment to the valuation allowance or tax reserves would be charged as a reduction to income in the period such determination was made. Likewise, should we determine that we would be able to realize future deferred tax assets in excess of its net recorded amount, an adjustment to the valuation allowance or tax reserves would increase net income in the period such determination was made. 
+We account for income taxes in accordance with ASC 740, “Income Taxes.” Among other things this provision prescribes a minimum recognition threshold that an income tax position must meet before it is recorded in the reporting entity’s financial statements. It also requires that the effects of such income tax positions be recognized only if, as of the balance sheet reporting date, it is “more likely than not” (i.e., more than a 50% likelihood) that the income tax position will be sustained based solely on its technical merits. When making this assessment, management must assume that the responsible taxing authority will examine the income tax position and have full knowledge of all relevant facts and other pertinent information. The accounting guidance also clarifies the method of accruing for interest and penalties when there is a difference between the amount claimed, or expected to be claimed, on a company’s income tax returns and the benefits recognized in the financial statements. 
+Warranty – We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. If actual future product repair rates or the actual costs of material and labor differ from the estimates, adjustments to the accrued warranty liability and related warranty expense would be made. 
+Contingencies – We record an estimated liability related to contingencies based on our estimates of the probable outcomes pursuant to ASC 450 “Contingencies.” On a quarterly basis, we assess the potential liability related to pending litigation, audits and other contingencies and confirm or revise estimates and reserves as appropriate. If the actual liabilities are settled in an amount greater than those recorded on the balance sheet, a charge to income would be recorded. 
+Share-Based Compensation – We calculate share-based compensation expense in accordance with ASC 718 “Compensation – Stock Compensation” using the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions for this valuation method include the expected term of an option grant, stock price volatility, risk-free interest rate, dividend yield, and forfeiture rate. The determination of these assumptions is based on past history and future expectations, and is subject to a high level of judgment. To the extent any of the assumptions were to change from year to year, the fair value of new option grants may vary significantly. 
+14 
+Table of Contents 
+Results of Operations: Year ended December 31, 2009 compared to year ended December 31, 2008 
+Net Sales. Net sales, which include printer sales and sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2009 and 2008 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Banking and POS 
+$ 
+16,695 
+28.6 
+% 
+$ 
+11,866 
+19.1 
+% 
+$ 
+4,829 
+40.7 
+% 
+Casino and gaming 
+17,526 
+30.0 
+% 
+22,299 
+35.8 
+% 
+(4,773 
+) 
+(21.4 
+)% 
+Lottery 
+9,551 
+16.4 
+% 
+15,731 
+25.3 
+% 
+(6,180 
+) 
+(39.3 
+)% 
+TSG 
+14,574 
+25.0 
+% 
+12,311 
+19.8 
+% 
+2,263 
+18.4 
+% 
+$ 
+58,346 
+100.0 
+% 
+$ 
+62,207 
+100.0 
+% 
+$ 
+(3,861 
+) 
+(6.2 
+)% 
+International* 
+$ 
+12,456 
+21.3 
+% 
+$ 
+10,126 
+16.3 
+% 
+$ 
+2,330 
+23.0 
+% 
+* 
+International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+Net sales for 2009 decreased $3,861,000, or 6%, from 2008 due to sales decreases in two out of four of our markets: casino and gaming (a decrease of approximately $4,773,000, or 21%) and lottery (a decrease of approximately $6,180,000 or 39%). Sales from banking and POS increased approximately $4,829,000 or 41% and sales from our TSG increased approximately $2,263,000, or 18%. Printer sales volume decreased 17% while the average selling price of our printers increased by approximately 6% (due primarily to an increase in sales of banking printers with higher average selling prices) from 2008 to 2009. Overall, international sales increased $2,330,000, or 23%, driven by higher sales to the gaming portion of the casino and gaming market. 
+Banking and POS : Revenue from the banking and POS market includes sales of printers used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. Revenue from this market also includes sales of inkjet, thermal and impact printers used primarily by retailers in restaurant (including fine dining, casual dining and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. Sales of our banking and POS printers worldwide increased approximately $4,829,000, or 41%, from 2008. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+15,480 
+92.7 
+% 
+$ 
+10,664 
+89.9 
+% 
+$ 
+4,816 
+45.2 
+% 
+International 
+1,215 
+7.3 
+% 
+1,202 
+10.1 
+% 
+13 
+1.1 
+% 
+$ 
+16,695 
+100.0 
+% 
+$ 
+11,866 
+100.0 
+% 
+$ 
+4,829 
+40.7 
+% 
+Domestic banking and POS printer revenue increased to $15,480,000, representing a $4,816,000, or 45%, increase from 2008 primarily driven by higher sales of our banking printers. Sales of our banking printers increased 443% in 2009 compared to 2008 as we finished shipping against the $4,900,000 order we received from a large banking customer in February 2009 as well as additional orders from this same customer. Sales of our POS printers declined approximately 15% largely due to the general economic slowdown that we believe is currently impacting, and will continue to adversely impact, the capital spending of a number of our retail and hospitality customers during 2010. Contributing to the decline in sales of our POS printers, sales of our legacy line of POS impact printers decreased approximately 39%. We expect sales of our legacy impact printers for 2010 to continue to be lower than those reported for the 2009 period, as these printers continue to be replaced by our newer thermal and inkjet printers. Despite these declines, sales of our two new printer products for McDonalds, the Ithaca 8000 ® (for McDonald’s new POS system upgrade including the grill initiative) and Ithaca® 8040 (for McDonald’s combined beverage initiative), increased approximately 48% during 2009 compared to 2008. During 2009, we benefited from increasing sales of printers for both of these McDonald’s initiatives, with the majority related to the rollout of printers for the combined beverage initiative that is currently nearing completion. Looking ahead, we expect to continue to benefit from our relationship with McDonalds as McDonalds increases the pace of its rollout of a new POS system in all 32,000 of its stores which we expect to result in increasing sales of our Ithaca ® 8000 printer throughout 2010. 
+International banking and POS printer shipments for 2009 were consistent with 2008, increasing $13,000, or 1%, to $1,215,000. 
+Casino and gaming : Revenue from the casino and gaming market includes sales of printers used in slot machines, video lottery terminals (“VLTs”), and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos and racetracks (“racinos”) and other gaming venues worldwide. Revenue from this market also includes sales of printers used in the international 
+15 
+Table of Contents 
+off-premise gaming market in gaming machines at non-casino gaming establishments such as Amusement with Prizes (“AWP”), Skills with Prizes (“SWP”), and Fixed Odds Betting Terminals (“FOBT”). Sales of our casino and gaming printers decreased $4,773,000, or 21%, from 2008, due primarily to decreased sales of our thermal casino and gaming printers domestically offset by increased sales of our thermal gaming printers internationally. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+7,497 
+42.8 
+% 
+$ 
+14,355 
+64.4 
+% 
+$ 
+(6,858 
+) 
+(47.8 
+)% 
+International 
+10,029 
+57.2 
+% 
+7,944 
+35.6 
+% 
+2,085 
+26.2 
+% 
+$ 
+17,526 
+100.0 
+% 
+$ 
+22,299 
+100.0 
+% 
+$ 
+(4,773 
+) 
+(21.4 
+)% 
+Domestic sales of our casino and gaming printers decreased $6,858,000, or 48%, due largely to a decrease in sales of our thermal casino printers, and to a lesser extent sales of our gaming printers, both of which were impacted by the downturn in the domestic casino and gaming market. Although, we anticipate some improvement in the domestic slot machine replacement cycle in 2010 compared to 2009, we believe the current uncertain economic environment could continue to negatively impact the casino industry’s level of capital expenditures in 2010. In light of these negative market conditions, our future sales to the domestic casino and gaming market could be unpredictable and adversely affected. 
+International casino and gaming printer sales increased $2,085,000, or 26%, to $10,029,000 in 2009. International gaming printer sales increased 89%, led largely by continued growing sales of our line of off-premise gaming printers in both Europe and Australia. International casino printer sales for 2009 increased 3% due primarily to an 83% increase in sales to our Australian distributer that was largely offset by a 39% decline in sales to our European distributor. Based on our current backlog of orders and forecasts of order flow provided by some of our customers, we expect our international casino and gaming sales to continue to increase in 2010 as compared to 2009. 
+Lottery: Revenue from the lottery market includes sales of lottery printers to GTECH for various lottery applications. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+9,117 
+95.5 
+% 
+$ 
+15,283 
+97.2 
+% 
+$ 
+(6,166 
+) 
+(40.3 
+)% 
+International 
+434 
+4.5 
+% 
+448 
+2.8 
+% 
+(14 
+) 
+(3.1 
+)% 
+$ 
+9,551 
+100.0 
+% 
+$ 
+15,731 
+100.0 
+% 
+$ 
+(6,180 
+) 
+(39.3 
+)% 
+Domestic and international lottery printer sales to GTECH, which include thermal on-line and other lottery printers, decreased approximately $6,180,000, or 39%, in 2009 compared to 2008, with domestic sales decreasing approximately $6,166,000 and international sales decreasing approximately $14,000. Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. We expect total sales to GTECH for 2010 to be lower than those reported during 2009. 
+TSG : Revenue from TSG includes sales of consumable products (inkjet cartridges, ribbons, receipt paper and other printing supplies), replacement parts, maintenance and repair services, refurbished printers, and shipping and handling charges. Sales from TSG increased approximately $2,263,000, or 18% from 2008. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+13,796 
+94.7 
+% 
+$ 
+11,779 
+95.7 
+% 
+$ 
+2,017 
+17.1 
+% 
+International 
+778 
+5.3 
+% 
+532 
+4.3 
+% 
+246 
+46.2 
+% 
+$ 
+14,574 
+100.0 
+% 
+$ 
+12,311 
+100.0 
+% 
+$ 
+2,263 
+18.4 
+% 
+Domestic revenue from TSG increased approximately $2,017,000, or 17%, largely due to an increase of approximately 33% in sales of consumable products from 2008, mostly due to significantly higher inkjet cartridge sales to a large banking customer. During 2009, this large customer purchased approximately two years worth of inkjet cartridges based on their annual average consumption rate. As a result, we expect sales of inkjet cartridges to this customer to be significantly lower in 2010 compared to 2009. We also expect this customer to resume purchases of inkjet cartridges at their annual average consumption rate beginning in 2011. 
+Internationally, TSG revenue increased $246,000, or 46%, to $778,000, due primarily to a 51% increase in sales of replacement parts and accessories and a 47% increase in maintenance and repair services revenue largely due to new service contracts won during 2009. 
+16 
+Table of Contents 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+18,829 
+$ 
+20,950 
+(10.1 
+)% 
+32.3 
+% 
+33.7 
+% 
+Gross profit is measured as revenue less cost of goods sold. Cost of goods sold includes primarily the cost of all raw materials and component parts, direct labor and the associated manufacturing overhead expenses, and the cost of finished products purchased directly from our contract manufacturer. Gross profit decreased $2,121,000, or 10%, to $18,829,000 from $20,950,000, and gross margin declined from 33.7% to 32.3% due primarily to (1) a 6% decrease in sales in 2009 compared to 2008, (2) a less favorable sales mix resulting from higher sales of banking printers and certain consumable products at lower gross margins than our overall gross margin and (3) higher material and labor cost as we depleted a substantial portion of our higher cost domestic inventory in the second half of 2009 as we completed the transition of full production of 70% of our printers to a contract manufacturer in China. These decreases were partially offset by (1) approximately $247,000 of lower product warranty expense from improved repair history and a 17% decline in printer shipments in 2009 compared to 2008 and (2) approximately $387,000 of lower manufacturing expenses due to the transition of more of our production to China. We expect our gross margin to improve in 2010 compared to 2009 as we have substantially depleted our higher cost domestic inventories and we realize the full benefit from our lower cost finished products sourced from China. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+2,788 
+$ 
+2,942 
+(5.2 
+)% 
+4.8 
+% 
+4.7 
+% 
+Engineering, design and product development expenses primarily include salary and payroll related expenses for our engineering staff, depreciation and design expenses (including prototype printer expenses, outside design and testing services, and supplies). Such expenses decreased $154,000, or 5%, to $2,788,000. Approximately $60,000 of the decrease was due to lower outside testing and pre-production prototype expenses related to new product development and approximately $97,000 of the decrease was due to lower employee compensation related expenses, including lower incentive compensation. 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+5,821 
+$ 
+6,078 
+(4.2 
+)% 
+10.0 
+% 
+9.8 
+% 
+Selling and marketing expenses primarily include salaries and payroll related expenses for our sales and marketing staff, sales commissions, travel expenses, expenses associated with the lease of sales offices, advertising, trade show expenses, e-commerce and other promotional marketing expenses. Selling and marketing expenses for 2009 decreased $257,000, or 4%, due primarily to approximately $104,000 of lower sales commissions resulting from a 6% decrease in sales, approximately $33,000 of lower travel related expenses, approximately $151,000 in reduced promotional marketing expenses, and a reduction of approximately $54,000 in consulting and professional fees due to the cost control initiatives that were put in place for 2009. These decreases were partially offset by an increase of approximately $67,000 in employee compensation related expenses as we replaced several existing sales employees with higher level sales employees at higher compensation levels during 2009 to upgrade certain key sales positions. 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+6,924 
+$ 
+7,040 
+(1.6 
+)% 
+11.9 
+% 
+11.3 
+% 
+General and administrative expenses primarily include salaries and payroll related expenses for our executive, accounting, human resource, business development and information technology staff, expenses for our corporate headquarters, professional and legal expenses, telecommunication expenses, and other expenses related to being a publicly-traded company. General and administrative expenses decreased 
+17 
+Table of Contents 
+$116,000, or 2%, due primarily to a reduction of approximately $515,000 in employee compensation related expenses largely due to lower incentive compensation in 2009 compared to 2008. These decreases were largely offset by approximately $68,000 in increased legal expenses, increased employee compensation related expenses associated with the full year affect of the hiring of our new Vice President of Business Development in May 2008, and $67,000 in increased depreciation. In addition, general and administrative expenses for 2009 included severance charges of approximately $211,000 related to the termination of approximately 17 employees. 
+Legal fees associated with lawsuit. During 2009, we did not incur any legal fees related to the settled lawsuit with FutureLogic compared to $3,029,000 in 2008. We settled our litigation with FutureLogic in May 2008 and as a result of the settlement, we do not expect to incur any additional legal fees related to the lawsuit. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales - 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+3,296 
+$ 
+1,861 
+77.1 
+% 
+5.6 
+% 
+3.0 
+% 
+During 2009, we reported operating income of $3,296,000, or 5.6% of net sales, compared to operating income of $1,861,000, or 3.0% of net sales in 2008. The increase in our operating income and operating margin was due to lower operating expenses (including the absence of legal expense related to the FutureLogic lawsuit), partially offset by lower gross profit on a 6% decline in sales in 2009 compared to 2008. 
+Interest. We recorded net interest expense of $50,000 in 2009 compared to $11,000 in 2008. Although our cash balance increased from $2,000,000 at December 31, 2008 to $10,017,000 at December 31, 2009, and we maintained a higher average cash balance in 2009 than in 2008, we earned lower interest income in 2009 due to a lower overall rate of return on our invested cash balance due to the decreasing interest rate environment. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2009 and 2008. See “Liquidity and Capital Resources” below for more information. 
+Other Income. We recorded other expense of $33,000 in 2009 compared to other income of $368,000 in 2008. The decrease was primarily due to foreign currency transaction exchange losses recorded by our U.K. subsidiary resulting from a 10% weakening of the U.S. dollar against the British pound during 2009, as compared to a foreign currency transaction exchange gain resulting from a 28% strengthening of the U.S. dollar against the British pound in 2008. 
+Income Taxes. We recorded an income tax provision for 2009 of $1,073,000 at an effective tax rate of 33.4% compared to $774,000 at an effective tax rate of 34.9%. The effective tax rate for 2009 decreased as compared to 2008 primarily due to increased utilization of state net operating losses and certain credits. We expect our annual effective tax rate for 2010 to be approximately 34-35%. 
+Net Income . We reported net income during 2009 of $2,140,000, or $0.23 per diluted share, compared to $1,444,000, or $0.15 per diluted share, for 2008. 
+Results of Operations: Year ended December 31, 2008 compared to year ended December 31, 2007 
+Net Sales. Net sales, which include printer sales and sales of replacement parts, consumables and repair services, by market for the years ended December 31, 2008 and 2007 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2008 
+December 31, 2007 
+$ 
+% 
+Banking and POS 
+$ 
+11,866 
+19.1 
+% 
+$ 
+11,046 
+22.6 
+% 
+$ 
+820 
+7.4 
+% 
+Casino and gaming 
+22,299 
+35.8 
+% 
+19,438 
+39.9 
+% 
+2,861 
+14.7 
+% 
+Lottery 
+15,731 
+25.3 
+% 
+5,900 
+12.1 
+% 
+9,831 
+166.6 
+% 
+TSG 
+12,311 
+19.8 
+% 
+12,382 
+25.4 
+% 
+(71 
+) 
+(0.6 
+)% 
+$ 
+62,207 
+100.0 
+% 
+$ 
+48,766 
+100.0 
+% 
+$ 
+13,441 
+27.6 
+% 
+International* 
+$ 
+10,126 
+16.3 
+% 
+$ 
+10,795 
+22.1 
+% 
+$ 
+(669 
+) 
+(6.2 
+)% 
+* 
+International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+18 
+Table of Contents 
+Net sales for 2008 increased $13,441,000, or 28%, from 2007 due to sales increases in three out of four of our markets: POS (an increase of approximately $820,000, or 7%), casino and gaming (an increase of approximately $2,861,000, or 15%) and lottery (an increase of approximately $9,831,000 or 167%). Sales from our TSG decreased by approximately $71,000, or less than 1%. 
+Overall, international sales decreased by $669,000, or 6%. The decrease in international sales was due largely to the expiration in November 2007 of a service contract with a single customer in the United Kingdom. 
+Banking and POS : Sales of our banking and POS printers worldwide increased approximately $820,000, or 7%, from 2007. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2008 
+December 31, 2007 
+$ 
+% 
+Domestic 
+$ 
+10,664 
+89.9 
+% 
+$ 
+9,775 
+88.5 
+% 
+$ 
+889 
+9.1 
+% 
+International 
+1,202 
+10.1 
+% 
+1,271 
+11.5 
+% 
+(69 
+) 
+(5.4 
+)% 
+$ 
+11,866 
+100.0 
+% 
+$ 
+11,046 
+100.0 
+% 
+$ 
+820 
+7.4 
+% 
+Domestic banking and POS printer sales increased to $10,664,000, representing an $889,000, or 9%, increase from 2007. Banking printer sales increased by approximately $610,000 due largely to incremental sales of our first generation BANKjet® 1500 bank teller printer as well as new product sales of our BANKjet® 2500 bank teller printer in 2008 compared to 2007. Our increased banking printer sales were also complemented by new product sales of our new Ithaca® 8000 and Ithaca® 8040 thermal receipt/label printers for McDonalds. We also experienced 5% lower sales of our legacy impact printers, as expected, during 2008 compared to 2007, as these printers continue to be replaced by our thermal and inkjet printers. 
+International banking and POS printer shipments decreased by approximately $69,000, or 5%, to $1,202,000, due primarily to lower sales to our international POS distributors in Europe and Asia, largely offset by a 30% increase in printer sales to our international POS distributors in Latin America. 
+Casino and gaming : Sales of our casino and gaming printers increased by $2,861,000, or 15%, from 2007, due to increased sales of our thermal casino and gaming printers both domestically and internationally. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2008 
+December 31, 2007 
+$ 
+% 
+Domestic 
+$ 
+14,355 
+64.4 
+% 
+$ 
+12,798 
+65.8 
+% 
+$ 
+1,557 
+12.2 
+% 
+International 
+7,944 
+35.6 
+% 
+6,640 
+34.2 
+% 
+1,304 
+19.6 
+% 
+$ 
+22,299 
+100.0 
+% 
+$ 
+19,438 
+100.0 
+% 
+$ 
+2,861 
+14.7 
+% 
+Domestic sales of our casino and gaming printers increased by $1,557,000, or 12%, despite a weak domestic casino market, due largely to an increase in domestic sales of our thermal casino printers, including incremental sales beginning in the second quarter of 2008 resulting from our new status as default printer provider to International Game Technology (“IGT”). 
+International casino and gaming printer sales increased $1,304,000, or 20%, to $7,944,000 in 2008 compared to 2007. International sales represented 36% and 34% of total sales into our casino and gaming market during 2008 and 2007, respectively. This increase was due primarily to 15% increased sales of our casino and gaming printers in Europe, including growing sales of our new off-premise gaming printers, as well as 22% increased international casino printer sales to Australia. 
+Lottery: Sales of our lottery printers increased by $9,831,000, or 167%, from 2007. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2008 
+December 31, 2007 
+$ 
+% 
+Domestic 
+$ 
+15,283 
+97.2 
+% 
+$ 
+5,297 
+89.8 
+% 
+$ 
+9,986 
+188.5 
+% 
+International 
+448 
+2.8 
+% 
+603 
+10.2 
+% 
+(155 
+) 
+(25.7 
+)% 
+$ 
+15,731 
+100.0 
+% 
+$ 
+5,900 
+100.0 
+% 
+$ 
+9,831 
+166.6 
+% 
+Domestic and international lottery printer sales to GTECH, which include thermal on-line and other lottery printers, increased by approximately $9,831,000, or 167%, in 2008 compared to 2007, with domestic sales increasing by approximately $9,986,000 and international sales declining by approximately $155,000. Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. 
+19 
+Table of Contents 
+TSG : Sales from TSG decreased by approximately $71,000, or less than 1% from 2007. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2008 
+December 31, 2007 
+$ 
+% 
+Domestic 
+$ 
+11,779 
+95.7 
+% 
+$ 
+10,101 
+81.6 
+% 
+$ 
+1,678 
+16.6 
+% 
+International 
+532 
+4.3 
+% 
+2,281 
+18.4 
+% 
+(1,749 
+) 
+(76.7 
+)% 
+$ 
+12,311 
+100.0 
+% 
+$ 
+12,382 
+100.0 
+% 
+$ 
+(71 
+) 
+(0.6 
+)% 
+Domestic revenue from TSG increased by approximately $1,678,000, or 17%, to $11,779,000, largely due to 50% increased sales of consumable products, including higher sales of inkjet cartridges as well as growing sales of paper and other consumable products through our new e-commerce website, www.transactsupplies.com . The increase in domestic TSG revenue was also due, to a lesser extent, to higher maintenance and repair services revenue for 2008 as we renewed and expanded existing contracts for our service products including extended warranty contracts and our 24-hour guaranteed replacement product service called TransAct Xpress™. These increases were partially offset by a 19% decline in the sales of replacement parts for certain legacy printers, as the installed base of these legacy printers in the market continues to decline. 
+Internationally, TSG sales decreased by approximately $1,749,000, or 77%, to $532,000, due largely to a 97% decrease in maintenance and repair services revenue from a service contract with a single customer in the United Kingdom. The service contract, which represented a substantial portion of our U.K. subsidiary’s revenue in 2007, ended in November 2007 and was not renewed, as the customer replaced our printers with newer technology that we were unable to provide. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2008 
+2007 
+Change 
+Total Sales - 2008 
+Total Sales - 2007 
+Year ended 
+$ 
+20,950 
+$ 
+15,996 
+31.0 
+% 
+33.7 
+% 
+32.8 
+% 
+Gross profit and gross margin increased due primarily to a higher volume of sales and lower component part and labor costs resulting from our initiatives to increasingly move production of our products to Asia, somewhat offset by a less favorable sales mix due primarily to a significant increase in sales of our lottery printers, which were sold at lower gross margins than our overall gross margin. Gross profit for 2008 was also favorably impacted by approximately $195,000 of increased absorption of certain manufacturing overhead expenses due to the transition of more of our production to China compared to 2007. Gross profit for 2007 was negatively impacted by a charge approximately $528,000, or 1.1% of net sales in 2007, to write-down inventory specifically related to certain obsolete electronic components and certain discontinued printer products. 
+Engineering and Product Development. Engineering and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2008 
+2007 
+Change 
+Total Sales - 2008 
+Total Sales – 2007 
+Year ended 
+$ 
+2,942 
+$ 
+3,129 
+(6.0 
+)% 
+4.7 
+% 
+6.4 
+% 
+Engineering, design and product development expenses decreased by $187,000 or 6.0%, due to 49% lower outside design, prototype, development and professional consulting related expenses partially offset by 13% higher employee compensation related expenses. Engineering and product development expenses decreased as a percentage of net sales due primarily to higher sales volume coupled with a lower level of expenses in 2008 compared to 2007. 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2008 
+2007 
+Change 
+Total Sales - 2008 
+Total Sales - 2007 
+Year ended 
+$ 
+6,078 
+$ 
+6,708 
+(9.4 
+)% 
+9.8 
+% 
+13.8 
+% 
+Selling and marketing expenses decreased primarily due to a reduced level of sales staff related expenses of 9% resulting from the cost reduction actions we took in late 2007 as well as lower promotional marketing expenses. Selling and marketing expenses decreased as a percentage of net sales due primarily to higher sales volume coupled with a lower level of expenses in 2008 compared to 2007. 
+20 
+Table of Contents 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2008 
+2007 
+Change 
+Total Sales - 2008 
+Total Sales - 2007 
+Year ended 
+$ 
+7,040 
+$ 
+6,995 
+0.6 
+% 
+11.3 
+% 
+14.3 
+% 
+General and administrative expenses increased by $45,000, or less than 1%, due primarily to (1) 17% higher incentive compensation expenses, (2) compensation and travel expenses related to the hiring of our new Vice President of Business Development in May 2008 and (3) the full year effect of increased rent and facility-related expenses, including depreciation expense on purchases of office furniture and leasehold improvements for our new corporate headquarters in Hamden, CT that we moved into during the second quarter of 2007. These increases were partially offset by 24% lower legal expenses related to general corporate matters, 53% lower recruitment related expenses, and 20% lower professional fees. General and administrative expenses decreased as a percentage of net sales due primarily to higher sales volume in 2008 compared to 2007. 
+Legal Fees associated with lawsuit. During 2008, we incurred approximately $3,029,000 of legal fees related to the settled lawsuit with FutureLogic compared to $2,907,000 in 2007. The substantial increase was due to the settlement of our litigation with FutureLogic in May 2008. 
+Operating Income (Loss). Operating income (loss) information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2008 
+2007 
+Change 
+Total Sales - 2008 
+Total Sales - 2007 
+Year ended 
+$ 
+1,861 
+$ 
+(3,755 
+) 
+NM 
+3.0 
+% 
+(7.7 
+)% 
+During 2008, the substantial increase in our operating income and operating margin was due largely to higher sales and the resulting higher gross profit and lower operating expenses in 2008 compared to that of 2007. 
+Interest. We recorded net interest expense of $11,000 in 2008 compared to net interest income of $76,000 in 2007. The decrease in our net interest income was largely due to a lower average cash balance in 2008 as compared to 2007, coupled with a lower overall rate of return on our invested cash balance due to the decreasing interest rate environment. See “Liquidity and Capital Resources” below for more information. 
+Other Income. We recorded other income of $368,000 in 2008 compared to other income of $21,000 in 2007. The increase was due primarily to transaction exchange gains recorded by our UK subsidiary resulting from the significant strengthening of the U.S. dollar against the British pound primarily in the third and fourth quarters of 2008. 
+Income Taxes. We recorded an income tax provision of $774,000, at an effective rate of 34.9% during 2008 compared to an income tax benefit of $1,384,000, at an effective rate of 37.8% in 2007. The effective tax rate for 2008 decreased compared to 2007 due largely to a decrease in the recognition of certain deferred tax credits. 
+Net Income (Loss) . We reported net income in 2008 of $1,444,000, or $0.15 per diluted share compared to a net loss of $(2,274,000), or $(0.24) per diluted share in 2007. 
+Liquidity and Capital Resources 
+We assess our liquidity in terms of our ability to generate cash to fund our operating, investing and financing activities. Significant factors affecting the management of liquidity are cash flows from operating activities, capital expenditures, stock repurchases, access to bank lines of credit and our ability to attract long-term capital with satisfactory terms. 
+Internal cash generation together with currently available cash and investments, available borrowing facilities and an ability to access credit lines, if needed, are expected to be sufficient to fund operations, capital expenditures, and any increase in working capital that would be required to accommodate a higher level of business activity. We actively seek to expand by acquisition as well as through the growth of our current business. While a significant acquisition may require additional debt and/or equity financing, although no assurances can be given, we believe that we would be able to obtain additional financing based on our historical earnings performance. 
+The recent and unprecedented disruption in the current credit markets has had a significant adverse impact on a number of financial institutions. At this point in time, our liquidity has not been impacted by the current credit environment and we do not expect that it will be materially impacted in the near future. We will continue to closely monitor our liquidity and the credit markets. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment. 
+21 
+Table of Contents 
+During 2009, our cash flows reflected increased cash generation from improved operating results, significantly reduced inventory balances and lower capital spending. Our cash balance increased $8,017,000, or 401%, from December 31, 2008 and we ended 2009 with approximately $10,017,000 in cash and cash equivalents and no debt outstanding. 
+Operating activities : The following significant factors primarily affected our cash provided by operations of $8,373,000 in 2009 as compared to $701,000 in 2008. 
+During 2009: 
+· 
+We reported net income of $2,140,000. 
+· 
+We recorded depreciation, amortization and non-cash compensation expense of $2,397,000. 
+· 
+We recorded a non-cash foreign currency transaction exchange transaction loss of $33,000 from our UK subsidiary due to the weakening of the U.S. dollar against the British pound. 
+· 
+We recorded non-cash deferred income tax expense of $1,002,000. 
+· 
+Accounts receivable increased $263,000 due to the timing of sales. 
+· 
+Inventories decreased $3,968,000 as we depleted a substantial portion of our domestic inventory prior to the final transition of full production of 70% of our printers to a contract manufacturer in China that was completed by the end of 2009. 
+· 
+Accounts payable increased $187,000 due to the timing of payments in the fourth quarter of 2009. 
+· 
+Accrued liabilities and other liabilities decreased $642,000 due primarily to lower payroll, fringe benefit and incentive compensation related accruals. 
+During 2008: 
+· 
+We reported net income of $1,444,000. 
+· 
+We recorded depreciation, amortization and non-cash compensation expense of $2,650,000. 
+· 
+We recorded a non-cash foreign currency exchange transaction gain of $368,000 from our UK subsidiary due to the strengthening of the U.S. dollar against the British pound. 
+· 
+We recorded non-cash deferred income tax expense of $592,000. 
+· 
+Accounts receivable increased by $2,611,000 due primarily to higher sales volume in the fourth quarter of 2008 compared to the fourth quarter of 2007. 
+· 
+Inventories increased by $1,257,000 due primarily to higher stocking levels resulting from our initiatives to move increased production to China and increased sales volume. 
+· 
+Accounts payable increased by $178,000 due to higher inventory purchases related to higher sales volumes during 2008. 
+· 
+Accrued liabilities and other liabilities increased by $19,000 due primarily to higher incentive compensation accruals largely offset by lower accrued legal fees related to our settled lawsuit with FutureLogic Inc. 
+Investing activities: Our capital expenditures were approximately $643,000 and $979,000 in 2009 and 2008, respectively. Expenditures in 2009 included approximately $295,000 for the purchase of new product tooling, $236,000 for the purchase of computer, networking equipment, and software, $72,000 for the purchase of manufacturing equipment, and the remaining amount primarily for the purchase of engineering equipment and leasehold improvements. Expenditures in 2008 included approximately $514,000 for the purchase of new product tooling, $329,000 for the purchase of computer, networking equipment, and software, $88,000 for the purchase of manufacturing equipment, and the remaining amount primarily for the purchase of engineering equipment and leasehold improvements. We expect our capital expenditures for 2010 to be approximately $2,0000,000, largely for new product tooling. 
+Financing activities: We generated approximately $290,000 of cash from financing activities during 2009 due to proceeds and tax benefits from stock option exercises. During 2008, we used approximately $229,000 for financing activities largely due to the repurchase of Company stock of approximately $543,000. The repurchases were offset by proceeds from stock option exercises of approximately $314,000 during 2008. 
+Working Capital 
+Our working capital increased to $20,474,000 at December 31, 2009 from $15,051,000 at December 31, 2008. Our current ratio also increased to 3.7 at December 31, 2009, compared to 2.9 at December 31, 2008. The increase in both our working capital and current ratio was largely due to higher cash balances and accounts receivable balances resulting from the timing of sales, somewhat offset by a lower inventory balance resulting from decreased inventory purchases and the utilization of inventory on hand. 
+Deferred Taxes 
+As of December 31, 2009, we had a net deferred tax asset of approximately $2,909,000. 
+22 
+Table of Contents 
+Credit Facility and Borrowings 
+On November 28, 2006, we signed a, five-year $20,000,000 credit facility (the “TD Bank Credit Facility”) with TD Bank. The TD Bank Credit Facility provides for a $20,000,000 revolving credit line expiring on November 28, 2011. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent and are secured by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the revolving credit line. The total deferred financing costs relating to expenses incurred to complete the TD Bank Credit Facility was $94,000. The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur additional indebtedness, the payment of dividends on our common stock and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2009. The following table lists the financial covenants and the performance measurements at December 31, 2009: 
+Financial Covenant 
+Requirement/Restriction 
+Calculation at December 31, 2009 
+Operating cash flow / Total debt service 
+Minimum of 1.25 times 
+74.0 times 
+Funded debt / EBITDA 
+Maximum of 3.25 
+0 times 
+As of December 31, 2009, we had no balances outstanding on the revolving credit line. Undrawn commitments under the TD Bank Credit facility were approximately $20,000,000 at December 31, 2009. 
+Stock Repurchase Program 
+On March 25, 2005, our Board of Directors approved a stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we were authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending on March 25, 2008, depending on market conditions, share price and other factors. 
+On November 1, 2007, our Board of Directors approved an increase in our stock repurchase authorization under the Stock Repurchase Program to $15,000,000 from $10,000,000. In addition, the Board approved a two-year extension of the Stock Repurchase Program to March 31, 2010. During 2009, we made no repurchases of common stock. As of December 31, 2009, we have repurchased a total of 1,164,100 shares of common stock for approximately $8,538,000, at an average price of $7.33 per share, since the inception of the Stock Repurchase Program. 
+Shareholders’ Equity 
+Shareholders’ equity increased $3,072,000 to $26,354,000 at December 31, 2009 from $23,282,000 at December 31, 2008. The increase was primarily due to net income of $2,140,000, proceeds of approximately $211,000 from the issuance of approximately 63,000 shares of common stock from stock option exercises, compensation expense related to stock options and restricted stock of $640,000, and an increase in additional paid-in capital of approximately $79,000 due to tax benefits resulting from employee stock transactions. 
+Contractual Obligations 
+TransAct’s contractual obligations as of December 31, 2009 were as follows: 
+(In thousands) 
+Total 
+< 1 year 
+1-3 years 
+3-5 years 
+> 5 years 
+Operating lease obligations 
+$ 
+3,993 
+$ 
+902 
+$ 
+1,532 
+$ 
+723 
+$ 
+836 
+Purchase obligations 
+22,918 
+19,472 
+3,446 
+- 
+- 
+Total 
+$ 
+26,911 
+$ 
+20,374 
+$ 
+4,978 
+$ 
+723 
+$ 
+836 
+Purchase obligations are for purchases made in the normal course of business to meet operational requirements, primarily of fully assembled printers and component part inventory. 
+Recently Issued Accounting Pronouncements 
+Codification: On July 1, 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”, also known as FASB Accounting Standards Codification (“ASC”) 105, “Generally Accepted Accounting Principles” (“ASC 105”) (the “Codification”). ASC 105 establishes the exclusive authoritative reference for U.S. GAAP for use in financial statements, except for Securities and Exchange Commission (“SEC”) rules and interpretive releases, which are also authoritative GAAP for SEC registrants. The Codification supersedes all existing non-SEC accounting and reporting standards. Going forward, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”), 
+which will serve to update the Codification, provide background information about the guidance and provide the basis for conclusions on the changes to the Codification. We have included references to the Codification, as appropriate, in these consolidated financial statements. 
+Participating Securities: ASC 260-10-45 “Earnings Per Share” (“ASC 260-10-45”) clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature 
+23 
+Table of Contents 
+are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. We have adopted the provisions of ASC 260-10-45 as of January 1, 2009. See Note 14 – Earnings per share. 
+Transfers of Financial Assets: ASC 860 “Transfers and Servicing” (“ASC 860”) improves the relevance and comparability of information that a reporting entity provides in its financial statements about transfers of financial assets. The provisions of ASC 860 will be applicable on January 1, 2010 and will be applied prospectively to transfers of financial assets completed after December 31, 2009. We do not anticipate these provisions will have a material impact on our consolidated financial statements. 
+Measuring Liabilities at Fair Value: In August 2009, the FASB issued ASU 2009-5, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value” (“ASU 2009-5”). This update provides clarification of the fair value measurement of financial liabilities when a quoted price in an active market for an identical liability (level 1 input of the valuation hierarchy) is not available. ASU 2009-5 was effective in the fourth quarter of 2009. This update did not have a material impact on our consolidated financial statements or disclosures. 
+Multiple-Deliverable Revenue Arrangements: In October 2009, the FASB issued ASU No. 2009-13, “Multiple-Deliverable Revenue Arrangements.” This ASU establishes the accounting and reporting guidance for arrangements including multiple revenue-generating activities. This ASU provides amendments to the criteria for separating deliverables, measuring and allocating arrangement consideration to one or more units of accounting. The amendments in this ASU also establish a selling price hierarchy for determining the selling price of a deliverable. Significantly enhanced disclosures are also required to provide information about a vendor’s multiple-deliverable revenue arrangements, including information about the nature and terms, significant deliverables, and its performance within arrangements. The amendments also require providing information about the significant judgments made and changes to those judgments and about how the application of the relative selling-price method affects the timing or amount of revenue recognition. The amendments in this ASU are effective prospectively for revenue arrangements entered into or materially modified in the fiscal years beginning on or after June 15, 2010. Early application is permitted. We are currently evaluating impact of this ASU. 
+Resource Sufficiency 
+We believe that our cash on hand, cash flows generated from operations and borrowings available under the TD Bank Credit Facility will provide sufficient resources to meet our working capital needs, finance our capital expenditures and meet our liquidity requirements through at least the next twelve months. 
+Impact of Inflation 
+We believe that our business has not been affected to a significant degree by inflationary trends during the past three years. However, inflation is still a factor in the worldwide economy and may increase the cost of purchasing printers from our contract manufacturer in China, as well as the cost of certain raw materials, component parts and labor used in the production of our products. It also may increase our operating expenses, manufacturing overhead expenses and the cost to acquire or replace fixed assets. Despite growing costs of oil, gas and freight over the last two years, we have generally been able to maintain or improve our profit margins through productivity and efficiency improvements, cost reduction programs and to a lesser extent, price increases, and we expect to be able to do the same during 2010. As such, we do not believe that inflation will have a significant impact on our business during 2010. 
+Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 
+Interest Rate Risk 
+Our exposure to market risk for changes in interest rates relates primarily to the investment of our available cash and cash equivalents. In accordance with our investment policy, we strive to achieve above market rates of return in exchange for accepting a prudent amount of incremental risk, which includes the risk of interest rate movements. Risk tolerance is constrained by an overriding objective to preserve capital. An effective increase or decrease of 10% in interest rates would not have a material effect on our results of operations or cash flows. 
+Foreign Currency Exchange Risk 
+A substantial portion of our sales are denominated in U.S. dollars and, as a result, we have relatively little exposure to foreign currency exchange risk with respect to sales made. This exposure may change over time as business practices evolve and could have a material adverse impact on our financial results in the future. We do not use forward exchange contracts to hedge exposures denominated in foreign currencies or any other derivative financial instruments for trading or speculative purposes. We estimate that the combined translational and transactional impact of a 10% overall movement in exchange rates from December 31, 2009 (principally the UK Pound Sterling) would have an immaterial effect on a pre-tax basis. 
+Item 8. Financial Statements and Supplementary Data. 
+The financial statements and schedule of the Company are annexed to this report as pages F-3 through F-18. An index to such materials appears on page F-1. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 
+None. 
+24 
+Table of Contents 
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. Part II, Item 8 of this Form 10-K sets forth the report of PricewaterhouseCoopers LLP, our independent registered public accounting firm, regarding its audit of TransAct’s internal control over financial reporting as of December 31, 2009. This section should be read in conjunction with the CEO and CFO certifications and the PricewaterhouseCoopers LLP report for a more complete understanding of the topics presented. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2009, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2009. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2009. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 
+Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2009. 
+The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. 
+Item 9B. Other Information. 
+Not applicable. 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance. 
+The information in response to this item is incorporated by reference from the Proxy Statement sections entitled “Election of Directors” and “Executive Officers.” 
+Executive Officers of the Registrant 
+The following list is included as an unnumbered item in Part III of this Report in lieu of being included in the Proxy Statement for the Annual Meeting of Stockholders to be held on May 27, 2010. 
+25 
+Table of Contents 
+The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. 
+Name 
+Age 
+Position 
+Bart C. Shuldman 
+52 
+Chairman of the Board, President and Chief Executive Officer 
+Steven A. DeMartino 
+40 
+Executive Vice President, Chief Financial Officer, Treasurer and Secretary 
+Michael S. Kumpf 
+60 
+Executive Vice President-Engineering 
+James B. Stetson 
+53 
+Senior Vice President and Business Manager of TSG 
+Tracey S. Chernay 
+50 
+Senior Vice President-Sales and Marketing 
+Andrew Hoffman 
+52 
+Senior Vice President-Operations 
+Benjamin C. Wyatt 
+36 
+Vice President Business Development 
+Bart C. Shuldman has been Chief Executive Officer, President and a Director of the Company since its formation in June 1996. In February 2001, Mr. Shuldman was elected Chairman of the Board. 
+Steven A. DeMartino was named as TransAct’s Executive Vice President, Chief Financial Officer, Treasurer and Secretary on June 1, 2004. Previously, Mr. DeMartino served as Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. 
+Michael S. Kumpf was appointed Executive Vice President of Engineering in March 2002. He served as Senior Vice President, Engineering from June 1996 to March 2002. 
+James B. Stetson was appointed Senior Vice President and Business Manager of TSG in January 2005. Previously, Mr. Stetson held the position of Executive Vice President of Sales and Marketing from February 2000 to December 2004, and Vice President of Latin American Sales from October 1997 to February 2000. 
+Tracey S. Chernay was appointed Senior Vice President, Sales and Marketing in June 2007, with responsibility for the sales and marketing of all TransAct printer products worldwide. Previously, Ms. Chernay served as Sr. Vice President, Marketing & Sales, POS & Banking with the Company from July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. 
+Andrew Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice President, Operations from September 1994 to November 2004. 
+Benjamin C. Wyatt was appointed Vice President, Business Development for TransAct in May 2008. Prior to joining TransAct, Mr. Wyatt was employed with Pitney Bowes Mail Services where he held the role of Director Business Development since 2006, and Manager Acquisitions and Integration from 2004 to 2006. 
+Item 11. Executive Compensation. 
+The information in response to this item is incorporated by reference from the Proxy Statement sections entitled “Executive Compensation and Certain Transactions” and “Compensation Discussion and Analysis.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Security Ownership of Certain Beneficial Owners and Management.” 
+26 
+Table of Contents 
+Information regarding our equity compensation plans as of December 31, 2009 is as follows: 
+Plan category 
+(a) 
+Number of securities to be issued upon exercise of outstanding options, warrants and rights 
+(b) 
+Weighted-average exercise price of outstanding options, warrants and rights 
+(c) 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) 
+Equity compensation plans approved by security holders: 
+1996 Stock Plan 
+249,117 
+$ 
+3.62 
+- 
+1996 Non-Employee Director Plan 
+146,250 
+11.97 
+- 
+2005 Equity Incentive Plan 
+536,500 
+5.93 
+36,000 
+Total 
+931,867 
+$ 
+6.26 
+36,000 
+Equity compensation plans not approved by security holders: 
+2001 Employee Stock Plan 
+30,161 
+$ 
+4.89 
+- 
+962,028 
+$ 
+6.22 
+36,000 
+The TransAct Technologies Incorporated 2001 Employee Stock Plan (the “2001 Employee Plan”) was adopted by our Board of Directors, without approval of our security holders, effective February 26, 2001. Under the 2001 Employee Plan, we may issue non-qualified stock options, shares of restricted stock, restricted units to acquire shares of common stock, stock appreciation rights and limited stock appreciation rights to key employees of TransAct or any of our subsidiaries and to non-employees who provide services to TransAct or any of our subsidiaries. The 2001 Employee Plan is administered by our Compensation Committee, which has the authority to determine the vesting period and other similar restrictions and terms of awards, provided that the exercise price of options granted under the plan may not be less than the fair market value of the underlying shares on the date of grant. 
+In May 2005, our shareholders approved the adoption of the 2005 Equity Incentive Plan. No new awards will be available for future issuance under any existing TransAct equity plan other than the 2005 Equity Incentive Plan. 
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Certain Relationships and Related Transactions.” 
+Item 14. Principal Accountant Fees and Services. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Independent Registered Public Accounting Firm’s Services and Fees.” 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules. 
+The financial statements and schedule filed as part of this report are listed in the accompanying Index to Financial Statements and Schedule. The exhibits filed as a part of this report are listed in the accompanying Index to Exhibits. 
+27 
+Table of Contents 
+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. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+By: 
+/s/ Bart C. Shuldman 
+Name: 
+Bart C. Shuldman 
+Title: 
+Chairman of the Board, President and Chief Executive Officer 
+Date: March 16, 2010 
+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/ Bart C. Shuldman 
+Chairman of the Board, 
+March 16, 2010 
+Bart C. Shuldman 
+President and Chief Executive Officer, 
+(Principal Executive Officer) 
+/s/ Steven A. DeMartino 
+Executive Vice President, 
+March 16, 2010 
+Steven A. DeMartino 
+Chief Financial Officer, 
+Treasurer and Secretary 
+(Principal Financial Officer) 
+/s/ Christopher Galletta 
+Corporate Controller 
+March 16, 2010 
+Christopher Galletta 
+(Principal Accounting Officer) 
+/s/ Charles A. Dill 
+Director 
+March 16, 2010 
+Charles A. Dill 
+/s/ Thomas R. Schwarz 
+Director 
+March 16, 2010 
+Thomas R. Schwarz 
+/s/ Graham Y. Tanaka 
+Director 
+March 16, 2010 
+Graham Y. Tanaka 
+28 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX TO FINANCIAL STATEMENTS AND SCHEDULE 
+Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Consolidated balance sheets as of December 31, 2009 and 20 0 8 
+F-3 
+Consolidated statements of operations for the years ended December 31, 2009, 2008 and 200 7 
+F-4 
+Consolidated statements of changes in shareholders' equity and comprehensive income (loss) for the years ended December 31, 2009, 2008 and 200 7 
+F-5 
+Consolidated statements of cash flows for the years ended December 31, 2009, 2008 and 200 7 
+F-6 
+Notes to consolidated financial statements 
+F-7 
+Financial Statement Schedule 
+The following financial statement schedule is included herein: 
+Schedule II - Valuation and Qualifying Accounts 
+F-19 
+All other financial statement schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto 
+F-1 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To the Board of Directors and Stockholders of TransAct Technologies Incorporated: 
+In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)1 present fairly, in all material respects, the financial position of TransAct Technologies Incorporated and its subsidiaries at December 31, 2009 and December 31, 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. In addition, in our opinion, the financial statement schedule listed in the index 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, 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 these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on these financial statements 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 
+Hartford, Connecticut 
+March 16, 2010 
+F-2 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+December 31, 
+2009 
+2008 
+Assets: 
+Current assets: 
+Cash and cash equivalents 
+$ 
+10,017 
+$ 
+2,000 
+Receivables, net 
+8,996 
+8,734 
+Inventories 
+5,952 
+9,919 
+Refundable income taxes 
+270 
+35 
+Deferred tax assets 
+2,240 
+2,054 
+Other current assets 
+521 
+352 
+Total current assets 
+27,996 
+23,094 
+Fixed assets, net 
+4,551 
+5,563 
+Goodwill 
+1,469 
+1,469 
+Deferred tax assets 
+669 
+1,759 
+Intangible and other assets, net of accumulated amortization of $390 and $306, respectively 
+214 
+349 
+6,903 
+9,140 
+Total assets 
+$ 
+34,899 
+$ 
+32,234 
+Liabilities and Shareholders’ Equity: 
+Current liabilities: 
+Accounts payable 
+$ 
+5,052 
+$ 
+4,863 
+Accrued liabilities 
+1,890 
+2,847 
+Deferred revenue 
+580 
+333 
+Total current liabilities 
+7,522 
+8,043 
+Deferred revenue, net of current portion 
+501 
+259 
+Deferred rent, net of current portion 
+385 
+473 
+Other liabilities 
+137 
+177 
+1,023 
+909 
+Total liabilities 
+8,545 
+8,952 
+Commitments and contingencies (Note 11) 
+Shareholders’ equity: 
+Preferred stock, $0.01 par value, 4,800,000 authorized, none issued and outstanding 
+- 
+- 
+Preferred stock, Series A, $0.01 par value, 200,000 authorized, none issued and outstanding 
+- 
+- 
+Common stock, $0.01 par value, 20,000,000 authorized at December 31, 2009 and 2008; 10,528,209 and 10,465,588 shares issued; 9,364,109 and 9,301,488 shares outstanding, at December 31, 2009 and 2008, respectively 
+105 
+105 
+Additional paid-in capital 
+21,820 
+20,890 
+Retained earnings 
+13,033 
+10,893 
+Accumulated other comprehensive loss, net of tax 
+(66 
+) 
+(68 
+) 
+Treasury stock, 1,164,100 shares, at cost 
+(8,538 
+) 
+(8,538 
+) 
+Total shareholders’ equity 
+26,354 
+23,282 
+Total liabilities and shareholders’ equity 
+$ 
+34,899 
+$ 
+32,234 
+See accompanying notes to consolidated financial statements. 
+F-3 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(In thousands, except per share data) 
+Year Ended December 31, 
+2009 
+2008 
+2007 
+Net sales 
+$ 
+58,346 
+$ 
+62,207 
+$ 
+48,766 
+Cost of sales 
+39,517 
+41,257 
+32,770 
+Gross profit 
+18,829 
+20,950 
+15,996 
+Operating expenses: 
+Engineering, design and product development 
+2,788 
+2,942 
+3,129 
+Selling and marketing 
+5,821 
+6,078 
+6,708 
+General and administrative 
+6,924 
+7,040 
+7,007 
+Legal fees associated with lawsuit (See Note 11) 
+- 
+3,029 
+2,907 
+15,533 
+19,089 
+19,751 
+Operating income (loss) 
+3,296 
+1,861 
+(3,755 
+) 
+Interest and other income (expense): 
+Interest expense 
+(70 
+) 
+(70 
+) 
+(69 
+) 
+Interest income 
+20 
+59 
+145 
+Other, net 
+(33 
+) 
+368 
+21 
+(83 
+) 
+357 
+97 
+Income (loss) before income taxes 
+3,213 
+2,218 
+(3,658 
+) 
+Income tax provision (benefit) 
+1,073 
+774 
+(1,384 
+) 
+Net income (loss) 
+$ 
+2,140 
+$ 
+1,444 
+$ 
+(2,274 
+) 
+Net income (loss) per common share: 
+Basic 
+$ 
+0.23 
+$ 
+0.16 
+$ 
+(0.24 
+) 
+Diluted 
+$ 
+0.23 
+$ 
+0.15 
+$ 
+(0.24 
+) 
+Shares used in per-share calculation: 
+Basic 
+9,289 
+9,308 
+9,364 
+Diluted 
+9,377 
+9,489 
+9,364 
+See accompanying notes to consolidated financial statements. 
+F-4 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS) 
+(In thousands, except share data) 
+Common Stock 
+Additional Paid-in 
+Retained 
+Treasury 
+Accumulated Other Comprehensive 
+Total Comprehensive 
+Shares 
+Amount 
+Capital 
+Earnings 
+Stock 
+Income (Loss) 
+Total 
+Income (Loss) 
+Balance, December 31, 2006 
+9,575,117 
+$ 
+104 
+$ 
+19,105 
+$ 
+11,405 
+$ 
+(6,492 
+) 
+$ 
+168 
+$ 
+24,290 
+Adoption of accounting for uncertainty in income taxes 
+- 
+- 
+- 
+318 
+- 
+- 
+318 
+Opening balance at January 1, 2007, as adjusted 
+9,575,117 
+104 
+19,105 
+11,723 
+(6,492 
+) 
+168 
+24,608 
+Cancellation of restricted stock 
+(9,750 
+) 
+- 
+- 
+- 
+- 
+- 
+- 
+Issuance of shares from exercise of stock options 
+33,199 
+- 
+149 
+- 
+- 
+- 
+149 
+Tax charge related to vesting of restricted stock 
+- 
+- 
+(97 
+) 
+- 
+- 
+- 
+(97 
+) 
+Purchase of treasury stock 
+(232,700 
+) 
+- 
+- 
+- 
+(1,503 
+) 
+- 
+(1,503 
+) 
+Share-based compensation expense 
+- 
+- 
+715 
+- 
+- 
+- 
+715 
+Comprehensive income (loss): 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+10 
+10 
+$ 
+10 
+Net loss 
+- 
+- 
+- 
+(2,274 
+) 
+- 
+- 
+(2,274 
+) 
+(2,274 
+) 
+Balance, December 31, 2007 
+9,365,866 
+104 
+19,872 
+9,449 
+(7,995 
+) 
+178 
+21,608 
+$ 
+(2,264 
+) 
+Cancellation of restricted stock 
+(1,250 
+) 
+- 
+- 
+- 
+- 
+- 
+Issuance of shares from exercise of stock options 
+66,972 
+1 
+313 
+- 
+- 
+- 
+314 
+Tax charge related to vesting of restricted stock 
+- 
+- 
+(98 
+) 
+- 
+- 
+- 
+(98 
+) 
+Purchase of treasury stock 
+(130,100 
+) 
+- 
+- 
+- 
+(543 
+) 
+- 
+(543 
+) 
+Share-based compensation expense 
+- 
+- 
+803 
+- 
+- 
+- 
+803 
+Comprehensive income (loss): 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(246 
+) 
+(246 
+) 
+$ 
+(246 
+) 
+Net income 
+- 
+- 
+- 
+1,444 
+- 
+- 
+1,444 
+1,444 
+Balance, December 31, 2008 
+9,301,488 
+105 
+20,890 
+10,893 
+(8,538 
+) 
+(68 
+) 
+23,282 
+$ 
+1,198 
+Cancellation of restricted stock 
+(500 
+) 
+- 
+- 
+- 
+- 
+- 
+Issuance of shares from exercise of stock options 
+63,121 
+- 
+211 
+- 
+- 
+- 
+211 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+79 
+- 
+- 
+- 
+79 
+Share-based compensation expense 
+- 
+- 
+640 
+- 
+- 
+- 
+640 
+Comprehensive income: 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+2 
+2 
+$ 
+2 
+Net income 
+- 
+- 
+- 
+2,140 
+- 
+- 
+2,140 
+2,140 
+Balance, December 31, 2009 
+9,364,109 
+$ 
+105 
+$ 
+21,820 
+$ 
+13,033 
+$ 
+(8,538 
+) 
+$ 
+(66 
+) 
+$ 
+26,354 
+$ 
+2,142 
+See accompanying notes to consolidated financial statements. 
+F-5 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+Year Ended December 31, 
+2009 
+2008 
+2007 
+Cash flows from operating activities: 
+Net income (loss) 
+$ 
+2,140 
+$ 
+1,444 
+$ 
+(2,274 
+) 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
+Share-based compensation expense 
+640 
+803 
+715 
+Incremental tax benefits from stock options exercised 
+(79 
+) 
+- 
+- 
+Depreciation and amortization 
+1,757 
+1,847 
+1,844 
+Deferred income taxes 
+1,002 
+592 
+(1,839 
+) 
+(Gain) loss on sale of fixed assets 
+- 
+3 
+(14 
+) 
+Foreign currency transaction (gain) loss 
+33 
+(368 
+) 
+6 
+Changes in operating assets and liabilities: 
+Receivables 
+(263 
+) 
+(2,611 
+) 
+5,294 
+Inventories 
+3,968 
+(1,257 
+) 
+(1,098 
+) 
+Refundable income taxes 
+(235 
+) 
+14 
+(9 
+) 
+Other current assets 
+(169 
+) 
+8 
+144 
+Other assets 
+34 
+29 
+40 
+Accounts payable 
+187 
+178 
+691 
+Accrued liabilities and other liabilities 
+(642 
+) 
+19 
+(575 
+) 
+Accrued restructuring expenses 
+- 
+- 
+(315 
+) 
+Net cash provided by operating activities 
+8,373 
+701 
+2,610 
+Cash flows from investing activities: 
+Purchases of fixed assets 
+(643 
+) 
+(979 
+) 
+(2,166 
+) 
+Proceeds from sale of assets 
+- 
+- 
+37 
+Net cash used in investing activities 
+(643 
+) 
+(979 
+) 
+(2,129 
+) 
+Cash flows from financing activities: 
+Payment of deferred financing costs 
+- 
+- 
+(6 
+) 
+Proceeds from stock option exercises 
+211 
+314 
+149 
+Purchases of common stock for treasury 
+- 
+(543 
+) 
+(1,503 
+) 
+Incremental tax benefits from stock options exercised 
+79 
+- 
+- 
+Net cash provided by (used in) financing activities 
+290 
+(229 
+) 
+(1,360 
+) 
+Effect of exchange rate changes on cash 
+(3 
+) 
+(54 
+) 
+4 
+Increase (decrease) in cash and cash equivalents 
+8,017 
+(561 
+) 
+(875 
+) 
+Cash and cash equivalents, beginning of period 
+2,000 
+2,561 
+3,436 
+Cash and cash equivalents, end of period 
+$ 
+10,017 
+$ 
+2,000 
+$ 
+2,561 
+Supplemental cash flow information: 
+Interest paid 
+$ 
+51 
+$ 
+51 
+$ 
+51 
+Income taxes paid 
+482 
+34 
+742 
+See accompanying notes to consolidated financial statements. 
+F-6 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. Description of business 
+TransAct Technologies Incorporated (“TransAct” or the “Company”), which has its headquarters in Hamden, CT and its primary operating facility in Ithaca, NY, operates in one industry segment, market-specific printers for transaction-based industries. These industries include casino, gaming, lottery, banking, kiosk and point-of-sale. Our printers are designed based on market specific requirements and are sold under the Ithaca® and Epic product brands. We distribute our products through OEMs, value-added resellers, selected distributors, and directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. We also generate revenue from the after-market side of the business, providing printer service, supplies and spare parts. 
+2. Summary of significant accounting policies 
+Principles of consolidation: The accompanying consolidated financial statements were prepared on a consolidated basis to include the accounts of TransAct and its wholly-owned subsidiaries. All intercompany accounts, transactions and unrealized profit were eliminated in consolidation. 
+Reclassifications: Certain amounts in the prior years’ financial statements have been reclassified to conform to the current year’s presentation. 
+Use of estimates: The accompanying consolidated financial statements were prepared using estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+Segment reporting: We apply the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” We view our operations and manage our business as one segment: the design, development, manufacture and sale of transaction-based printers and printer-related service, supplies and replacement parts . Factors used to identify TransAct’s single operating segment include the organizational structure of the Company and the financial information available for evaluation by the chief operating decision-maker in making decisions about how to allocate resources and assess performance. 
+Cash and cash equivalents: We consider all highly liquid investments with a maturity date of three months or less at date of purchase to be cash equivalents. 
+Allowance for doubtful accounts: We establish an allowance for doubtful accounts to ensure trade receivables are valued appropriately. We maintain an allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, significant one-time events and historical experience. We record a specific allowance for individual accounts when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, we would further adjust estimates of the recoverability of receivables. Allowances for doubtful accounts on accounts receivable balances were $57,000 and $55,000 as of December 31, 2009 and 2008, respectively. 
+Inventories: Inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. 
+Fixed assets: Fixed assets are stated at cost. Depreciation is recorded using the straight-line method over the estimated useful lives. The estimated useful life of tooling is five years; machinery and equipment is ten years; furniture and office equipment is five to ten years; and computer software and equipment is three to seven years. Leasehold improvements are amortized over the shorter of the term of the lease or the useful life of the asset. Costs related to repairs and maintenance are expensed as incurred. The costs of sold or retired assets are removed from the related asset and accumulated depreciation accounts and any gain or loss is recognized. Depreciation expense was $1,655,000, $1,744,000 and $1,743,000 in 2009, 2008 and 2007, respectively. 
+Leases: Rent expense under non-cancelable operating leases with scheduled rent increases or free rent periods are accounted for on a straight-line basis over the lease term, beginning on the date of control of physical use of the asset or of initial possession. The amount of the excess of straight-line rent expense over scheduled payments is recorded as a deferred liability. Construction allowances and other such lease incentives are recorded as deferred credits, and are amortized on a straight-line basis as a reduction of rent expense beginning in the period they are deemed to be earned, which generally coincides with the occupancy date. 
+Goodwill: We account for goodwill in accordance with the provisions of ASC 350, “Intangibles - Goodwill and Other.” We test goodwill annually for impairment, or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We have performed an impairment test as of December 31, 2009 and determined that no impairment has occurred. 
+F-7 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Revenue recognition: Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within ASC 605, “Revenue Recognition.” Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms, which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We account for all revenue arrangements involving multiple deliverables in accordance with ASC 605, Revenue Recognition (ASC 605), 605-25, Multiple-Element Arrangements . For these arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Concentration of credit risk: Financial instruments that potentially expose TransAct to concentrations of credit risk are limited to cash and cash equivalents held by our banks in excess of insured limits and accounts receivable. 
+Accounts receivable from customers representing 10% or more of total accounts receivable were as follows: 
+December 31, 
+2009 
+2008 
+Customer A 
+24 
+% 
+20 
+% 
+Customer B 
+18 
+% 
+* 
+Customer C 
+* 
+10 
+% 
+* -Customers represent less than 10% of total accounts receivable 
+F-8 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Sales to customers representing 10% or more of total net sales were as follows: 
+Year ended December 31, 
+2009 
+2008 
+2007 
+Customer A 
+19 
+% 
+28 
+% 
+14 
+% 
+Customer B 
+10 
+% 
+* 
+10 
+% 
+Customer C 
+12 
+% 
+* 
+* 
+* -Customers represent less than 10% of total net sales 
+Prior to 2008, the primary operations of our United Kingdom subsidiary, a European sales and service center, related to revenue generated from a service contract with a single customer in the United Kingdom. The service contract, which represented a substantial portion of our U.K. subsidiary’s revenue, was renewed in April 2007 through November 2007 at a lower minimum sales value compared to the minimum sales value of the prior year’s contract. The service contract ended in November 2007 and was not renewed, as the customer replaced our printers with a different technology that we were unable to provide. 
+Warranty: We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. 
+The following table summarizes the activity recorded in the accrued product warranty liability: 
+Year ended December 31, 
+(In thousands) 
+2009 
+2008 
+2007 
+Balance, beginning of period 
+$ 
+393 
+$ 
+500 
+$ 
+603 
+Accruals for warranties issued during the period 
+112 
+297 
+173 
+Changes in estimates 
+(96 
+) 
+(34 
+) 
+183 
+Settlements during the period 
+(176 
+) 
+(370 
+) 
+(459 
+) 
+Balance, end of period 
+$ 
+233 
+$ 
+393 
+$ 
+500 
+Approximately $64,000 and $133,000 of the accrued product warranty liability were classified as long-term at December 31, 2009 and 2008, respectively. 
+Research and development expenses: Research and development expenses include engineering, design and product development expenses incurred in connection with specialized engineering and design to introduce new products and to customize existing products, and are expensed as a component of operating expenses as incurred. We recorded approximately $2,788,000, $2,942,000 and $3,129,000 of research and development expenses in 2009, 2008 and 2007, respectively. 
+Advertising: Advertising costs are expensed as incurred. Advertising expenses, which are included in selling and marketing expense on the accompanying consolidated statements of operations, for 2009, 2008 and 2007 totaled $763,000, $916,000 and $979,000, respectively. These expenses include items such as consulting and professional services, tradeshows, and print advertising. 
+Restructuring: We continually evaluate our cost structure to ensure that it is appropriately positioned to respond to changing market conditions. We record pre-tax restructuring charges in accordance with ASC 420-10-25-4 “Exit or Disposal Cost Obligations.” 
+Income taxes: The income tax amounts reflected in the accompanying financial statements are accounted for under the liability method in accordance with ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. We assess the likelihood that net deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. In accordance with ASC 740, we identified, evaluated and measured the amount of benefits to be recognized for our tax return positions. See Note 13 for information regarding our accounting for income taxes. 
+F-9 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Foreign currency translation: The financial position and results of operations of our foreign subsidiary in the United Kingdom are measured using local currency as the functional currency. Assets and liabilities of such subsidiary have been translated into U.S. dollars at the year-end exchange rate, related revenues and expenses have been translated at the average exchange rate for the year, and shareholders’ equity has been translated at historical exchange rates. The resulting translation gains or losses, net of tax, are recorded in stockholders’ equity as a cumulative translation adjustment, which is a component of accumulated other comprehensive income. Foreign currency transaction gains and losses, including those related to intercompany balances, are recognized in other income (expense). 
+Comprehensive income: ASC 220, “Comprehensive Income,” requires that items defined as comprehensive income or loss be separately classified in the financial statements and that the accumulated balance of other comprehensive income or loss be reported separately from accumulated deficit and additional paid-in-capital in the equity section of the balance sheet. We include the foreign currency translation adjustment, net of tax, related to our subsidiary in the United Kingdom within our calculation of comprehensive income. 
+Share-based Payments: At December 31, 2009, we had stock-based employee compensation plans, which are described more fully in Note 12 “Stock incentive plans.” We account for those plans under the recognition and measurement principles of ASC 718 “Compensation – Stock Compensation.” Share-based compensation expense is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. We have no awards with market or performance conditions. 
+We use the Black-Scholes option-pricing model to calculate the fair value of share based awards. The key assumptions for this valuation method include the expected term of the option, stock price volatility, risk-free interest rate, dividend yield, market price of our underlying stock and exercise price. Many of these assumptions are judgmental and highly sensitive in the determination of compensation expense. In addition, we estimate forfeitures when recognizing compensation expense, and we adjust our estimate of forfeitures over the requisite service period based on the extent to which actual forfeitures differ, or are expected to differ, from such estimates. Changes in estimated forfeitures are recognized through a cumulative true-up adjustment in the period of change and also impacts the amount of compensation expense to be recognized in future periods. 
+Net income and loss per share: We report net income or loss per share in accordance with ASC 260 “Earnings per Share (EPS).” Under this guidance, basic EPS, which excludes dilution, is computed by dividing income or loss available to common shareholders by the weighted average number of common shares outstanding for the period. Unvested restricted stock is excluded from the calculation of weighted average common shares for basic EPS. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted EPS includes restricted stock and in-the-money stock options using the treasury stock method. During a loss period, the assumed exercise of in-the-money stock options has an anti-dilutive effect, and therefore, these instruments are excluded from the computation of dilutive EPS. See Note 14 - Earnings per Share. 
+3. Recently issued accounting pronouncements 
+Codification: On July 1, 2009, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles”, also known as FASB ASC 105, “Generally Accepted Accounting Principles (“GAAP”)” (“ASC 105”) (the “Codification”). ASC 105 establishes the exclusive authoritative reference for U.S. GAAP for use in financial statements, except for Securities and Exchange Commission (“SEC”) rules and interpretive releases, which are also authoritative GAAP for SEC registrants. The Codification supersedes all existing non-SEC accounting and reporting standards. Going forward, the FASB will not issue new standards in the form of Statements, FASB Staff Positions or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”), which will serve to update the Codification, provide background information about the guidance and provide the basis for conclusions on the changes to the Codification. We have included references to the Codification, as appropriate, in these consolidated financial statements. 
+Participating Securities: ASC 260-10-45 “Earnings Per Share” (“ASC 260-10-45”) clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. We have adopted the provisions of ASC 260-10-45 as of January 1, 2009. See Note 14 – Earnings per share. 
+Transfers of Financial Assets: ASC 860 “Transfers and Servicing” (“ASC 860”) improves the relevance and comparability of information that a reporting entity provides in its financial statements about transfers of financial assets. The provisions of ASC 860 will be applicable on January 1, 2010 and will be applied prospectively to transfers of financial assets completed after December 31, 2009. We do not anticipate these provisions will have a material impact on our consolidated financial statements. 
+F-10 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+3. Recently issued accounting pronouncements (continued) 
+Measuring Liabilities at Fair Value: In August 2009, the FASB issued ASU 2009-5, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value” (“ASU 2009-5”). This update provides clarification of the fair value measurement of financial liabilities when a quoted price in an active market for an identical liability (level 1 input of the valuation hierarchy) is not available. ASU 2009-5 is effective in the fourth quarter of 2009. This update did not have a material impact on our consolidated financial statements or disclosures. 
+Multiple-Deliverable Revenue Arrangements: In October 2009, the FASB issued ASU No. 2009-13, “Multiple-Deliverable Revenue Arrangements.” This ASU establishes the accounting and reporting guidance for arrangements including multiple revenue-generating activities. This ASU provides amendments to the criteria for separating deliverables, measuring and allocating arrangement consideration to one or more units of accounting. The amendments in this ASU also establish a selling price hierarchy for determining the selling price of a deliverable. Significantly enhanced disclosures are also required to provide information about a vendor’s multiple-deliverable revenue arrangements, including information about the nature and terms, significant deliverables, and its performance within arrangements. The amendments also require providing information about the significant judgments made and changes to those judgments and about how the application of the relative selling-price method affects the timing or amount of revenue recognition. The amendments in this ASU are effective prospectively for revenue arrangements entered into or materially modified in the fiscal years beginning on or after June 15, 2010. Early application is permitted. We are currently evaluating the impact of this ASU. 
+4. Inventories 
+The components of inventories are: 
+December 31, 
+(In thousands) 
+2009 
+2008 
+Raw materials and purchased component parts 
+$ 
+4,466 
+$ 
+7,207 
+Work-in-process 
+2 
+27 
+Finished goods 
+1,484 
+2,685 
+$ 
+5,952 
+$ 
+9,919 
+5. Fixed assets 
+The components of fixed assets are: 
+December 31, 
+(In thousands) 
+2009 
+2008 
+Tooling, machinery and equipment 
+$ 
+13,721 
+$ 
+13,316 
+Furniture and office equipment 
+1,704 
+1,694 
+Computer software and equipment 
+4,922 
+4,694 
+Leasehold improvements 
+1,874 
+1,872 
+22,221 
+21,576 
+Less: accumulated depreciation and amortization 
+(17,670 
+) 
+(16,013 
+) 
+$ 
+4,551 
+$ 
+5,563 
+6. Intangible assets 
+Identifiable intangible assets are recorded in Intangible assets and other assets in the accompanying consolidated balance sheets. Identifiable intangible assets are comprised of the following: 
+December 31, 
+2009 
+2008 
+(In thousands) 
+Gross Amount 
+Accumulated Amortization 
+Gross Amount 
+Accumulated Amortization 
+Purchased technology 
+$ 
+364 
+$ 
+(273 
+) 
+$ 
+364 
+$ 
+(213 
+) 
+Covenant not to compete 
+146 
+(94 
+) 
+146 
+(73 
+) 
+Patents 
+57 
+(23 
+) 
+57 
+(20 
+) 
+Total 
+$ 
+567 
+$ 
+(390 
+) 
+$ 
+567 
+$ 
+(306 
+) 
+F-11 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+6. Intangible assets (continued) 
+Amortization expense was $84,000 in 2009, 2008 and 2007, respectively. Amortization expense for each of the next five years ending December 31 is expected to be as follows: $84,000 in 2010; $55,000 in 2011; $13,000 in 2012; $3,000 in 2013; $3,000 in 2014; and $19,000 thereafter. 
+7. Accrued liabilities 
+The components of accrued liabilities (current portion) are: 
+December 31, 
+(In thousands) 
+2009 
+2008 
+Payroll and fringe benefits 
+$ 
+1,189 
+$ 
+1,771 
+Income taxes 
+6 
+134 
+Warranty 
+169 
+260 
+Professional and consulting 
+171 
+114 
+Other 
+355 
+568 
+$ 
+1,890 
+$ 
+2,847 
+8. Accrued business consolidation and restructuring expenses 
+We continually evaluate our cost structure to ensure that it is appropriately positioned to respond to changing market conditions. Given recent economic trends, in 2008 and continuing in 2009, we initiated and completed certain restructuring programs to better utilize its workforce. These restructuring activities reduced the number of employees and caused the Company to incur costs for employee termination benefits related to the employee reductions. During 2009 and 2008, we recorded pre-tax restructuring charges of approximately $211,000 and $25,000, respectively, in accordance with ASC 420-10-25-4 “Exit or Disposal Cost Obligations.” These one-time termination benefit charges have been included within general and administrative expenses in the accompanying consolidated statements of operations. The restructuring activity during 2009 and 2008 included severance costs related to the termination of 17 and 2 employees, respectively. 
+The following table summarizes the activity recorded in accrued restructuring expenses during 2009 and 2008, and is included in accrued liabilities in the accompanying consolidated balance sheets. 
+December 31, 
+(In thousands) 
+2009 
+2008 
+Accrual balance, beginning of period 
+$ 
+18 
+$ 
+32 
+Pre-tax severance charges 
+211 
+25 
+Cash payments 
+(216 
+) 
+(39 
+) 
+Accrual balance, end of period 
+$ 
+13 
+$ 
+18 
+9. Retirement savings plan 
+We maintain a 401(k) plan under which all full-time employees are eligible to participate at the beginning of each month immediately following their date of hire. We match employees’ contributions at a rate of 50% of employees’ contributions up to the first 6% of the employees’ compensation contributed to the 401(k) plan. Our matching contributions were $237,000, $244,000 and $247,000 in 2009, 2008 and 2007, respectively. 
+10. Borrowings 
+On November 28, 2006, we signed a five-year $20,000,000 credit facility (the “TD Bank Credit Facility”) with TD Bank, N.A. (“TD Bank”). The TD Bank Credit Facility provides for a $20,000,000 revolving credit line expiring on November 28, 2011. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent and are collateralized by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the revolving credit line. The total deferred financing costs relating to expenses incurred to complete the TD Bank Credit Facility was $94,000. The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur indebtedness, the payment of dividends on our common stock and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2009. 
+F-12 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+10. Borrowings (continued) 
+As of December 31, 2009, we had no outstanding borrowings on the revolving credit line. Undrawn commitments under the TD Bank Credit Facility were $20,000,000 at December 31, 2009. 
+11. Commitments and contingencies 
+We had been involved in patent litigation with FutureLogic, Inc. (“FutureLogic”) with respect to our patents U.S. Patent 6,924,903 and U.S. Patent 7,099,035. On May 13, 2008, we signed a Patent License and Settlement Agreement with FutureLogic that settled the current patent litigation and all other legal matters outstanding between the two parties. Under the Patent License and Settlement Agreement, FutureLogic agreed to license our dual port technology for printers and upgrade kits that utilize the patented technology. The license grants FutureLogic worldwide, perpetual rights for U.S. Patent 6,924,903, U.S. Patent 7,099,035, related applications and patents, and foreign counterparts. 
+At December 31, 2009, we were the lessee on operating leases for equipment and real property. Rent expense was approximately $1,024,000, $1,030,000 and $1,152,000 in 2009, 2008 and 2007, respectively. Minimum aggregate rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2009 are as follows: $902,000 in 2010; $943 ,000 in 2011; $589,000 in 2012; $358,000 in 2013; $365,000 in 2014; and $836,000 thereafter. 
+12. Stock incentive plans 
+Stock incentive plans . We currently have four primary stock incentive plans: the 1996 Stock Plan, which provided for the grant of awards to officers and other key employees of the Company; the 1996 Directors’ Stock Plan, which provided for non-discretionary awards to non-employee directors; the 2001 Employee Stock Plan, which provided for the grant of awards to key employees of the Company and other non-employees who provided services to the Company; and the 2005 Equity Incentive Plan, which provides for awards to executives, key employees, directors and consultants. The plans generally provide for awards in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units, (v) stock appreciation rights or (vi) limited stock appreciation rights. However, the 2001 Employee Stock Plan does not provide for incentive stock option awards. Options granted under these plans have exercise prices equal to 100% of the fair market value of the common stock at the date of grant. Options granted have a ten-year term and generally vest over a three- to five-year period, unless automatically accelerated for certain defined events. As of May 2005, no new awards will be made under the 1996 Stock Plan, the 1996 Directors’ Stock Plan or the 2001 Employee Stock Plan. Under our 2005 Equity Incentive Plan, we may authorize up to 600,000 of shares of TransAct common stock. At December 31, 2009, approximately 36,000 shares of common stock remained available for issuance under the 2005 Equity Incentive Plan. 
+Under the assumptions indicated below, the weighted-average fair value of stock option grants for the years ended December 31, 2009, 2008 and 2007 was $2.56, $5.85 and $5.81, respectively. The table below indicates the key assumptions used in the option valuation calculations for options granted in the years ended December 31, 2009, 2008 and 2007 and a discussion of our methodology for developing each of the assumptions used in the valuation model: 
+Year ended December 31, 
+2009 
+2008 
+2007 
+Expected option term 
+6.0 years 
+5.7 years 
+6.0 years 
+Expected volatility 
+67.4 
+% 
+61.7 
+% 
+71.2 
+% 
+Risk-free interest rate 
+2.0 
+% 
+3.0 
+% 
+4.5 
+% 
+Dividend yield 
+0 
+% 
+0 
+% 
+0 
+% 
+Expected Option Term - This is the weighted average period of time over which the options granted are expected to remain outstanding giving consideration to our historical exercise patterns. Options granted have a maximum term of ten years. An increase in the expected term will increase compensation expense. 
+Expected Volatility – The stock volatility for each grant is measured using the weighted average of historical daily price changes of our common stock over the most recent period approximately equal to the expected option term of the grant. An increase in the expected volatility factor will increase compensation expense. 
+Risk-Free Interest Rate - This is the U.S. Treasury rate in effect at the time of grant having a term approximately equal to the expected term of the option. An increase in the risk-free interest rate will increase compensation expense. 
+F-13 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+12. Stock incentive plans (continued) 
+Dividend Yield - We have not made any dividend payments on our common stock, and we have no plans to pay dividends in the foreseeable future. An increase in the dividend yield will decrease compensation expense. 
+For the years ending December 31, 2009, 2008 and 2007, we recorded $640,000, $803,000, and $715,000 of share-based compensation costs, respectively, in our consolidated statements of operations. We recorded income tax benefits of $214,000, $280,000, and $270,000 in 2009, 2008, and 2007 respectively, related to share-based compensation. At December 31, 2009, these benefits are recorded as a deferred tax asset in the consolidated balance sheet. 
+The 1996 Stock Plan, 1996 Directors’ Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan option activity is summarized below: 
+Number of Shares 
+Weighted Average Exercise Price 
+Weighted Average Remaining Contractual Term 
+Aggregate Intrinsic Value 
+Outstanding at December 31, 2008 
+851,649 
+$ 
+6.87 
+Granted 
+159,000 
+2.56 
+Exercised 
+(63,121 
+) 
+3.35 
+Forfeited 
+(7,500 
+) 
+5.24 
+Expired 
+(1,000 
+) 
+21.71 
+Outstanding at December 31, 2009 
+939,028 
+$ 
+6.37 
+5.5 years 
+$ 
+1,852,000 
+Options exercisable at December 31, 2009 
+537,428 
+$ 
+7.10 
+3.5 years 
+$ 
+984,000 
+Options vested or expected to vest 
+746,403 
+$ 
+7.14 
+4.6 years 
+$ 
+1,138,000 
+Shares that are issued upon exercise of employee stock options are newly issued shares and not issued from treasury stock. As of December 31, 2009, unrecognized compensation cost related to stock options totaled $984,000, which is expected to be recognized over a weighted average period of 3.3 years. 
+The total intrinsic value of stock options exercised was $161,000, $402,000 and $61,000 and the total fair value of stock options vested was $341,000, $247,000, and $124,000 during the years ended December 31, 2009, 2008 and 2007, respectively. Cash received from option exercises were $211,000, $314,000 and $149,000 for 2009, 2008 and 2007, respectively. We recorded a realized tax benefit in 2009 from equity-based awards of $190,000 related to options exercised which has been included as a component of cash flows from financing activities in the consolidated statement of cash flows. 
+Restricted stock: Under the 1996 Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan, we have granted shares of restricted common stock, for no consideration, to our officers, directors and certain key employees. R estricted stock activity for the 1996 Stock Plan , 2001 Employee Stock Plan and 2005 Equity Incentive Plan is summarized below: 
+Shares 
+Weighted Average Grant Date Fair Values 
+Nonvested shares at December 31, 2008 
+60,850 
+$ 
+12.15 
+Granted 
+- 
+- 
+Vested 
+(37,350 
+) 
+12.91 
+Canceled 
+(500 
+) 
+10.03 
+Nonvested shares at December 31, 2009 
+23,000 
+$ 
+10.97 
+As of December 31, 2009, unrecognized compensation cost related to restricted stock totaled $119,000, which is expected to be recognized over a weighted average period of 1.0 year. 
+F-14 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Income taxes 
+The components of the income tax provision (benefit) are as follows: 
+Year Ended December 31, 
+(In thousands) 
+2009 
+2008 
+2007 
+Current: 
+Federal 
+$ 
+53 
+$ 
+- 
+$ 
+(32 
+) 
+State 
+13 
+16 
+35 
+Foreign 
+5 
+166 
+452 
+Deferred: 
+Federal 
+891 
+386 
+(1,693 
+) 
+State 
+110 
+207 
+(144 
+) 
+Foreign 
+1 
+(1 
+) 
+(2 
+) 
+Income tax provision (benefit) 
+$ 
+1,073 
+$ 
+774 
+$ 
+(1,384 
+) 
+At December 31, 2009, we have $1,478,000 of state net operating loss carryforwards that begin to expire in 2014, and no federal net operating loss carryforwards. We also have approximately $718,000 in federal research and development tax credit carryforwards that begin to expire in 2025, $103,000 in state tax credit carryforwards that begin to expire in 2010, and foreign tax credit carryforwards of approximately $243,000 that begin to expire in 2018. We had foreign income (loss) before taxes of ($49,000), $541,000 and $1,486,000 in 2009, 2008 and 2007, respectively. 
+Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Our gross deferred tax assets and liabilities were comprised of the following: 
+December 31, 
+(In thousands) 
+2009 
+2008 
+Deferred tax assets: 
+Net operating losses 
+$ 
+129 
+$ 
+122 
+Capitalized research and development 
+342 
+413 
+Inventory reserves 
+1,066 
+1,081 
+Deferred revenue 
+91 
+139 
+Warranty reserve 
+82 
+139 
+Stock compensation expense 
+421 
+360 
+Foreign tax and other credits 
+913 
+1,437 
+Other liabilities and reserves 
+435 
+456 
+Gross deferred tax assets 
+3,479 
+4,147 
+Valuation allowance 
+(76 
+) 
+(26 
+) 
+Net deferred tax assets 
+3,403 
+4,121 
+Gross deferred tax liabilities: 
+Depreciation 
+453 
+269 
+Other 
+41 
+39 
+Net deferred tax liabilities 
+494 
+308 
+Total net deferred tax assets 
+$ 
+2,909 
+$ 
+3,813 
+During 2009, we recorded a full valuation allowance of $26,000 on the foreign net operating los s from our Macau subsidiary. We also recorded a full valuation allowance of $9,000 against certain state net operating loss carryforwards and $27,000 against certain state tax credits. 
+F-15 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Income taxes (continued) 
+Differences between the U.S. statutory federal income tax rate and our effective income tax rate are analyzed below: 
+Year Ended December 31, 
+2009 
+2008 
+2007 
+Federal statutory tax rate 
+34.0 
+% 
+34.0 
+% 
+(34.0 
+)% 
+State income taxes, net of federal income taxes 
+2.5 
+6.6 
+(2.0 
+) 
+Tax benefit from tax credits, net of valuation allowance 
+(4.5 
+) 
+(5.6 
+) 
+(4.0 
+) 
+Foreign rate differential 
+- 
+(2.4 
+) 
+0.2 
+Valuation allowance and tax accruals 
+0.8 
+1.2 
+- 
+Permanent items 
+1.0 
+1.4 
+0.9 
+Other 
+(0.3 
+) 
+(0.3 
+) 
+1.1 
+Effective tax rate 
+33.5 
+% 
+34.9 
+% 
+(37.8 
+)% 
+Effective January 1, 2007 we adopted the accounting provision in ASC Topic 740 related to uncertain tax positions. As a result of the adoption, we recognized a decrease to reserves for uncertain tax positions. This decrease was accounted for as a $318,000 adjustment to the beginning balance of retained earnings in the consolidated balance sheets. Including the cumulative effect decrease, at the beginning of 2007 we had approximately $79,000 of total gross unrecognized tax benefits that, if recognized, would favorably affect the effective income tax rate in any future periods. 
+The total gross unrecognized tax benefits at December 31, 2009 are $189,000, of which $116,000 is recorded as a reduction of the related deferred tax asset, and $73,000 is recorded as a long term liability. At December 31, 2009 and 2008, we had approximately $189,000 and $160,000 of total gross unrecognized tax benefits that, if recognized, would favorably affect the effective income tax rate in any future periods. We are not aware of any events that could occur within the next twelve months that could cause a significant change in the total amount of unrecognized tax benefits. A tabular reconciliation of the gross amounts of unrecognized tax benefits at the beginning and end of the year is as follows: 
+(In thousands) 
+2009 
+2008 
+Unrecognized tax benefits as of January 1 
+$ 
+160 
+$ 
+125 
+Tax positions taken during the current period 
+29 
+36 
+Settlements 
+- 
+- 
+Lapse of statute of limitations 
+- 
+(1 
+) 
+Unrecognized tax benefits as of December 31 
+$ 
+189 
+$ 
+160 
+We are subject to U.S. federal income tax as well as income tax of certain state and foreign jurisdictions. We have substantially concluded all U.S. federal income tax, state and local, and foreign tax matters through 2003. During 2008, a limited scope examination of our 2005 and 2006 federal tax returns was completed. However, our federal tax returns for the years 2004 through 2008 remain open to examination. Various state and foreign tax jurisdiction tax years remain open to examination as well, though we believe that any additional assessment would be immaterial to the consolidated financial statements. No federal, state or foreign tax jurisdiction income tax returns are currently under examination. 
+We do not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2010. 
+We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2009 and 2008, we have approximately $12,000 and $7,000 of accrued interest and penalties related to uncertain tax positions. 
+F-16 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+14. Earnings per share 
+For 2009, 2008 and 2007, earnings per share were computed as follows (in thousands, except per share amounts): 
+Year Ended December 31, 
+2009 
+2008 
+2007 
+Net income (loss) 
+$ 
+2,140 
+$ 
+1,444 
+$ 
+(2,274 
+) 
+Shares: 
+Basic: Weighted average common shares outstanding 
+9,289 
+9,308 
+9,364 
+Add: Dilutive effect of outstanding options as determined by the treasury stock method 
+88 
+181 
+- 
+Diluted: Weighted average common and common equivalent shares outstanding 
+9,377 
+9,489 
+9,364 
+Net income (loss) per common share: 
+Basic 
+$ 
+0.23 
+$ 
+0.16 
+$ 
+(0.24 
+) 
+Diluted 
+0.23 
+0.15 
+(0.24 
+) 
+FASB ASC 260-10-45 “Earnings Per Share” (“ASC 260-10-45”) clarifies that all outstanding unvested share-based payment awards that contain rights to nonforfeitable dividends participate in undistributed earnings with common shareholders. Awards of this nature are considered participating securities and the two-class method of computing basic and diluted earnings per share must be applied. ASC 260-10-45 was effective on January 1, 2009. This provision did not have a material effect on our computation of basic and diluted earnings per share since our unvested restricted stock awards do not contain rights to nonforfeitable dividends. 
+Certain stock-based awards were not included in the full year computation of earnings per diluted share because the effect would be anti-dilutive. Anti-dilutive stock options and restricted shares excluded from the computation of earnings per dilutive share were 525,500, 258,250, and 871,379, at December 31, 2009, 2008 and 2007 respectively. 
+15. Stock repurchase program 
+On March 25, 2005, our Board of Directors approved a stock repurchase program (“the Stock Repurchase Program”). Under the Stock Repurchase Program, we were authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending on March 25, 2008, depending on market conditions, share price and other factors. 
+On November 1, 2007, our Board of Directors approved an increase in our stock repurchase authorization under the Stock Repurchase Program to $15,000,000 from $10,000,000. In addition, the Board approved a two-year extension of the Stock Repurchase Program to March 31, 2010. As of December 31, 2009, we repurchased a total of 1,164,100 shares of common stock for approximately $8,538,000 under this program, at an average price of $7.33 per share. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. 
+F-17 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+16. Geographic Area Information 
+Information regarding our operations by geographic area is contained in the following table. These amounts in the geographic area table are based on the location of the customer. 
+Year Ended December 31, 
+(In thousands) 
+2009 
+2008 
+2007 
+Net sales: 
+United States 
+$ 
+45,890 
+$ 
+52,081 
+$ 
+37,971 
+International 
+12,456 
+10,126 
+10,795 
+Total 
+$ 
+58,346 
+$ 
+62,207 
+$ 
+48,766 
+Fixed assets, net: 
+United States 
+$ 
+3,395 
+$ 
+4,190 
+$ 
+4,941 
+International 
+1,156 
+1,373 
+1,397 
+Total 
+$ 
+4,551 
+$ 
+5,563 
+$ 
+6,338 
+Sales to international customers were 21%, 16%, and 22% in 2009, 2008, and 2007 respectively. Sales to Europe represented 45%, 56%, and 46%, sales to the Pacific Rim (which includes Australia and Asia) represented 31%, 21%, and 17%, and sales to Canada represented 11%, 8%, and 7% of total international sales in 2009, 2008, and 2007 respectively. International long-lived assets consist of net fixed assets located at our foreign subsidiary in the United Kingdom as well as our manufacturer in China. 
+17. Quarterly results of operations (unaudited) 
+Our quarterly results of operations for 2009 and 2008 are as follows: 
+Quarter Ended 
+(In thousands, except per share amounts) 
+March 31 
+June 30 
+September 30 
+December 31 
+2009: 
+Net sales 
+$ 
+12,202 
+$ 
+14,236 
+$ 
+17,982 
+$ 
+13,926 
+Gross profit 
+4,126 
+4,856 
+5,525 
+4,322 
+Net income 
+121 
+649 
+1,184 
+186 
+Net income per share: 
+Basic 
+0.01 
+0.07 
+0.13 
+0.02 
+Diluted 
+0.01 
+0.07 
+0.13 
+0.02 
+2008: 
+Net sales 
+$ 
+14,285 
+$ 
+16,319 
+$ 
+17,326 
+$ 
+14,277 
+Gross profit 
+4,779 
+5,460 
+5,894 
+4,817 
+Net income (loss) 
+(692 
+) 
+290 
+1,210 
+636 
+Net income (loss) per share: 
+Basic 
+(0.07 
+) 
+0.03 
+0.13 
+0.07 
+Diluted 
+(0.07 
+) 
+0.03 
+0.13 
+0.07 
+F-18 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+Schedule II 
+Valuation and Qualifying Accounts 
+(Amounts in thousands) 
+Description 
+Balance at Beginning of Period 
+Additions Charged to Costs and Expenses 
+Deductions 
+Balance at End of Period 
+Valuation account for accounts receivable: 
+Year ended December 31, 2009 
+$ 
+55 
+$ 
+3 
+$ 
+(1 
+) 
+$ 
+57 
+Year ended December 31, 2008 
+$ 
+62 
+$ 
+- 
+$ 
+(7 
+) 
+$ 
+55 
+Year ended December 31, 2007 
+$ 
+204 
+$ 
+- 
+$ 
+(142 
+) 
+$ 
+62 
+F-19 
+Table of Contents 
+Index to Exhibits 
+3.1(a) 
+Certificate of Incorporation of TransAct Technologies Incorporated (“TransAct” or the “Company”), filed with the Secretary of State of Delaware on June 17, 1996. 
+(2) 
+3.1(b) 
+Certificate of Amendment of Certificate of Incorporation of the Company, filed with the Secretary of State of Delaware on June 4, 1997. 
+(4) 
+3.1(c) 
+Certificate of Designation, Series A Preferred Stock, filed with the Secretary of State of Delaware on December 2, 1997. 
+(5) 
+3.1(d) 
+Certificate of Designation, Series B Preferred Stock, filed with the Secretary of State of Delaware on April 6, 2000. 
+(8) 
+3.2 
+Amended and Restated By-laws of the Company. 
+(6) 
+4.1 
+Specimen Common Stock Certificate. 
+(2) 
+10.1(x) 
+1996 Stock Plan, effective July 30, 1996. 
+(3) 
+10.2(x) 
+Non-Employee Directors’ Stock Plan, effective August 22, 1996. 
+(3) 
+10.3(x) 
+2001 Employee Stock Plan. 
+(10) 
+10.4(x) 
+2005 Equity Incentive Plan. 
+(15) 
+10.5(x) 
+Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. Shuldman. 
+(2) 
+10.6(x) 
+Severance Agreement by and between TransAct and Michael S. Kumpf, dated September 4, 1996. 
+(3) 
+10.7(x) 
+Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, 2004. 
+(14) 
+10.8(x) 
+Severance Agreement by and between TransAct and James B. Stetson, dated January 24, 2001. 
+(9) 
+10.9(x) 
+Severance Agreement by and between TransAct and Tracey S. Chernay, dated July 29, 2005. 
+(19) 
+10.10(x) 
+Amendment to Employment Agreement, effective January 1, 2008, by and between TransAct and Bart C. Shuldman. 
+(20) 
+10.11(x) 
+Amendment to Severance Agreement by and between TransAct and Michael S. Kumpf, effective January 1, 2008. 
+(20) 
+10.12(x) 
+Amendment to Severance Agreement by and between TransAct and Steven A. DeMartino, effective January 1, 2008. 
+(20) 
+10.13(x) 
+Amendment to Severance Agreement by and between TransAct and James B. Stetson, effective January 1, 2008. 
+(20) 
+10.14(x) 
+Amendment to Severance Agreement by and between TransAct and Tracey S. Chernay, effective January 1, 2008. 
+(20) 
+10.15 
+Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, 1992. 
+(2) 
+10.16 
+Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated December 2, 1996. 
+(4) 
+10.17 
+Agreement regarding the Continuation and Renewal of Lease by and between Bomax Properties, LLC and TransAct, dated July 18, 2001. 
+(12) 
+10.18 
+Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated December 2, 2004. 
+(14) 
+10.19 
+First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 
+(1) 
+10.20 
+Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated November 27, 2006. 
+(17) 
+10.21 
+OEM Purchase Agreement by and between GTECH Corporation, TransAct and Magnetec Corporation commencing July 14, 1999. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(7) 
+10.22 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct commencing July 2, 2002. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(11) 
+10.23 
+Amendment to OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated February 17, 2006. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(16) 
+10.24 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated November 20, 2009. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy) 
+(1) 
+10.25 
+Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. dated November 28, 2006 
+(17) 
+Table of Contents 
+10.26 
+First Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. effective September 30, 2007. 
+(18) 
+10.27 
+License Agreement between Seiko Epson Corporation and TransAct dated May 17, 2004 (Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(13) 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+(1) 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+(1) 
+These exhibits are filed herewith. 
+(2) 
+These exhibits, which were previously filed with the Company’s Registration Statement on Form S-1 (No. 333-06895), are incorporated by reference. 
+(3) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1996, are incorporated by reference. 
+(4) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1997, are incorporated by reference. 
+(5) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed February 18, 1999, is incorporated by reference. 
+(6) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1998, is incorporated by reference. 
+(7) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 25, 1999, is incorporated by reference. 
+(8) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended March 25, 2000, are incorporated by reference. 
+(9) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2000, is incorporated by reference. 
+(10) 
+This exhibit, which was previously filed with the Company’s Registration Statement on Form S-8 (No. 333-59570), is incorporated by reference. 
+(11) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002, is incorporated by reference. 
+(12) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003, is incorporated by reference. 
+(13) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004, is incorporated by reference. 
+(14) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, are incorporated by reference. 
+(15) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed June 1, 2005, is incorporated by reference. 
+(16) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, is incorporated by reference. 
+(17) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, are incorporated by reference. 
+(18) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1997, is incorporated by reference. 
+(19) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, is incorporated by reference. 
+Table of Contents 
+(20) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, is incorporated by reference. 
+(x) 
+Management contract or compensatory plan or arrangement. 
+Table of Contents 
+EXHIBIT LIST 
+The following exhibits are filed herewith. 
+Exhibit 
+10.19 
+First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 
+10.24 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated November 20, 2009. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy) 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2009/0001017303-10-000006/filing_metadata.csv b/raw/filings/0001017303/2009/0001017303-10-000006/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..820c36ceaae65150d40742604afdde9059aea958
--- /dev/null
+++ b/raw/filings/0001017303/2009/0001017303-10-000006/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
+0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2010-03-16,2009-12-31,2010-03-16T20:26:24.000Z,0001017303-10-000006,form10-k.htm,FORM 10-K,2213570,0,0,https://www.sec.gov/Archives/edgar/data/1017303/000101730310000006/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730310000006/,2009,2009,1
diff --git a/raw/filings/0001017303/2009/0001017303-10-000006/item1.txt b/raw/filings/0001017303/2009/0001017303-10-000006/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..182cd81a7223a0545688719428967d4bb2eb1bf4
--- /dev/null
+++ b/raw/filings/0001017303/2009/0001017303-10-000006/item1.txt
@@ -0,0 +1,82 @@
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops, assembles, markets and services world-class transaction printers under the Epic and Ithaca® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers generate top-quality transaction records such as receipts, tickets, coupons, register journals and other documents. We focus on the following core markets: banking and point-of-sale (“POS”), casino and gaming, and lottery. We sell our products to original equipment manufacturers ("OEMs"), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. Beyond printers, TransAct provides printing supplies to the full transaction printer market. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables items used in the printing and scanning activities of customers in the hospitality, banking, retail, gaming, and government markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating facility and eastern region service center located in Ithaca, NY, our printer sales headquarters and western region service center in Las Vegas, NV, a printhead manufacturing and repair center located in New Britain, CT, a European sales and service center in the United Kingdom, a sales office located in Macau and two other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518, with a telephone number of (203) 859-6800. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction printers and printer-related service, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers 
+TransAct designs, develops, assembles and markets a broad array of transaction-based printers utilizing inkjet, thermal and impact printing technology for applications requiring up to 60 character columns, primarily in the banking, POS, casino, gaming and lottery markets. Our printers are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Banking and POS: Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We us an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of a dedicated internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals, with an approximate 70% market share. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals that print tickets or receipts instead of issuing coins at casinos, racetracks and other gaming establishments worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that will allow casinos to print coupons/promotions. In addition, we sell printers using thermal and impact printing technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through three regional distributors (one in the United States and Asia, one in Europe and Africa, and one in Australia). We also maintain a dedicated sales force to solicit sales from slot manufacturers and casinos, as well as manage sales through our distributors. 
+1 
+Table of Contents 
+TSG 
+Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper and other transaction supplies), replacement parts and maintenance services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. During 2009, we completed a program to transfer final assembly for approximately 70% of our total printer production to a third-party contract manufacturer in China. We continue to perform final assembly for the remaining 30% of our products in our Ithaca, NY facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY. Critical component parts and subassemblies include inkjet, thermal and impact printheads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of transitioning 70% of our production to our contract manufacturer, 2009 purchases of component parts declined, while purchases of fully-assembled printers increased, due to the decline of in-house printer assembly in Ithaca, NY and the increase of assembly by our contract manufacturer. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturer, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2010 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. The loss of the supply of HP inkjet cartridges would have a material adverse effect on both the sale of our inkjet printers and TSG consumable products. Our relationship with HP remains strong and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be any less favorable than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+Okidata Americas, Inc. (“Okidata”) is the sole supplier for an impact printer component kit consisting of a printhead, control board and carriage (the “Oki Kit”) that is used in all of our Ithaca â brand impact printers. The loss of the supply of Oki Kits would have a material adverse effect on us. However, sales of impact printers continue to decline as sales of these printers are replaced by sales of thermal and inkjet printers. As such, we believe that any possible loss of supply of Oki Kits will continue to have less of an impact on us in 2010 and beyond. Although we do not have a supply agreement with Okidata, our relationship with Okidata remains strong and we have no reason to believe that Okidata will discontinue its supply of Oki Kits to us during 2010 or that their terms to us will be any less favorable than they have been historically. 
+Patents and Proprietary Information 
+We have significantly expanded our patent portfolio since 2002, and expect to continue to do so in the future. We also believe our patent portfolio could provide additional opportunities to license our intellectual property in the future. We hold 24 United States and 27 foreign patents and have 9 United States and 54 foreign patent applications pending pertaining to our products. The duration of these patents range from 8 to 16 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain 
+manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise 
+2 
+Table of Contents 
+obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+Seasonality 
+Retailers typically reduce purchases of new POS equipment in the fourth quarter due to the increased volume of consumer transactions in that holiday period, and our sales of printers in the POS market historically have increased in the third quarter and decreased in the fourth quarter. Similarly, installations of lottery terminals are typically reduced in the fourth quarter, resulting in decreased sales of lottery printers. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH is our most significant customer. We currently have an ongoing OEM purchase agreement, as amended in February 2006 (the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of thermal on-line lottery printers and spare parts, at fixed prices, through June 28, 2012. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH New Thermal Printer Agreement”). Under the terms of the new agreement, we will provide GTECH with their next generation thermal lottery printers for various lottery applications. The terms of the new agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH. The exclusivity period will extend for four years from the start of production of the new printer, which is expected to commence in the fall of 2010. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2009 
+2008 
+2007 
+GTECH 
+19 
+% 
+28 
+% 
+14 
+% 
+Customer A 
+10 
+% 
+* 
+10 
+% 
+Customer B 
+12 
+% 
+* 
+* 
+* Customers represented less than 10% of total net sales 
+Backlog 
+Our backlog of firm orders was approximately $6,976,000 as of February 26, 2010, compared to $9,994,000 as of February 28, 2009. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2010. 
+Competition 
+The market for transaction-based printers is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group, Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreements with GTECH, which holds approximately 70% market share of the worldwide on-line lottery market. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+3 
+Table of Contents 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including internet resellers, depending on the geographic area. 
+Our strategy for competing in our markets is to continue to develop new products and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $2,788,000, $2,942,000 and $3,129,000 in 2009, 2008 and 2007, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new products and to customize or improve existing products. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of February 26, 2010, TransAct and our subsidiaries employed 143 persons, of whom 140 were full-time and 3 were temporary employees. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 16 – Geographic Area Information in the Notes to the Consolidated Financial Statements. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. You may read and copy any materials filed with the Securities and Exchange Commission at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the Securities and Exchange Commission at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2009/0001017303-10-000006/item13.txt b/raw/filings/0001017303/2009/0001017303-10-000006/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..04c167e20adc5eb1e001215326abd59fdd7e4809
--- /dev/null
+++ b/raw/filings/0001017303/2009/0001017303-10-000006/item13.txt
@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Certain Relationships and Related Transactions.”
\ No newline at end of file
diff --git a/raw/filings/0001017303/2009/0001017303-10-000006/item9a.txt b/raw/filings/0001017303/2009/0001017303-10-000006/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..add35c38a802e68e3d6ce1942a626a242b50cbdc
--- /dev/null
+++ b/raw/filings/0001017303/2009/0001017303-10-000006/item9a.txt
@@ -0,0 +1,9 @@
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. Part II, Item 8 of this Form 10-K sets forth the report of PricewaterhouseCoopers LLP, our independent registered public accounting firm, regarding its audit of TransAct’s internal control over financial reporting as of December 31, 2009. This section should be read in conjunction with the CEO and CFO certifications and the PricewaterhouseCoopers LLP report for a more complete understanding of the topics presented. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2009, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2009. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2009. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 
+Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2009. 
+The effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2009/0001017303-10-000006/rp_note.txt b/raw/filings/0001017303/2009/0001017303-10-000006/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2009/0001017303-10-000006/rpt_disclosure.txt b/raw/filings/0001017303/2009/0001017303-10-000006/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..2333719d972d08351a9104419c5fb0d314c66b86
--- /dev/null
+++ b/raw/filings/0001017303/2009/0001017303-10-000006/rpt_disclosure.txt
@@ -0,0 +1,4 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+The Company maintains policies that relate to the identification, review and approval of related party transactions. As part of a review of possible related person transactions, the Company annually distributes and collects questionnaires that solicit information about any direct or indirect transactions with the Company from each of our directors and officers. 
+Our Standards of Business Conduct require all directors, officers and employees to avoid any situation that involves an actual or apparent conflict of interest in personal and professional relationships or with their duty to, or with any interest of, the Company. Under the Standards of Business Conduct, situations that involve, or may reasonably be inferred to involve, a conflict between a director, officer or employee’s personal interests and the interests of the Company should be disclosed to the Chair of the Audit Committee. The Audit Committee is then responsible for reviewing the related party transaction. No related party transaction shall be approved or ratified if such transaction is contrary to the best interests of the Company. In determining whether to approve or ratify a related party transaction, the Audit Committee takes into account such factors as it deems appropriate, which may include whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the related person’s interest in the transaction. 
+From January 1, 2009 to the date of this proxy statement, there have not been any transactions subject to the Company’s related party transaction policy or of the type described in Item 404 of Regulation S-K, and currently no such transactions are proposed.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/filing.txt b/raw/filings/0001017303/2010/0001017303-11-000006/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..b846b8810bb6ae4902e8240ea7a52ea6057ac377
--- /dev/null
+++ b/raw/filings/0001017303/2010/0001017303-11-000006/filing.txt
@@ -0,0 +1,3434 @@
+10-K
+1
+form10k.htm
+FORM 10-K
+form10k.htm 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2010 
+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: 0-21121 
+______________________________________________________________________ 
+___________________________________ ___________________________________ 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+06-1456680 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT 
+06518 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code 203-859-6800 
+______________________________________________________________________ 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Exchange on which Registered 
+Common Stock, par value $.01 per share 
+NASDAQ Global 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 o 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 o 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 o 
+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 (§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  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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer  
+Accelerated filer  
+Non-accelerated filer  (Do not check if a smaller reporting company) 
+Smaller reporting company ý 
+Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý 
+The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the Registrant was approximately $64,400,000 based on the last sale price on June 30, 2010. 
+As of February 28, 2011, the registrant had outstanding 9,442,043 shares of common stock, $0.01 par value. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the TransAct Technologies Incorporated Proxy Statement to be filed with the Securities and Exchange Commission (SEC) within 120 days after the year covered by this Form 10-K with respect to the 2011 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX 
+PART I. 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+4 
+Item 1B. 
+Unresolved Staff Comments 
+9 
+Item 2. 
+Properties 
+9 
+Item 3. 
+Legal Proceedings 
+9 
+Item 4. 
+(Removed and Reserved) 
+9 
+PART II. 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+9 
+Item 6. 
+Selected Financial Data 
+11 
+Item 7. 
+Management's Discussion and Analysis of Financial Condition and Results of Operations 
+12 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+24 
+Item 8. 
+Financial Statements and Supplementary Data 
+24 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+24 
+Item 9A. 
+Controls and Procedures 
+25 
+Item 9B. 
+Other Information 
+25 
+PART III. 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+25 
+Item 11. 
+Executive Compensation 
+26 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+26 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+27 
+Item 14. 
+Principal Accountant Fees and Services 
+27 
+PART IV. 
+Item 15. 
+Exhibits 
+27 
+SIGNATURES 
+Signatures 
+28 
+CONSOLIDATED FINANCIAL STATEMENTS 
+Index to Consolidated Financial Statements 
+F-1 
+EXHIBITS 
+Index to Exhibits 
+Table of Contents 
+PART I 
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops, assembles, markets and services world-class transaction-based printers under the Epic and Ithaca® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers generate top-quality transaction records such as receipts, tickets, coupons, register journals and other documents. We focus on the following core markets: banking and point-of-sale (“POS”), casino and gaming, and lottery. We sell our products to original equipment manufacturers ("OEMs"), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, Latin America, the Caribbean Islands and the South Pacific. Beyond printers, TransAct is a leader in providing printing supplies to the full transaction printer market. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the hospitality, banking, retail, gaming, and government markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating facility and eastern region service center located in Ithaca, NY, our printer sales headquarters and western region service center in Las Vegas, NV, a printhead manufacturing and repair center located in New Britain, CT, a European sales and service center in the United Kingdom, a sales office located in Macau and two other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518, with a telephone number of (203) 859-6800. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction-based printers and printer-related service, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers 
+TransAct designs, develops, assembles and markets a broad array of transaction-based printers utilizing inkjet, thermal and impact printing technology for applications requiring up to 60 character columns, primarily in the banking, POS, casino, gaming and lottery markets. Our printers are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Banking and POS: Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of our internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals that print tickets or receipts instead of issuing coins at casinos, racetracks and other gaming establishments worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that allows casinos to print coupons and promotions. In addition, we sell printers using thermal and impact printing technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through regional distributors (four in the United States and Asia, one in Europe and Africa, two in Latin America and one in Australia). We also maintain a dedicated internal sales force to solicit sales from slot manufacturers and casinos, as well as to manage sales through our distributors. 
+1 
+Table of Contents 
+TSG 
+Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper and other transaction supplies), replacement parts and maintenance services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. During 2009, we completed a program to transfer final assembly for approximately 70% of our total printer production to a third-party contract manufacturer in China. We continue to perform final assembly for the remaining 30% of our products in our Ithaca, NY facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY. Critical component parts and subassemblies include inkjet, thermal and impact printheads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturer, purchases of component parts have declined while purchases of fully-assembled printers produced by our contract manufacturer have increased. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturer, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2011 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges that are compatible with the HP inkjet cartridge are available, the loss of the supply of HP inkjet cartridges could have a material adverse effect on both the sale of our inkjet printers and TSG consumable products. Our relationship with HP remains strong and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be any less favorable than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+Patents and Proprietary Information 
+We have significantly expanded our patent portfolio since 2002, and expect to continue to do so in the future. We also believe our patent portfolio could provide additional opportunities to license our intellectual property in the future. We hold 25 United States and 26 foreign patents and have 14 United States and 28 foreign patent applications pending pertaining to our products. The duration of these patents range from 7 to 15 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain 
+manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+2 
+Table of Contents 
+Seasonality 
+Retailers typically reduce purchases of new POS equipment in the fourth quarter due to the increased volume of consumer transactions in that holiday period, and our sales of printers in the POS market historically have increased in the third quarter and decreased in the fourth quarter. Similarly, installations of lottery terminals are typically reduced in the fourth quarter, resulting in decreased sales of lottery printers. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH is our most significant customer. We currently have an ongoing OEM purchase agreement, as amended in February 2006 (the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of thermal on-line lottery printers and spare parts, at fixed prices, through June 28, 2012. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH New Thermal Printer Agreement”). Under the terms of the new agreement, we will provide GTECH with their next generation thermal lottery printers for various lottery applications. The terms of the new agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH. The exclusivity period will extend for four years from the start of production of the new printer, which began in January 2011. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2010 
+2009 
+2008 
+GTECH 
+12 
+% 
+19 
+% 
+28 
+% 
+Customer A 
+14 
+% 
+10 
+% 
+* 
+Customer B 
+* 
+12 
+% 
+* 
+* Customers represented less than 10% of total net sales 
+Backlog 
+Our backlog of firm orders was approximately $12,764,000 as of February 28, 2011, compared to $6,976,000 as of February 26, 2010. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2011. 
+Competition 
+The market for transaction-based printers is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group, Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreements with GTECH. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including internet resellers, depending on the geographic area. 
+3 
+Table of Contents 
+Our strategy for competing in our markets is to continue to develop new products and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $3,000,000, $2,788,000 and $2,942,000 in 2010, 2009 and 2008, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new products and to customize or improve existing products. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established for the product. Once technological feasibility is established, all material software costs are capitalized within Intangible and other assets in our consolidated balance sheet until the product is available for general release to customers. Judgment is required in determining when technological feasibility of a product is established. We have determined that technological feasibility for our software products is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of revenue over the estimated life of the product. During 2010 we began the development of a new software product that enables casino customers to print coupons and promotions at the slot machine. As of December 31, 2010, we have capitalized $130,000 of developments costs for such software; there has been no amortization of capitalized software development costs. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of February 28, 2011, TransAct and our subsidiaries employed 124 persons, of whom 123 were full-time and one was a temporary employee. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 16 – Geographic Area Information in the Notes to the Consolidated Financial Statements. Risks attendant to our foreign operations are described in Item 1A below. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. You may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800. 
+Item 1A. Risk Factors 
+Investors should carefully consider the risks, uncertainties and other factors described below, as well as other disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, because they could have a material adverse effect on our business, financial condition, operating results, and growth prospects. The risks described below are not the only ones facing our Company. Additional risks not known to us now or that we currently deem immaterial may also impair our business operations. 
+We assume no obligation (and specifically disclaim any such obligation) to update these Risk Factors or any other forward-looking statements contained in this Annual Report to reflect actual results, changes in assumptions or other factors affecting such forward-looking statements, except as required by law. 
+4 
+Table of Contents 
+Our operating results and financial condition may fluctuate. 
+Our operating results and financial condition may fluctuate from quarter to quarter and year to year and are likely to continue to vary due to a number of factors, many of which are not within our control. If our operating results do not meet the expectations of securities analysts or investors, who may derive their expectations by extrapolating data from recent historical operating results, the market price of our common stock will likely decline. Fluctuations in our operating results and financial condition may be due to a number of factors, including, but not limited to, those identified throughout this “Risk Factors” section: 
+· 
+market acceptance of our products, both domestically and internationally; 
+· 
+development of new competitive printers by others; 
+· 
+our responses to price competition; 
+· 
+our level of research and development activities; 
+· 
+changes in the amount that we spend to develop, acquire or license new products, consumables, technologies or businesses; 
+· 
+changes in the amount we spend to promote our products and services; 
+· 
+changes in the cost of satisfying our warranty obligations and servicing our installed base of printers; 
+· 
+delays between our expenditures to develop and market new or enhanced printers and consumables and the generation of sales from those products; 
+· 
+the geographic distribution of our sales; 
+· 
+availability of third-party components at reasonable prices; 
+· 
+general economic and industry conditions, including changes in interest rates affecting returns on cash balances and investments, that affect customer demand; 
+· 
+severe weather events (such as hurricanes) that can disrupt or interrupt the operation of our customers or suppliers facilities; and 
+· 
+changes in accounting rules. 
+Due to all of the foregoing factors, and the other risks discussed in this report, quarter-to-quarter comparisons of our operating results may not be an indicator of future performance. 
+We rely on resellers to sell our products and services. 
+We use a variety of distribution channels, including OEMs and distributors, to market our products. We may be adversely impacted by any conflicts that could arise between and among our various sales channels. 
+Our dependence upon resellers exposes us to numerous risks, including: 
+· 
+loss of channel and the ability to bring new products to market; 
+· 
+concentration of credit risk, including disruption in distribution should the resellers’ financial condition deteriorate; 
+· 
+reduced visibility to end user demand and pricing issues which makes forecasting more difficult; 
+· 
+resellers leveraging their buying power to change the terms of pricing, payment and product delivery schedules; and 
+· 
+direct competition should a reseller decide to manufacture printers internally or source printers from a competitor. 
+We cannot guarantee that resellers will not reduce, delay or eliminate purchases from us, which could have a material adverse effect upon the business, consolidated results of operations and financial condition. 
+General economic conditions and the related deterioration in the global business environment could have a material adverse effect on our business, operating results and financial condition. 
+Global consumer confidence has eroded amidst concerns over, among other things, declining asset values, inflation, volatility in energy costs, geopolitical issues, the availability and cost of credit, rising unemployment, and the stability and solvency of financial institutions, financial markets, businesses and sovereign nations. These concerns have slowed global economic growth and have resulted in recessions in numerous countries, including many of those in North America, Europe and Asia, where the Company does substantially all of its business. As these economic conditions continue to persist, or if they worsen, a number of negative effects on our business could result, including customers or potential customers reducing or delaying orders, the insolvency of key suppliers which could result in production delays, the inability of customers to obtain credit, and the insolvency of one or more customers. Any of these effects could impact our ability to effectively manage inventory levels and collect receivables, create unabsorbed costs due to lower net sales, and ultimately decrease our net sales and profitability including write-downs of assets. 
+In the lottery market, we have been dependent on sales to one large customer; the loss of this customer or reduction in orders from this customer could materially affect our sales. 
+We expect that sales to one large customer will continue to represent a significant percentage of our net sales for the foreseeable future. A reduction, delay or cancellation in orders from this customer, including reductions or delays due to market, economic, or competitive conditions in the industries in which we serve, could have a material adverse effect upon our results of operations. 
+5 
+Table of Contents 
+Our success will depend on our ability to sustain and manage growth. 
+As part of our business strategy, we intend to pursue a growth strategy. Assuming this growth occurs, it will require the expansion of distribution relationships in international markets, the successful development and marketing of new products for our existing and new markets, expanded customer service and support, and the continued implementation and improvement of our operational, financial and management information systems. 
+To the extent that we seek growth through acquisitions, our ability to manage our growth will also depend on our ability to integrate businesses that have previously operated independently. We may not be able to achieve this integration without encountering difficulties or experiencing the loss of key employees, customers or suppliers. It may be difficult to design and implement effective financial controls for combined operations and differences in existing controls for each business may result in weaknesses that require remediation when the financial controls and reporting functions are combined. As we pursue acquisitions, we may incur legal, accounting and other transaction related expenses for unsuccessful acquisition attempts that could adversely affect our results of operations in the period in which they are incurred. 
+There can be no assurance that we will be able to successfully implement our growth strategy, or that we can successfully manage expanded operations. As the Company expands, we may from time to time experience constraints that will adversely affect our ability to satisfy customer demand in a timely fashion. Failure to manage growth effectively could adversely affect our results of operations and financial condition. 
+We compete in highly competitive markets, which are likely to become more competitive. Competitors may be able to respond more quickly to new or emerging technology and changes in customer requirements. 
+We face significant competition in developing and selling our printers, transaction supplies and services. Principal competitors have substantial marketing, financial, development and personnel resources. To remain competitive, we believe we must continue to provide: 
+· 
+Technologically advanced printers that satisfy the user demands, 
+· 
+Superior customer service, 
+· 
+High levels of quality and reliability, and 
+· 
+Dependable and efficient distribution networks. 
+We cannot ensure we will be able to compete successfully against current or future competitors. Increased competition in printers or supplies may result in price reductions, lower gross profit margins and loss of market share, and could require increased spending on research and development, sales and marketing and customer support. Some competitors may make strategic acquisitions or establish cooperative relationships with suppliers or companies that produce complementary products. Any of these factors could reduce our earnings. 
+We have outsourced a large portion of the assembly of our printers to a contract manufacturer and will be dependent on them for the manufacturing of such printers. A failure by this contract manufacturer, or any disruption in such manufacturing, may adversely affect our business results. 
+In an effort to achieve additional cost savings and operation benefits, we have continued to outsource the manufacturing and assembly of our printers to a contract manufacturer in China. 
+However, to the extent we rely on a third-party service provider for manufacturing services, we may incur increased business continuity risks. We will no longer be able to exercise control over the assembly of certain of our printers or any related operations or processes, including the internal controls associated with operations and processes conducted and the quality of our products assembled by the contract manufacturer. If we are unable to effectively develop and implement our outsourcing strategy, we may not realize cost structure efficiencies and our operating and financial results could be materially adversely affected. 
+In addition, if the contract manufacturer experiences business difficulties or fails to meet our manufacturing needs, then we may be unable to meet production requirements, may lose revenue and may not be able to maintain relationships with our customers. Without the contract 
+manufacturer continuing to manufacture our products and the continuing operation of the contract manufacturer’s facility, we will have limited means for the final assembly of a majority of our printers until we are able to secure the manufacturing capability at another facility or develop an alternative manufacturing facility, which could be costly and time consuming and have a material adverse effect on our operating and financial results. 
+The increased elements of risk that arise from conducting certain operating processes in foreign jurisdictions may lead to an increase in reputational risk. 
+Although we carry business interruption insurance to cover lost revenue and profits in an amount we consider adequate, this insurance does not cover all possible situations. In addition, the business interruption insurance would not compensate us for the loss of opportunity and potential adverse impact, both short-term and long-term, on relations with our existing customers resulting from our inability to produce products for them. 
+6 
+Table of Contents 
+The contract manufacturer has access to our intellectual property, which increases the risk of infringement or misappropriation of this intellectual property. 
+We source some of our component parts and consumable products from sole source suppliers; any disruptions may impact our ability to manufacture and sell our products. 
+A disruption in the supply of such component parts and consumable products could have a material adverse effect on our operations and financial results. 
+We sell a significant portion of our products internationally and purchase important components from foreign suppliers. These circumstances create a number of risks. 
+We sell a significant amount of our products to customers outside the United States. Shipments to international customers are expected to continue to account for a material portion of net sales. Risks associated with sales and purchases outside the United States include: 
+· 
+Fluctuating foreign currency rates could restrict sales, or increase costs of purchasing, in foreign countries. 
+· 
+Foreign governments may impose burdensome tariffs, quotas, taxes, trade barriers or capital flow restrictions. 
+· 
+Political and economic instability may reduce demand for our products or put our foreign assets at risk. 
+· 
+Restrictions on the export or import of technology may reduce or eliminate the ability to sell in or purchase from certain markets. 
+· 
+Potentially limited intellectual property protection in certain countries, such as China, may limit recourse against infringing products or cause us to refrain from selling in certain geographic territories. 
+We face risks associated with manufacturing forecasts. 
+If we fail to predict our manufacturing requirements accurately, we could incur additional costs or experience manufacturing delays, which could cause us to lose orders or customers and result in lower net sales. We currently use a rolling 12-month forecast based primarily on our anticipated product orders and our product order history to help determine our requirements for components and materials. It is very important that we accurately predict both the demand for our products and the lead-time required to obtain the necessary components and raw materials. Lead times for materials and components that we order vary significantly and depend on factors such as the specific supplier, the size of the order, contract terms, and demand for each component at a given time. If we underestimate our requirements, we may have inadequate manufacturing capacity or inventory, which could interrupt manufacturing of our products and result in delays in shipments and net sales. If we overestimate our requirements, we could have excess inventory of parts. In addition, delays in the manufacturing of our products could cause us to lose orders or customers. 
+Our revenue and profitability depend on our ability to continue to develop, on a timely basis, new technologies which are free from hardware or software anomalies and cannot be fraudulently manipulated: 
+The success of a newly introduced technology, such as printing coupons and promotions at the slot machine using our EPICENTRAL™ Print System, is dependent on our casino customers' acceptance of such technology. While we have designed our EPICENTRAL™ Print System to support our customers' existing investment in our Epic 950® thermal casino printers, such acceptance may nevertheless only build gradually over time or not at all. Delays in acceptance by our customers of new technologies may adversely affect our operations. 
+Our success depends upon our ability to adapt our capabilities and processes to meet the demands of producing new and innovative products. Because our newer products are generally more technologically sophisticated than those we have produced in the past, we must continually refine our capabilities to meet the needs of our product innovation. If we cannot efficiently adapt our infrastructure to meet the needs of our product innovations in a timely manner, our business could be negatively impacted. 
+We depend on key personnel, the loss of which could materially impact our business. 
+Our future success will depend in significant part upon the continued service of certain key management and other personnel and our continuing ability to attract and retain highly qualified managerial, technical and sales and marketing personnel. There can be no assurance that we will be able to recruit and retain such personnel. The loss of either Bart C. Shuldman, the Company's Chairman of the Board and Chief Executive Officer, or Steven A. DeMartino, the Company’s President, Chief Financial Officer, Treasurer and Secretary, or the loss of certain groups of key employees, could have a material adverse effect on our results of operations. 
+If we are unable to enforce our patents or if it is determined that we infringe patents held by others it could damage our business. Prosecuting and defending patent lawsuits is very expensive. We are committed to aggressively asserting and defending our technology and related intellectual property, which we have spent a significant amount of money to develop. These factors could cause us to become involved in new patent litigation in the future. The expense of prosecuting or defending these future lawsuits could also have a material adverse effect on our business, financial condition and results of operations. 
+If we were to lose a patent lawsuit in which another party is asserting that our products infringe its patents, we would likely be prohibited from marketing those products and could also be liable for significant damages. Either or both of these results may have a material adverse effect on our business, financial condition and results of operations. If we lose a patent lawsuit in which we are claiming that another party’s products are 
+7 
+Table of Contents 
+infringing our patents and thus, are unable to enforce our patents, it may have a material adverse effect on our business, financial condition and results of operations. In addition to disputes relating to the validity or alleged infringement of other parties' rights, we may become involved in disputes relating to our assertion of our own intellectual property rights. Whether we are defending the assertion of intellectual property rights against us or asserting our intellectual property rights against others, intellectual property litigation can be complex, costly, protracted, and highly disruptive to business operations by diverting the attention and energies of management and key technical personnel. Plaintiffs in intellectual property cases often seek injunctive relief, and the measures of damages in intellectual property litigation are complex and often subjective or uncertain. Thus, any adverse determinations in this type of litigation could subject us to significant liabilities and costs. During the course of these lawsuits there may be public announcements of the results of hearings, motions, and other interim proceedings or developments in the litigation. If securities analysts or investors perceive these results to be negative, it could harm the market price of our stock. 
+The inability to protect intellectual property could harm our reputation, and our competitive position may be materially damaged. 
+Our intellectual property is valuable and provides us with certain competitive advantages. Copyrights, patents, trade secrets and contracts are used to protect these proprietary rights. Despite these precautions, it may be possible for third parties to copy aspects of our products or, without authorization, to obtain and use information which we regard as trade secrets. 
+Infringement on the proprietary rights of others could put us at a competitive disadvantage, and any related litigation could be time consuming and costly. 
+Third parties may claim that we violated their intellectual property rights. To the extent of a violation of a third party’s patent or other intellectual property right, we may be prevented from operating our business as planned and may be required to pay damages, to obtain a license, if available, or to use a non-infringing method, if possible, to accomplish our objectives. Any of these claims, with or without merit, could result in costly litigation and divert the attention of key personnel. If such claims are successful, they could result in costly judgments or settlements. 
+Our stock price may fluctuate significantly. 
+The market price of our common stock could fluctuate significantly in response to variations in quarterly operating results and other factors, such as: 
+· 
+changes in our business, operations or prospects; 
+· 
+developments in our relationships with our customers; 
+· 
+announcements of new products or services by us or by our competitors; 
+· 
+announcement or completion of acquisitions by us or by our competitors; 
+· 
+changes in existing or adoption of additional government regulations; 
+· 
+unfavorable or reduced analyst coverage; and 
+· 
+prevailing domestic and international market and economic conditions. 
+In addition, the stock market has experienced significant price fluctuations in recent years. Broad market fluctuations, general economic conditions and specific conditions in the industries in which we operate may adversely affect the market price of our common stock. 
+Limited trading volume of our capital stock may contribute to its price volatility. 
+Our common stock is traded on the NASDAQ Global Market. During the year ended December 31, 2010, the average daily trading volume for our common stock as reported by the NASDAQ Global Market was approximately 19,000 shares. We are uncertain whether a more active trading market in our common stock will develop. In addition, many investment banks no longer find it profitable to provide securities research on micro-cap and small-cap companies. If any analyst were to discontinue coverage of our common stock, our trading volume may be further reduced. As a result, relatively small trades may have a significant impact on the market price of our common stock, which could increase the volatility and depress the price of our common stock. 
+Future sales of our common stock may cause our stock price to decline. 
+In the future, we may sell additional shares of our common stock in public or private offerings, and we may also issue additional shares of our common stock to finance future acquisitions. Shares of our common stock are also available for future sale pursuant to stock options that we have granted to our employees, and in the future we may grant additional stock options and other forms of equity compensation to our employees. Sales of our common stock or the perception that such sales could occur may adversely affect prevailing market prices for shares of our common stock and could impair our ability to raise capital through future offerings. 
+If market conditions deteriorate or future results of operations are less than expected, a valuation allowance may be required for all or a portion of our deferred tax assets. 
+We currently have significant deferred tax assets, which may be used to reduce taxable income in the future. We assess the realization of these deferred tax assets on a quarterly basis, and if we determine that it is more likely than not that some portion of these assets will not be realized, 
+8 
+Table of Contents 
+an income tax valuation allowance is recorded. If market conditions deteriorate or future results of operations are less than expected, or there is a change to applicable tax rules, future assessments may result in a determination that it is more likely than not that some or all of our net deferred tax assets are not realizable. As a result, we may need to establish a valuation allowance for all or a portion of our net deferred tax assets, which may have a material adverse effect on our business, results of operations and financial condition. 
+We cannot provide any assurance that current laws, or any laws enacted in the future, will not have a material adverse effect on our business. 
+Our operations are subject to laws, rules, regulations, including environmental regulations, government policies and other requirements in each of the jurisdictions in which we conduct business. Changes in laws, rules, regulations, policies or requirements could result in the need to modify our products and could affect the demand for our products, which may have an adverse impact on our future operating results. If we do not comply with applicable laws, rules and regulations we could be subject to costs and liabilities and our business may be adversely impacted. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. It is possible that terrorist attacks could be directed at important locations for the gaming industry. Heightened security measures and other efforts to combat terrorism may also have an adverse effect on the gaming industry by reducing tourism. Any of these developments could also negatively affect the general economy and consumer confidence. Any downturn in the economy or in the gaming industry in particular could reduce demand for our products and adversely affect our business and results of operations. In addition, heightened security measures may cause certain governments to restrict the import/export of goods, which may have an adverse effect on our ability to buy/sell goods. 
+Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial also may adversely impact our business. Should any risks or uncertainties develop into actual events, these developments could have material adverse effects on our business, financial condition, and results of operations. 
+Item 1B. Unresolved Staff Comments. 
+Not applicable. 
+Item 2. Properties. 
+Our corporate headquarters is currently located in Hamden, CT. Our global engineering, assembly and eastern region service facility is located in Ithaca, NY. We also maintain a facility in Las Vegas, NV that serves as our global printer sales headquarters and western region service center. In addition, we maintain an impact printhead manufacturing and repair facility in New Britain, CT. We believe that our facilities generally are in good condition, adequately maintained and suitable for their present and currently contemplated uses. 
+Our principal facilities as of December 31, 2010 are listed below: 
+Location 
+Operations Conducted 
+Size 
+(Approx. Sq. Ft.) 
+Owned or 
+Leased 
+Lease Expiration 
+Date 
+Hamden, Connecticut 
+Executive offices and TSG sales office 
+11,100 
+Leased 
+April 23, 2017 
+Ithaca, New York 
+Research, design, assembly and service facility 
+73,900 
+Leased 
+June 30, 2012 
+Las Vegas, Nevada 
+Service center and printer sales headquarters 
+13,700 
+Leased 
+December 31, 2016 
+New Britain, Connecticut 
+Printhead manufacturing and repair facility 
+11,500 
+Leased 
+April 1, 2012 
+Doncaster, United Kingdom 
+Sales office and service center 
+2,800 
+Leased 
+August 1, 2016 
+Georgia and New York 
+Two regional sales offices 
+300 
+Leased 
+Various 
+Macau, China 
+Sales office 
+180 
+Leased 
+June 30, 2011 
+113,480 
+Item 3. Legal Proceedings. 
+None. 
+Item 4. (Removed and Reserved). 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+9 
+Table of Contents 
+Our common stock is traded on the NASDAQ Global Market under the symbol TACT. As of February 28, 2011, there were 481 holders of record of the common stock. The high and low sales prices of the common stock reported during each quarter of the years ended December 31, 2010 and 2009 were as follows: 
+Year Ended 
+Year Ended 
+December 31, 2010 
+December 31, 2009 
+High 
+Low 
+High 
+Low 
+First Quarter 
+$ 
+7.83 
+$ 
+6.25 
+$ 
+4.74 
+$ 
+1.60 
+Second Quarter 
+7.90 
+6.88 
+5.96 
+2.35 
+Third Quarter 
+8.16 
+6.83 
+5.96 
+3.80 
+Fourth Quarter 
+9.75 
+7.50 
+6.94 
+4.75 
+No dividends on common stock have been declared and we do not anticipate declaring dividends in the foreseeable future. Our credit agreement with TD Bank prohibits the payment of cash dividends on our common stock for the term of the agreement. 
+Issuer Purchases of Equity Securities 
+On May 27, 2010, our Board of Directors approved a new stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we are authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending May 27, 2013, depending on market conditions, share price and other factors. 
+During the fourth quarter of 2010, we made no repurchases of common stock. As of December 31, 2010, we have repurchased a total of 22,338 shares of common stock for approximately $177,000 , at an average price of $7.95 per share, under the Stock Repurchase Program. 
+CORPORATE PERFORMANCE GRAPH 
+The following graph compares the cumulative total return on the Company’s Common Stock from December 31, 2005 through December 31, 2010, with the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index. The graph assumes that $100 was invested on December 31, 2005 in each of the Company’s common stock, the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index, and that all dividends were reinvested. 
+10 
+Table of Contents 
+COMPARISON OF CUMULATIVE TOTAL RETURN AMONG 
+TRANSACT TECHNOLOGIES INCORPORATED COMMON STOCK, 
+THE CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.), 
+AND THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX 
+12/31/05 
+12/31/06 
+12/31/07 
+12/31/08 
+12/31/09 
+12/31/10 
+TransAct Technologies Incorporated Common Stock 
+$ 
+100.00 
+$ 
+105.06 
+$ 
+60.63 
+$ 
+58.10 
+$ 
+87.85 
+$ 
+119.24 
+CRSP Total Return Index for the Nasdaq Stock Market (U.S.) 
+$ 
+100.00 
+$ 
+109.84 
+$ 
+119.14 
+$ 
+57.41 
+$ 
+82.53 
+$ 
+97.95 
+Nasdaq Computer Manufacturer Stocks Index 
+$ 
+100.00 
+$ 
+102.13 
+$ 
+149.41 
+$ 
+62.76 
+$ 
+137.84 
+$ 
+196.73 
+Item 6. Selected Financial Data (in thousands, except per share amounts) 
+The following is summarized from our audited financial statements of the past five years: 
+Year Ended December 31, 
+2010 
+2009 
+2008 
+2007 
+2006 
+Consolidated Statement of Operations Data: 
+Net sales 
+$ 
+63,194 
+$ 
+58,346 
+$ 
+62,207 
+$ 
+48,766 
+$ 
+64,328 
+Gross profit 
+22,548 
+18,829 
+20,950 
+15,996 
+22,365 
+Operating expenses 
+16,687 
+15,533 
+19,089 
+19,751 
+16,277 
+Operating income (loss) 
+5,861 
+3,296 
+1,861 
+(3,755 
+) 
+6,088 
+Net income (loss) 
+3,904 
+2,140 
+1,444 
+(2,274 
+) 
+3,916 
+Net income (loss) per share: 
+Basic 
+0.42 
+0.23 
+0.16 
+(0.24 
+) 
+0.41 
+Diluted 
+0.41 
+0.23 
+0.15 
+(0.24 
+) 
+0.40 
+11 
+Table of Contents 
+December 31, 
+2010 
+2009 
+2008 
+2007 
+2006 
+Consolidated Balance Sheet Data: 
+Total assets 
+$ 
+43,621 
+$ 
+34,899 
+$ 
+32,234 
+$ 
+30,414 
+$ 
+33,706 
+Working capital 
+25,525 
+20,474 
+15,051 
+11,338 
+16,643 
+Shareholders’ equity 
+31,134 
+26,354 
+23,282 
+21,608 
+24,290 
+Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 
+This discussion should be read in conjunction with the Consolidated Financial Statements and notes thereto. 
+Forward Looking Statements 
+Certain statements included in this report, including without limitation statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, which are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements generally can be identified by the use of forward-looking terminology, such as “may”, “will”, “expect”, “intend”, ”estimate”, “anticipate”, “believe”, “project” or “continue” or the negative thereof or other similar words. All forward-looking statements involve risks and uncertainties, including, but not limited to those listed in Item 1A of this Annual Report. Actual results may differ materially from those discussed in, or implied by, the forward-looking statements. The forward-looking statements speak only as of the date of this report and we assume no duty to update them. 
+Overview 
+During 2010, we again concentrated our efforts on growing overall revenue in our existing markets, with particular emphasis on gaining market share in the U.S. casino market. In addition, we also focused on increasing our gross margin and leveraging such increase to our operating income. We believe we successfully achieved these objectives in 2010. We increased our overall sales 8% and our U.S. casino and gaming printer sales 24%, despite a decline in the replacement cycle of casino printers and a difficult U.S. economy. Our printer shipments also increased 17% to almost 190,000 in 2010. In addition, our gross margin, operating margin and earnings per share for 2010 each increased substantially from 2009. We continued to generate positive cash flow during 2010, as we increased our cash balance to almost $11,300,000 – a record high. 
+We continue to focus on sales growth in our core markets (banking and POS, casino and gaming, lottery, and TSG) to drive increased profitability. During 2010, our total net sales increased 8% to approximately $63,194,000. See the table below for a breakdown of our sales by market. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Banking and POS 
+$ 
+14,528 
+23.0 
+% 
+$ 
+16,695 
+28.6 
+% 
+$ 
+(2,167 
+) 
+(13.0 
+%) 
+Casino and gaming 
+25,678 
+40.6 
+% 
+17,526 
+30.0 
+% 
+8,152 
+46.5 
+% 
+Lottery 
+8,142 
+12.9 
+% 
+9,551 
+16.4 
+% 
+(1,409 
+) 
+(14.8 
+%) 
+TSG 
+14,846 
+23.5 
+% 
+14,574 
+25.0 
+% 
+272 
+1.9 
+% 
+Total net sales 
+$ 
+63,194 
+100.0 
+% 
+$ 
+58,346 
+100.0 
+% 
+$ 
+4,848 
+8.3 
+% 
+Sales of our banking and POS printers decreased 13% in 2010 compared to 2009. In the banking market, we focus mainly on supplying printers for use in bank teller stations at banks and financial institutions primarily in the U.S. Opportunities in the banking market are project oriented and as a result, our banking printer sales can fluctuate significantly year-to-year. During 2010, our banking printer sales decreased 79% primarily due to an order not recurring in 2010 for a large banking customer who completed a project in 2009. This decrease was somewhat offset by the first year of volume sales of our Bankjet ® 2500 printer. In the POS market, we focus primarily on supplying printers that print receipts or linerless labels for customers in the restaurant, hospitality and specialty retail markets. Sales of our POS printers increased 43% in 2010 largely due to a 121 % increase in sales of our two printer products for McDonalds – (1) the Ithaca® 8000 thermal receipt/label printer, which is used at the POS terminal to print either a receipt at the front counter or a label at the grill station and (2) the Ithaca® 8040 label printer, which is used to print labels for McDonalds combined beverage initiative. During 2010, we benefited from increasing sales of printers for both of these McDonald’s initiatives, with the majority of the increase related to the rollout of printers for the new POS system in more than 14,000 of its U.S. stores. We expect the rollout to the U.S. stores to continue into 2011, and as it nears completion in 2011, we expect McDonalds to begin the rollout in its international stores (totaling more than 18,000 stores). 
+Sales of our casino and gaming printers increased 47% in 2010 compared to 2009. In our casino and gaming market, our focus lies primarily in supplying printers for use in slot machines at casinos and racetracks, as well as in other gaming devices that print tickets or receipts, worldwide. Sales in the international casino and gaming market grew for the third consecutive year in 2010. In fact, our international sales increased 63% from 2009, representing more than half – or 64% - of our total worldwide casino and gaming sales. This increase was led by an 84% increase in 
+12 
+Table of Contents 
+our thermal casino printer sales. The increase in sales to our international customers was primarily due to the sales of gaming machines into Italy, where the Italian government has approved gambling operators to install approximately 50,000 VLT games. Since a substantial portion of these games were installed during 2010, we expect installations for 2011 to be significantly lower than in 2010. Domestic sales of our casino and gaming printers increased 24%, due largely to market share gains in the casino market, as we believe the overall replacement cycle of slot machines was lower in 2010 as compared to 2009. 
+In the lottery market, we continue to hold a leading position based on our long-term purchase agreement with GTECH, our largest customer and the world’s largest provider of lottery terminals. GTECH has been our customer since 1995, and we continue to maintain a good relationship with them. In 2009 we expanded our long-standing relationship with GTECH by executing a new exclusive purchase agreement to develop and supply them with their next generation online thermal lottery printer. Pursuant to the new agreement, GTECH will exclusively purchase all of its requirements for thermal on-line lottery printers from us and we will exclusively sell such printers to GTECH for four years from the start of production of the new printer, which occurred in January 2011. This new agreement extends our relationship with GTECH through at least 2014. Currently, we fulfill substantially all of GTECH’s printer requirements for lottery terminal installations and upgrades worldwide. During 2010, total printer sales to GTECH decreased approximately 15%, compared to 2009. Our sales to GTECH each year are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. 
+Our TransAct Services Group, which sells service, replacement parts and consumable products, including receipt paper, ribbons and inkjet cartridges, continues to offer a growth opportunity and recurring revenue stream for TransAct. TSG revenue continued to increase in 2010, rising 2% from 2009 primarily due to higher sales of inkjet cartridges to new and existing customers, as well as an increase in service revenue from our new paper testing services program. Companies who produce and sell consumable items that are used in our printers, such as paper, utilize this new service for a fee to have their product qualified for use in our printers. 
+Operationally, both our gross margin and operating margin showed marked improvement from 2009. During 2010, our gross margin increased to 35.7% compared to 32.3% in 2009 and our operating margin increased to 9.3% in 2010 compared to 5.6% in 2009. Both our gross margin and operating margin increased due primarily to higher sales volume combined with an increase in sales of contract manufactured products with lower overall product costs, including lower labor costs, resulting from the move of production for the majority of our products to a low cost contract manufacturer in China. In addition, we also experienced a more favorable sales mix as we sold more higher margin casino printer products and fewer lower margin banking printers in 2010 compared to 2009. 
+We reported net income of $3,904,000 and net income per diluted share of $0.41 for 2010, compared to net income of $2,140,000 and net income per diluted share of $0.23 in 2009. In terms of cash flow for 2010, we generated $2,132,000 of cash from operations, utilized $1,107,000 of cash for capital expenditures and we finished the year with a record high $11,285,000 of cash and no debt on our balance sheet as of December 31, 2010. Overall, we exited 2010 financially stronger than we entered it, with over $11,000,000 of cash, no debt outstanding and over $25,000,000 of working capital. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect both balance sheet items and income statement categories. Such estimates and judgments are based upon historical experience and certain assumptions that are believed to be reasonable in the particular circumstances. We evaluate our assumptions on an ongoing basis by comparing actual results with our estimates. Actual results may differ from the original estimates. 
+The following accounting policies are those that we believe to be most critical in the preparation of our financial statements. These items utilize assumptions and estimates about the effect of future events that are inherently uncertain and are therefore based on our judgment. Please refer to Note 2 – “Summary of significant accounting policies” in the accompanying Consolidated Financial Statements for a complete listing of our accounting policies. 
+Revenue Recognition – Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within Accounting Standards Codification (“ASC”) 605, “Revenue Recognition” (ASC 605). Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We account for all revenue arrangements involving multiple deliverables in accordance with ASC 605-25, “Multiple-Element Arrangements.” For these arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value 
+13 
+Table of Contents 
+among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and recognize revenue as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established, but we cannot guarantee that we will continue to experience return rates consistent with historical patterns. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. However, we cannot guarantee that this minimal level will continue. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Accounts Receivable – We have standardized credit granting and review policies and procedures for all customer accounts, including: credit reviews of all new customer accounts; ongoing credit evaluations of current customers; credit limits and payment terms based on available credit information; and adjustments to credit limits based upon payment history and the customer’s current creditworthiness. We also provide an estimate of doubtful accounts based on historical experience and specific customer collection issues. Our allowance for doubtful accounts as of December 31, 2010 was $57,000, or less than 1.0% of outstanding accounts receivable, which we feel is appropriate considering the overall quality of our accounts receivable. While credit losses have historically been within expectations and the reserves established, we cannot guarantee that our credit loss experience will continue to be consistent with historical experience. 
+Inventory – Our inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Assumptions are reviewed at least quarterly and adjustments are made, as necessary, to reflect changing market conditions. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. Should circumstances change and we determine that additional inventory is subject to obsolescence, additional write-downs of inventory could result in a charge to income. 
+Goodwill – We test the impairment of goodwill each year or more frequently if events or changes in circumstances indicate that the carrying value may not be recoverable. We completed our last assessment as of December 31, 2010. Factors considered that may trigger an impairment review are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Goodwill amounted to $1,469,000 at December 31, 2010 and we have determined that no goodwill impairment has occurred. 
+Income Taxes – In preparing our consolidated financial statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. This involves estimating the actual current tax exposure together with assessing temporary differences between the tax basis of certain assets and liabilities and their reported amounts in the financial statements, as well as net operating losses, tax credits and other carryforwards. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheets. We then assess the likelihood that the deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. 
+Significant judgment is required in determining the provision for income taxes and, in particular, any valuation allowance or tax reserves with respect to our deferred tax assets and uncertain tax positions. On a quarterly basis, we evaluate the recoverability of our deferred tax assets based upon historical results and forecasted taxable income over future years, and match this forecast against the basis differences, deductions available in future years and the limitations allowed for net operating loss and tax credit carryforwards to ensure that there is adequate support for the realization of the deferred tax assets. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance or tax reserve, in the event we were to determine that we would not be able to realize all or part of our deferred tax assets in the future, an adjustment to the valuation allowance or tax reserves would be charged as a reduction to 
+14 
+Table of Contents 
+income in the period such determination was made. Likewise, should we determine that we would be able to realize future deferred tax assets in excess of its net recorded amount, an adjustment to the valuation allowance or tax reserves would increase net income in the period such determination was made. 
+We account for income taxes in accordance with ASC 740, “Income Taxes.” Among other things this provision prescribes a minimum recognition threshold that an income tax position must meet before it is recorded in the reporting entity’s financial statements. It also requires that the effects of such income tax positions be recognized only if, as of the balance sheet reporting date, it is “more likely than not” (i.e., more than a 50% likelihood) that the income tax position will be sustained based solely on its technical merits. When making this assessment, management must assume that the responsible taxing authority will examine the income tax position and have full knowledge of all relevant facts and other pertinent information. The accounting guidance also clarifies the method of accruing for interest and penalties when there is a difference between the amount claimed, or expected to be claimed, on a company’s income tax returns and the benefits recognized in the financial statements. 
+Warranty – We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. If actual future product repair rates or the actual costs of material and labor differ from the estimates, adjustments to the accrued warranty liability and related warranty expense would be made. 
+Contingencies – We record an estimated liability related to contingencies based on our estimates of the probable outcomes pursuant to ASC 450, “Contingencies.” On a quarterly basis, we assess the potential liability related to pending litigation, audits and other contingencies and confirm or revise estimates and reserves as appropriate. If the actual liabilities are settled in an amount greater than those recorded on the balance sheet, a charge to income would be recorded. 
+Share-Based Compensation – We calculate share-based compensation expense in accordance with ASC 718, “Compensation – Stock Compensation” using the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions for this valuation method include the expected term of an option grant, stock price volatility, risk-free interest rate, dividend yield, and forfeiture rate. The determination of these assumptions is based on past history and future expectations, and is subject to a high level of judgment. To the extent any of the assumptions were to change from year to year, the fair value of new option grants may vary significantly. 
+Results of Operations: Year ended December 31, 2010 compared to year ended December 31, 2009 
+Net Sales. Net sales, which include printer sales and sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2010 and 2009 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Banking and POS 
+$ 
+14,528 
+23.0 
+% 
+$ 
+16,695 
+28.6 
+% 
+$ 
+(2,167 
+) 
+(13.0 
+)% 
+Casino and gaming 
+25,678 
+40.6 
+% 
+17,526 
+30.0 
+% 
+8,152 
+46.5 
+% 
+Lottery 
+8,142 
+12.9 
+% 
+9,551 
+16.4 
+% 
+(1,409 
+) 
+(14.8 
+)% 
+TSG 
+14,846 
+23.5 
+% 
+14,574 
+25.0 
+% 
+272 
+1.9 
+% 
+$ 
+63,194 
+100.0 
+% 
+$ 
+58,346 
+100.0 
+% 
+$ 
+4,848 
+8.3 
+% 
+International* 
+$ 
+19,093 
+30.2 
+% 
+$ 
+12,456 
+21.3 
+% 
+$ 
+6,637 
+53.3 
+% 
+* 
+International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+Net sales for 2010 increased $4,848,000, or 8%, from 2009 due to sales increases in two out of four of our markets: casino and gaming (an increase of approximately $8,152,000, or 47%) and TSG (an increase of approximately $272,000, or 2%). Sales from banking and POS decreased approximately $2,167,000, or 13%, and sales from our lottery market decreased approximately $1,409,000, or 15%. Printer sales volume increased 17% while the average selling price of our printers decreased approximately 5% (due primarily to a decrease in sales of banking printers with higher average selling prices) from 2009 to 2010. Overall, international sales increased $6,637,000, or 53%, driven by higher sales to the gaming portion of the casino and gaming market. 
+Banking and POS : Revenue from the banking and POS market includes sales of printers used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. Revenue from this market also includes sales of inkjet, thermal and impact printers used primarily by retailers in restaurant (including fine dining, casual dining and fast food), hospitality, and specialty retail industries to 
+15 
+Table of Contents 
+print receipts for consumers, validate checks, or print on linerless labels or other inserted media. Sales of our banking and POS printers worldwide decreased approximately $2,167,000, or 13%, from 2009. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+13,447 
+92.6 
+% 
+$ 
+15,480 
+92.7 
+% 
+$ 
+(2,033 
+) 
+(13.1 
+)% 
+International 
+1,081 
+7.4 
+% 
+1,215 
+7.3 
+% 
+(134 
+) 
+(11.0 
+)% 
+$ 
+14,528 
+100.0 
+% 
+$ 
+16,695 
+100.0 
+% 
+$ 
+(2,167 
+) 
+(13.0 
+)% 
+Domestic banking and POS printer revenue was $13,447,000, a 13% decrease from 2009, primarily driven by lower sales of our banking printers. Sales of our banking printers decreased 79% in 2010 compared to 2009 due to the completion of a project by one of our large banking customers utilizing our BANKjet® 1500 bank teller printers in 2009 that did not recur in 2010. This decrease was somewhat offset by the first year of volume sales of our BANKjet® 2500 printer. Although we are currently pursuing several banking opportunities, due to the project-oriented nature of these sales, we cannot predict the level of future sales. Domestic sales of our POS printers increased approximately 52% largely due to sales of our two printer products for McDonalds for its combined beverage initiative and its POS system upgrade and grill initiatives. Sales of these printers increased approximately 121% during 2010 compared to 2009. We expect to continue to benefit from our relationship with McDonalds during 2011 as McDonalds continues and completes the rollout of its new POS system, which includes the grill initiative printer upgrades, to more than 14,000 U.S. stores and begins to expand the rollout to more than 18,000 international stores. 
+International banking and POS printer sales for 2010 decreased from 2009 by $134,000, or 11%, to $1,081,000 due primarily to lower legacy impact printer sales to our international distributor in Latin America. 
+Casino and gaming : Revenue from the casino and gaming market includes sales of printers used in slot machines, video lottery terminals (“VLTs”), and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos and racetracks (“racinos”) and other gaming venues worldwide. Revenue from this market also includes sales of printers used in the international off-premise gaming market in gaming machines such as Amusement with Prizes (“AWP”), Skills with Prizes (“SWP”), Fixed Odds Betting Terminals (“FOBT”) at non-casino gaming establishments and royalties related to our patented casino and gaming technology. Sales of our casino and gaming printers increased $8,152,000, or 47%, from 2009. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+9,287 
+36.2 
+% 
+$ 
+7,497 
+42.8 
+% 
+$ 
+1,790 
+23.9 
+% 
+International 
+16,391 
+63.8 
+% 
+10,029 
+57.2 
+% 
+6,362 
+63.4 
+% 
+$ 
+25,678 
+100.0 
+% 
+$ 
+17,526 
+100.0 
+% 
+$ 
+8,152 
+46.5 
+% 
+Domestic sales of our casino and gaming printers increased $1,790,000, or 24%, due largely to an increase of 53% in the volume of sales of our thermal casino printers. We believe that our increased casino printer sales during 2010 resulted from market share gains, as we believe the overall replacement cycle of slot machines was lower in 2010 as compared to 2009. Even though we anticipate little improvement in the domestic slot machine replacement cycle in 2011, we expect our domestic casino sales to be higher in 2011 than in 2010 as we expect to continue to gain market share. However, we believe the current uncertain economic environment could continue to negatively impact the casino industry’s level of capital expenditures in 2011, and as a result, our future sales to the domestic casino and gaming market could be unpredictable and adversely affected. 
+International casino and gaming printer sales increased $6,362,000, or 63%, to $16,391,000 in 2010. This increase was due primarily to a 161% increase in our thermal casino printer sales to our OEM and distributor customers in Canada and Europe, partially offset by a 23% decrease in casino printer sales to our distributor in Australia. The increase in sales to our customers in Canada and Europe was primarily due to the sales of gaming machines into Italy, where in 2010 the Italian government approved gambling operators to install approximately 50,000 VLT games over the course of several years. Since a substantial portion of these games were installed during 2010, we expect installations for 2011 to be significantly lower than in 2010. In addition, sales for 2010 included $1,600,000 in sales of our off-premise gaming printers to a new customer for use in gaming machines in the U.K. 
+Lottery: Revenue from the lottery market includes sales of lottery printers to GTECH for various lottery applications. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+7,813 
+96.0 
+% 
+$ 
+9,117 
+95.5 
+% 
+$ 
+(1,304 
+) 
+(14.3 
+)% 
+International 
+329 
+4.0 
+% 
+434 
+4.5 
+% 
+(105 
+) 
+(24.2 
+)% 
+$ 
+8,142 
+100.0 
+% 
+$ 
+9,551 
+100.0 
+% 
+$ 
+(1,409 
+) 
+(14.8 
+)% 
+16 
+Table of Contents 
+Domestic and international lottery printer sales to GTECH, which include thermal on-line and other lottery printers, decreased approximately $1,409,000, or 15%, in 2010 compared to 2009, with domestic sales decreasing approximately $1,304,000 and international sales decreasing approximately $105,000. Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. Based on our backlog of orders, we expect total sales to GTECH for 2011 to be significantly higher than those reported during 2010, particularly during the first half of 2011. 
+TSG : Revenue from TSG includes sales of consumable products (inkjet cartridges, ribbons, receipt paper and other printing supplies), replacement parts, maintenance and repair services, testing services, refurbished printers, and shipping and handling charges. Sales from TSG increased approximately $272,000, or 2%, from 2009. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+13,554 
+91.3 
+% 
+$ 
+13,796 
+94.7 
+% 
+$ 
+(242 
+) 
+(1.8 
+%) 
+International 
+1,292 
+8.7 
+% 
+778 
+5.3 
+% 
+514 
+66.1 
+% 
+$ 
+14,846 
+100.0 
+% 
+$ 
+14,574 
+100.0 
+% 
+$ 
+272 
+1.9 
+% 
+Domestic revenue from TSG decreased approximately $242,000, or 2%, largely due to a decrease of 23% in sales of replacement parts compared to the same period in 2009. The decrease in replacement part sales was primarily due to lower demand for certain legacy printers, as the installed base of these legacy printers in the market continues to decline. In addition, maintenance and repair service revenue declined 18% due primarily to lower service contract revenue. These decreases were somewhat offset by an increase in revenue from our new paper testing services and a 2% increase in sales of inkjet cartridges largely due to newly acquired customers. We expect TSG sales in 2011 to be consistent with 2010. 
+Internationally, TSG revenue increased $514,000, or 66%, to $1,292,000, due primarily to higher sales of replacement parts and printer accessories, largely for our casino, gaming and lottery printers installed in Europe. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+22,548 
+$ 
+18,829 
+19.8 
+% 
+35.7 
+% 
+32.3 
+% 
+Gross profit is measured as revenue less cost of goods sold. Cost of goods sold includes primarily the cost of all raw materials and component parts, direct labor and the associated manufacturing overhead expenses, and the cost of finished products purchased directly from our contract manufacturer. Gross profit increased $3,719,000, or 20%, to $22,548,000 from $18,829,000 and gross margin improved from 32.3% to 35.7% due primarily to (1) an increase in sales of contract manufactured products with lower overall product costs, including lower labor costs, resulting from the move of production for the majority of our products to a low cost contract manufacturer in China, (2) a more favorable sales mix as we sold more higher margin casino printers and fewer lower margin banking printers in 2010 compared to 2009 and (3) increased volume of 17% offset by a decrease of 5% in average selling prices of our printers in 2010 compared to 2009. Additionally, our gross margin for 2009 was adversely impacted by higher material and labor costs as we depleted a substantial portion of our higher cost domestic inventory in preparation for the completion of our production transfer to China. We expect our gross margin for 2011 to be approximately the same as in 2010. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+3,000 
+$ 
+2,788 
+7.6 
+% 
+4.7 
+% 
+4.8 
+% 
+Engineering, design and product development expenses primarily include salary and payroll related expenses for our engineering staff, depreciation and design expenses (including prototype printer expenses, outside design and testing services, and supplies). Such expenses increased $212,000, or 8%, to $3,000,000. The increase was due primarily to higher employee compensation related expenses resulting largely from annual salary increases and higher incentive compensation of $165,000, higher outside testing and pre-production expenses related to new product development of $20,000, and higher consulting expenses of $21,000 compared to 2009. 
+17 
+Table of Contents 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+6,407 
+$ 
+5,821 
+10.1 
+% 
+10.1 
+% 
+10.0 
+% 
+Selling and marketing expenses primarily include salaries and payroll related expenses for our sales and marketing staff, sales commissions, travel expenses, expenses associated with the lease of sales offices, advertising, trade show expenses, e-commerce and other promotional marketing expenses. Selling and marketing expenses for 2010 increased $586,000, or 10%, to $6,407,000. The increase was due primarily to approximately $182,000 of higher employee compensation related expenses associated with increased headcount within the sales departments and higher sales commissions resulting from higher sales volume, $275,000 of increased travel related expenses, $99,000 of increased tradeshow expenses, and $46,000 of higher demonstration printer expenses. These increases were somewhat offset by $13,000 decrease in other promotional marketing expenses compared to the prior year period. 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+7,280 
+$ 
+6,924 
+5.1 
+% 
+11.5 
+% 
+11.9 
+% 
+General and administrative expenses primarily include salaries and payroll related expenses for our executive, accounting, human resource, business development and information technology staff, expenses for our corporate headquarters, professional and legal expenses, telecommunication expenses, and other expenses related to being a publicly-traded company. General and administrative expenses increased $356,000, or 5%, to $7,280,000. The increase was due primarily to $430,000 in increased employee compensation related expenses from annual salary increases and higher incentive compensation, as well as an increase of $115,000 in certain state and local taxes. These increases were largely offset by a reduction in legal and professional fee expenses of $150,000 and a reduction of depreciation expense of $55,000. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales - 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+5,861 
+$ 
+3,296 
+77.8 
+% 
+9.3 
+% 
+5.6 
+% 
+During 2010, we reported operating income of $5,861,000, or 9.3%, of net sales, compared to operating income of $3,296,000, or 5.6% of net sales in 2009. The increase in our operating income and operating margin was primarily due to higher gross profit resulting from the 8% increase in net sales and a 340 basis point improvement in gross margin in 2010 compared to 2009. 
+Interest. We recorded net interest expense of $9,000 in 2010 compared to $50,000 in 2009. The decrease in net interest expense is due to increased interest income earned on a higher average cash balance in 2010 compared to 2009, partially offset by $26,000 of interest expense incurred in 2010 related to certain prior years’ state and local tax liabilities. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2010 and 2009. See “Liquidity and Capital Resources” below for more information. 
+Other Income. We recorded other expense of $25,000 in 2010 compared to other expense of $33,000 in 2009. Other expense for 2010 and 2009 primarily included foreign currency transaction exchange losses recorded by our U.K. subsidiary. These losses were relatively consistent in 2010 compared to 2009. 
+Income Taxes. We recorded an income tax provision for 2010 of $1,923,000 at an effective tax rate of 33.0% compared to $1,073,000 at an effective tax rate of 33.5%. The effective tax rate for 2010 decreased slightly as compared to 2009 primarily due to increased utilization of state net operating losses and certain credits. We expect our annual effective tax rate for 2011 to be approximately 34-35%. 
+Net Income . We reported net income during 2010 of $3,904,000, or $0.41, per diluted share, compared to $2,140,000, or $0.23, per diluted share, for 2009. 
+18 
+Table of Contents 
+Results of Operations: Year ended December 31, 2009 compared to year ended December 31, 2008 
+Net Sales. Net sales, which include printer sales and sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2009 and 2008 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Banking and POS 
+$ 
+16,695 
+28.6 
+% 
+$ 
+11,866 
+19.1 
+% 
+$ 
+4,829 
+40.7 
+% 
+Casino and gaming 
+17,526 
+30.0 
+% 
+22,299 
+35.8 
+% 
+(4,773 
+) 
+(21.4 
+)% 
+Lottery 
+9,551 
+16.4 
+% 
+15,731 
+25.3 
+% 
+(6,180 
+) 
+(39.3 
+)% 
+TSG 
+14,574 
+25.0 
+% 
+12,311 
+19.8 
+% 
+2,263 
+18.4 
+% 
+$ 
+58,346 
+100.0 
+% 
+$ 
+62,207 
+100.0 
+% 
+$ 
+(3,861 
+) 
+(6.2 
+)% 
+International* 
+$ 
+12,456 
+21.3 
+% 
+$ 
+10,126 
+16.3 
+% 
+$ 
+2,330 
+23.0 
+% 
+* 
+International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+Net sales for 2009 decreased $3,861,000, or 6%, from 2008 due to sales decreases in two out of four of our markets: casino and gaming (a decrease of approximately $4,773,000, or 21%) and lottery (a decrease of approximately $6,180,000 or 39%). Sales from banking and POS increased approximately $4,829,000 or 41% and sales from our TSG increased approximately $2,263,000, or 18%. Printer sales volume decreased 17% while the average selling price of our printers increased by approximately 6% (due primarily to an increase in sales of banking printers with higher average selling prices) from 2008 to 2009. Overall, international sales increased $2,330,000, or 23%, driven by higher sales to the gaming portion of the casino and gaming market. 
+Banking and POS : Sales of our banking and POS printers worldwide increased approximately $4,829,000, or 41%, from 2008. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+15,480 
+92.7 
+% 
+$ 
+10,664 
+89.9 
+% 
+$ 
+4,816 
+45.2 
+% 
+International 
+1,215 
+7.3 
+% 
+1,202 
+10.1 
+% 
+13 
+1.1 
+% 
+$ 
+16,695 
+100.0 
+% 
+$ 
+11,866 
+100.0 
+% 
+$ 
+4,829 
+40.7 
+% 
+Domestic banking and POS printer revenue increased to $15,480,000, representing a $4,816,000, or 45%, increase from 2008 primarily driven by higher sales of our banking printers. Sales of our banking printers increased 443% in 2009 compared to 2008 as we finished shipping against the $4,900,000 order we received from a large banking customer in February 2009 as well as additional orders from this same customer. Sales of our POS printers declined approximately 15% largely due to the general economic slowdown that we believe adversely impacted the capital spending of a number of our retail and hospitality customers during 2009. Contributing to the decline in sales of our POS printers, sales of our legacy line of POS impact printers decreased approximately 39%. Despite these declines, sales of our two new printer products for McDonalds, the Ithaca 8000 Ò (for McDonald’s new POS system upgrade including the grill initiative) and Ithaca® 8040 (for McDonald’s combined beverage initiative), increased approximately 48% during 2009 compared to 2008. During 2009, we benefited from increasing sales of printers for both of these McDonald’s initiatives, but most especially from the rollout of printers for the combined beverage initiative that was nearing completion. 
+International banking and POS printer shipments for 2009 were consistent with 2008, increasing $13,000, or 1%, to $1,215,000. 
+Casino and gaming : Sales of our casino and gaming printers decreased $4,773,000, or 21%, from 2008, due primarily to decreased sales of our thermal casino and gaming printers domestically offset by increased sales of our thermal gaming printers internationally. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+7,497 
+42.8 
+% 
+$ 
+14,355 
+64.4 
+% 
+$ 
+(6,858 
+) 
+(47.8 
+)% 
+International 
+10,029 
+57.2 
+% 
+7,944 
+35.6 
+% 
+2,085 
+26.2 
+% 
+$ 
+17,526 
+100.0 
+% 
+$ 
+22,299 
+100.0 
+% 
+$ 
+(4,773 
+) 
+(21.4 
+)% 
+Domestic sales of our casino and gaming printers decreased $6,858,000, or 48%, due largely to a decrease in sales of our thermal casino printers, and to a lesser extent sales of our gaming printers, both of which were impacted by the downturn in the domestic casino and gaming market. 
+19 
+Table of Contents 
+International casino and gaming printer sales increased $2,085,000, or 26%, to $10,029,000 in 2009. International gaming printer sales increased 89%, led largely by continued growing sales of our line of off-premise gaming printers in both Europe and Australia. International casino printer sales for 2009 increased 3% due primarily to an 83% increase in sales to our Australian distributer that was largely offset by a 39% decline in sales to our European distributor. 
+Lottery: Revenue from the lottery market includes sales of lottery printers to GTECH for various lottery applications. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+9,117 
+95.5 
+% 
+$ 
+15,283 
+97.2 
+% 
+$ 
+(6,166 
+) 
+(40.3 
+)% 
+International 
+434 
+4.5 
+% 
+448 
+2.8 
+% 
+(14 
+) 
+(3.1 
+)% 
+$ 
+9,551 
+100.0 
+% 
+$ 
+15,731 
+100.0 
+% 
+$ 
+(6,180 
+) 
+(39.3 
+)% 
+Domestic and international lottery printer sales to GTECH, which include thermal on-line and other lottery printers, decreased approximately $6,180,000, or 39%, in 2009 compared to 2008, with domestic sales decreasing approximately $6,166,000 and international sales decreasing approximately $14,000. Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. 
+TSG : Sales from TSG increased approximately $2,263,000, or 18% from 2008. 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2009 
+December 31, 2008 
+$ 
+% 
+Domestic 
+$ 
+13,796 
+94.7 
+% 
+$ 
+11,779 
+95.7 
+% 
+$ 
+2,017 
+17.1 
+% 
+International 
+778 
+5.3 
+% 
+532 
+4.3 
+% 
+246 
+46.2 
+% 
+$ 
+14,574 
+100.0 
+% 
+$ 
+12,311 
+100.0 
+% 
+$ 
+2,263 
+18.4 
+% 
+Domestic revenue from TSG increased approximately $2,017,000, or 17%, largely due to an increase of approximately 33% in sales of consumable products from 2008, mostly due to significantly higher inkjet cartridge sales to a large banking customer. During 2009, this large customer purchased approximately two years worth of inkjet cartridges based on their annual average consumption rate. 
+Internationally, TSG revenue increased $246,000, or 46%, to $778,000, due primarily to a 51% increase in sales of replacement parts and accessories and a 47% increase in maintenance and repair services revenue largely due to new service contracts won during 2009. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+18,829 
+$ 
+20,950 
+(10.1 
+)% 
+32.3 
+% 
+33.7 
+% 
+Gross profit decreased $2,121,000, or 10%, to $18,829,000 from $20,950,000, and gross margin declined from 33.7% to 32.3% due primarily to (1) a 6% decrease in sales in 2009 compared to 2008, (2) a less favorable sales mix resulting from higher sales of banking printers and certain consumable products at lower gross margins than our overall gross margin and (3) higher material and labor cost as we depleted a substantial portion of our higher cost domestic inventory in the second half of 2009 as we completed the transition of full production of 70% of our printers to a contract manufacturer in China. These decreases were partially offset by (1) approximately $247,000 of lower product warranty expense from improved repair history and a 17% decline in printer shipments in 2009 compared to 2008 and (2) approximately $387,000 of lower manufacturing expenses due to the transition of more of our production to China. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+2,788 
+$ 
+2,942 
+(5.2 
+)% 
+4.8 
+% 
+4.7 
+% 
+20 
+Table of Contents 
+Engineering, design and product development expenses decreased $154,000, or 5%, to $2,788,000. Approximately $60,000 of the decrease was due to lower outside testing and pre-production prototype expenses related to new product development and approximately $97,000 of the decrease was due to lower employee compensation related expenses, including lower incentive compensation. 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+5,821 
+$ 
+6,078 
+(4.2 
+)% 
+10.0 
+% 
+9.8 
+% 
+Selling and marketing expenses for 2009 decreased $257,000, or 4%, due primarily to approximately $104,000 of lower sales commissions resulting from a 6% decrease in sales, approximately $33,000 of lower travel related expenses, approximately $151,000 in reduced promotional marketing expenses, and a reduction of approximately $54,000 in consulting and professional fees due to the cost control initiatives that were put in place for 2009. These decreases were partially offset by an increase of approximately $67,000 in employee compensation related expenses as we replaced several existing sales employees with higher level sales employees at higher compensation levels during 2009 to upgrade certain key sales positions. 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales – 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+6,924 
+$ 
+7,040 
+(1.6 
+)% 
+11.9 
+% 
+11.3 
+% 
+General and administrative expenses decreased $116,000, or 2%, due primarily to a reduction of approximately $515,000 in employee compensation related expenses largely due to lower incentive compensation in 2009 compared to 2008. These decreases were largely offset by approximately $68,000 in increased legal expenses, increased employee compensation related expenses associated with the full year effect of the hiring of our new Vice President of Business Development in May 2008, and $67,000 in increased depreciation. In addition, general and administrative expenses for 2009 included severance charges of approximately $211,000 related to the termination of approximately 17 employees. 
+Legal fees associated with lawsuit. During 2009, we did not incur any legal fees related to the settled lawsuit with FutureLogic compared to $3,029,000 in 2008. We settled our litigation with FutureLogic in May 2008 and as a result of the settlement, we do not expect to incur any additional legal fees related to the lawsuit. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2009 
+2008 
+Change 
+Total Sales - 2009 
+Total Sales – 2008 
+Year ended 
+$ 
+3,296 
+$ 
+1,861 
+77.1 
+% 
+5.6 
+% 
+3.0 
+% 
+During 2009, we reported operating income of $3,296,000, or 5.6% of net sales, compared to operating income of $1,861,000, or 3.0% of net sales in 2008. The increase in our operating income and operating margin was due to lower operating expenses (including the absence of legal expense related to the FutureLogic lawsuit), partially offset by lower gross profit on a 6% decline in sales in 2009 compared to 2008. 
+Interest. We recorded net interest expense of $50,000 in 2009 compared to $11,000 in 2008. Although our cash balance increased from $2,000,000 at December 31, 2008 to $10,017,000 at December 31, 2009, and we maintained a higher average cash balance in 2009 than in 2008, we earned lower interest income in 2009 due to a lower overall rate of return on our invested cash balance due to the decreasing interest rate environment. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2009 and 2008. See “Liquidity and Capital Resources” below for more information. 
+Other Income. We recorded other expense of $33,000 in 2009 compared to other income of $368,000 in 2008. The decrease was primarily due to foreign currency transaction exchange losses recorded by our U.K. subsidiary resulting from a 10% weakening of the U.S. dollar against the British pound during 2009, as compared to a foreign currency transaction exchange gain resulting from a 28% strengthening of the U.S. dollar against the British pound in 2008. 
+21 
+Table of Contents 
+Income Taxes. We recorded an income tax provision for 2009 of $1,073,000 at an effective tax rate of 33.5% compared to $774,000 at an effective tax rate of 34.9%. The effective tax rate for 2009 decreased as compared to 2008 primarily due to increased utilization of state net operating losses and certain credits. 
+Net Income . We reported net income during 2009 of $2,140,000, or $0.23 per diluted share, compared to $1,444,000, or $0.15 per diluted share, for 2008. 
+Liquidity and Capital Resources 
+We assess our liquidity in terms of our ability to generate cash to fund our operating, investing and financing activities. Significant factors affecting the management of liquidity are cash flows from operating activities, capital expenditures, stock repurchases, access to bank lines of credit and our ability to attract long-term capital with satisfactory terms. 
+Internal cash generation together with currently available cash and investments, available borrowing facilities and an ability to access credit lines, if needed, are expected to be sufficient to fund operations, capital expenditures, and any increase in working capital that would be required to accommodate a higher level of business activity. We actively seek to expand by acquisition as well as through the growth of our current business. While a significant acquisition may require additional debt and/or equity financing, although no assurances can be given, we believe that we would be able to obtain additional financing based on our historical earnings performance. 
+During 2010, our cash flows primarily reflected higher sales volume, resulting in higher accounts receivable balances and increased inventory investment. Our cash balance increased $1,268,000, or 13%, from December 31, 2009 and we ended 2010 with approximately $11,285,000 in cash and cash equivalents and no debt outstanding. 
+Operating activities : The following significant factors primarily affected our cash provided by operations of $2,132,000 in 2010 as compared to $8,373,000 in 2009. 
+During 2010: 
+· 
+We reported net income of $3,904,000. 
+· 
+We recorded depreciation, amortization and non-cash compensation expense of $2,114,000. 
+· 
+We recorded non-cash deferred income tax expense of $540,000. 
+· 
+Accounts receivable increased $1,878,000 due to higher sales volume and the timing of sales during the year. 
+· 
+Inventories increased $6,851,000 as we increased stocking levels of our lower cost, fully-built printers from our contract manufacturer in China in the first half of 2010. During the second half of 2010, inventory purchases were at a significantly higher level than the first half due to backlogged orders that will be shipped in 2011. We expect our inventories to decline starting in the second quarter of 2011 as we ship our backlog of orders and reduce our inventory purchases. 
+· 
+Accounts payable increased $3,289,000 due to higher inventory purchases in the fourth quarter of 2010 in anticipation of significantly higher demand in the first half of 2011, and to a lesser extent, the timing of payments in the fourth quarter of 2010. 
+· 
+Accrued liabilities and other liabilities increased $625,000 due primarily to higher incentive compensation and fringe benefit related accruals as well as increased income taxes payable resulting from a higher level of taxable income. 
+During 2009: 
+· 
+We reported net income of $2,140,000. 
+· 
+We recorded depreciation, amortization and non-cash compensation expense of $2,397,000. 
+· 
+We recorded non-cash deferred income tax expense of $1,002,000. 
+· 
+Accounts receivable increased $263,000 due to the timing of sales. 
+· 
+Inventories decreased $3,968,000 as we depleted a substantial portion of our domestic inventory prior to the final transition of full production of 70% of our printers to a contract manufacturer in China that was completed by the end of 2009. 
+· 
+Accounts payable increased $187,000 due to the timing of payments in the fourth quarter of 2009. 
+· 
+Accrued liabilities and other liabilities decreased $642,000 due primarily to lower payroll, fringe benefit and incentive compensation related accruals. 
+Investing activities: Our capital expenditures were approximately $1,107,000 and $643,000 in 2010 and 2009, respectively. Expenditures in 2010 included approximately $643,000 for the purchase of new product tooling, $269,000 for the purchase of computer, networking equipment, and software, $130,000 for capitalized development costs for our new EPICENTRAL™ promotional printing system for the casino market, $29,000 for the purchase of engineering equipment, and the remaining amount primarily for the purchase of manufacturing equipment, leasehold improvements and furniture and fixtures. Expenditures in 2009 included approximately $295,000 for the purchase of new product tooling, $236,000 for the purchase of computer, networking equipment, and software, $72,000 for the purchase of manufacturing equipment, and the remaining amount primarily for the purchase of engineering equipment and leasehold improvements. We expect our capital 
+22 
+Table of Contents 
+expenditures for 2011 to be between $1,500,000, and $2,000,000, largely for new product tooling and continued development of our EPICENTRAL™ software product. 
+Financing activities: We generated approximately $237,000 of cash from financing activities during 2010 due to $414,000 of proceeds and tax benefits from stock option exercises offset by $177,000 of purchases of common stock for treasury. During 2009, we generated approximately $290,000 from financing activities due to proceeds and tax benefits from stock option exercises. 
+Working Capital 
+Our working capital increased to $25,525,000 at December 31, 2010 from $20,474,000 at December 31, 2009. Our current ratio decreased to 3.2 at December 31, 2010, compared to 3.7 at December 31, 2009. The increase in our working capital was largely due to higher cash balances, accounts receivable balances and inventory balances offset by higher accounts payable and accrued liabilities balances all resulting from higher sales and inventory purchases. The current ratio decreased due to higher accounts payable and accrued liabilities balances resulting from higher inventory purchases. 
+Resource Sufficiency 
+We believe that our cash on hand and cash flows generated from operations will provide sufficient resources to meet our working capital needs, finance our capital expenditures and meet our liquidity requirements through at least the next twelve months. 
+Credit Facility and Borrowings 
+On November 28, 2006, we signed a, five-year $20,000,000 credit facility (the “TD Bank Credit Facility”) with TD Bank. The TD Bank Credit Facility provides for a $20,000,000 revolving credit line expiring on November 28, 2011. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent and are secured by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the revolving credit line. The total deferred financing costs relating to expenses incurred to complete the TD Bank Credit Facility was $94,000. The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur additional indebtedness, the payment of dividends on our common stock and the creation of other liens. We expect to renew our credit facility with TD Bank or another financial institution during 2011. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2010. The following table lists the financial covenants and the performance measurements at December 31, 2010: 
+Financial Covenant 
+Requirement/Restriction 
+Calculation at December 31, 2010 
+Operating cash flow / Total debt service 
+Minimum of 1.25 times 
+74.7 times 
+Funded debt / EBITDA 
+Maximum of 3.25 
+0 times 
+As of December 31, 2010, we had no balances outstanding on the revolving credit line. Undrawn commitments under the TD Bank Credit facility were approximately $20,000,000 at December 31, 2010. 
+Stock Repurchase Program 
+On May 27, 2010, our Board of Directors approved a new stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we are authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending May 27, 2013, depending on market conditions, share price and other factors. 
+During the fourth quarter of 2010, we made no repurchases of common stock. As of December 31, 2010, we have repurchased a total of 22,338 shares of common stock for approximately $177,000 , at an average price of $7.95 per share, under the Stock Repurchase Program. 
+Shareholders’ Equity 
+Shareholders’ equity increased $4,780,000 to $31,134,000 at December 31, 2010 from $26,354,000 at December 31, 2009. The increase was primarily due to net income of $3,904,000, proceeds of approximately $393,000 from the issuance of 84,672 shares of common stock from stock option exercises, compensation expense related to stock options and restricted stock of $565,000, an increase in additional paid-in capital of approximately $21,000 due to tax benefits resulting from employee stock transactions and approximately $77,000 from the issuance of 10,204 shares of deferred stock units. These increases were offset by $177,000 for the purchase of 22,338 shares of treasury stock. 
+Contractual Obligations 
+Our contractual obligations as of December 31, 2010 were as follows: 
+23 
+Table of Contents 
+Payments due by period 
+(In thousands) 
+Total 
+< 1 year 
+1-3 years 
+3-5 years 
+> 5 years 
+Operating lease obligations 
+$ 
+3,110 
+$ 
+952 
+$ 
+958 
+$ 
+740 
+$ 
+460 
+Purchase obligations 
+19,601 
+19,370 
+231 
+- 
+- 
+Total 
+$ 
+22,711 
+$ 
+20,322 
+$ 
+1,189 
+$ 
+740 
+$ 
+460 
+Purchase obligations are for purchases made in the normal course of business to meet operational requirements, primarily of fully assembled printers and component part inventory. 
+Recently Issued Accounting Pronouncements 
+Multiple-Deliverable Revenue Arrangements: In October 2009, the FASB established the accounting and reporting guidance for arrangements including multiple revenue-generating activities. This guidance provides amendments to the criteria for separating deliverables, measuring and allocating arrangement consideration to one or more units of accounting. The amendments also establish a selling price hierarchy for determining the selling price of a deliverable. Significantly enhanced disclosures are also required to provide information about a vendor’s multiple-deliverable revenue arrangements, including information about the nature and terms, significant deliverables, and its performance within arrangements. The amendments also require providing information about the significant judgments made and changes to those judgments and about how the application of the relative selling-price method affects the timing or amount of revenue recognition. The amendments are effective prospectively for revenue arrangements entered into or materially modified in the fiscal years beginning on or after June 15, 2010. Early application is permitted. Currently these provisions do not have an impact on our consolidated financial statements and we do not anticipate these provisions will have a material impact on our consolidated financial statements. 
+Financing Receivables: In July 2010 the FASB issued new accounting guidance to improve the disclosures that an entity provides about the credit quality of its financing receivables and the related allowance for credit losses. Accounts receivable with terms exceeding one year are considered finance receivables subject to the provisions of this standard. Our trade receivables, which arose from the sale of goods or services, have a contractual maturity of one year or less and therefore are not subject to the provisions of this standard. We do not have any significant receivables with a term exceeding one year and as a result, the standard does not have a material impact on us. 
+Impact of Inflation 
+We believe that our business has not been affected to a significant degree by inflationary trends during the past three years. However, inflation is still a factor in the worldwide economy and may increase the cost of purchasing printers from our contract manufacturer in China, as well as the cost of certain raw materials, component parts and labor used in the production of our products. It also may increase our operating expenses, manufacturing overhead expenses and the cost to acquire or replace fixed assets. Despite growing costs of oil, gas and freight over the last two years, we have generally been able to maintain or improve our profit margins through productivity and efficiency improvements, cost reduction programs and to a lesser extent, price increases, and we expect to be able to do the same during 2011. As such, we do not believe that inflation will have a significant impact on our business during 2011. 
+Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 
+Interest Rate Risk 
+Our exposure to market risk for changes in interest rates relates primarily to the investment of our available cash and cash equivalents. In accordance with our investment policy, we strive to achieve above market rates of return in exchange for accepting a prudent amount of incremental risk, which includes the risk of interest rate movements. Risk tolerance is constrained by an overriding objective to preserve capital. An effective increase or decrease of 10% in interest rates would not have a material effect on our results of operations or cash flows. 
+Foreign Currency Exchange Risk 
+A substantial portion of our sales are denominated in U.S. dollars and, as a result, we have relatively little exposure to foreign currency exchange risk with respect to sales made. This exposure may change over time as business practices evolve and could have a material adverse impact on our financial results in the future. We do not use forward exchange contracts to hedge exposures denominated in foreign currencies or any other derivative financial instruments for trading or speculative purposes. We estimate that the combined translational and transactional impact of a 10% overall movement in exchange rates from December 31, 2010 (principally the U.K. Pound Sterling) would increase/decrease net income 2%. 
+Item 8. Financial Statements and Supplementary Data. 
+The financial statements of the Company are annexed to this report as pages F-3 through F-17. An index to such materials appears on page F-1. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 
+None. 
+24 
+Table of Contents 
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2010, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2010. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Annual Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2010. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 
+Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2010. 
+This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report. 
+Item 9B. Other Information. 
+Not applicable. 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance. 
+The information in response to this item is incorporated by reference from the Proxy Statement sections entitled “Election of Directors” and “Executive Officers.” 
+Executive Officers of the Registrant 
+The following list is included as an unnumbered item in Part III of this Report in lieu of being included in the Proxy Statement for the Annual Meeting of Stockholders to be held on May 27, 2011. 
+The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. 
+Name 
+Age 
+Position 
+Bart C. Shuldman 
+53 
+Chairman of the Board and Chief Executive Officer 
+Steven A. DeMartino 
+41 
+President, Chief Financial Officer, Treasurer and Secretary 
+Michael S. Kumpf 
+61 
+Executive Vice President-Engineering 
+Tracey S. Chernay 
+51 
+Executive Vice President-Sales and Marketing 
+Andrew J. Hoffman 
+53 
+Senior Vice President-Operations 
+Benjamin C. Wyatt 
+37 
+Vice President-Software Products and Business Development 
+Christopher Galletta 
+33 
+Corporate Controller 
+25 
+Table of Contents 
+Bart C. Shuldman has been Chief Executive Officer, President and a Director of the Company since its formation in June 1996. In February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman relinquished the President title, effective June 1, 2010, to focus on new products and markets, international expansion and potential acquisitions. 
+Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. 
+Michael S. Kumpf was appointed Executive Vice President of Engineering in March 2002. He served as Senior Vice President, Engineering from June 1996 to March 2002. 
+Tracey S. Chernay was appointed Executive Vice President, Sales and Marketing in June 2010, with responsibility for the sales and marketing of all TransAct printer products, consumables, service and web sales worldwide. Previously, Ms. Chernay serves as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Sr. Vice President, Marketing & Sales, POS & Banking with the Company from July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. 
+Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice President, Operations from September 1994 to November 2004. 
+Benjamin C. Wyatt was appointed Vice President, Software Products and Business Development in December 2010. Previously, Mr. Wyatt served as Vice President, Business Development for TransAct from May 2008 to November 2010. Prior to joining TransAct, Mr. Wyatt was employed with Pitney Bowes Mail Services where he held the role of Director Business Development since 2006, and Manager Acquisitions and Integration from 2004 to 2006. 
+Christopher Galletta was appointed Corporate Controller in October 2007. Previously, Mr. Galletta served as TransAct’s Assistant Corporate Controller from June 2005 to September 2007. Prior to joining TransAct, Mr. Galletta was employed by PricewaterhouseCoopers LLP, an independent public accounting firm, most recently as a senior associate in the technology audit practice. 
+Item 11. Executive Compensation. 
+The information in response to this item is incorporated by reference from the Proxy Statement sections entitled “Executive Compensation and Certain Transactions” and “Compensation Discussion and Analysis.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Security Ownership of Certain Beneficial Owners and Management.” 
+Information regarding our equity compensation plans as of December 31, 2010 is as follows: 
+Plan category 
+(a) 
+Number of securities to be issued upon exercise of outstanding options, warrants and rights 
+(b) 
+Weighted-average exercise price of outstanding options, warrants and rights 
+(c) 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) 
+Equity compensation plans approved by security holders: 
+1996 Stock Plan 
+186,267 
+$ 
+3.76 
+- 
+1996 Non-Employee Director Plan 
+123,750 
+12.92 
+- 
+2005 Equity Incentive Plan 
+623,104 
+6.36 
+534,196 
+Total 
+933,121 
+$ 
+6.71 
+534,196 
+Equity compensation plans not approved by security holders: 
+2001 Employee Stock Plan 
+23,039 
+$ 
+5.42 
+- 
+956,160 
+$ 
+6.68 
+534,196 
+26 
+Table of Contents 
+The TransAct Technologies Incorporated 2001 Employee Stock Plan (the “2001 Employee Plan”) was adopted by our Board of Directors, without approval of our security holders, effective February 26, 2001. Under the 2001 Employee Plan, we may issue non-qualified stock options, shares of restricted stock, restricted units to acquire shares of common stock, stock appreciation rights and limited stock appreciation rights to key employees of TransAct or any of our subsidiaries and to non-employees who provide services to TransAct or any of our subsidiaries. The 2001 Employee Plan is administered by our Compensation Committee, which has the authority to determine the vesting period and other similar restrictions and terms of awards, provided that the exercise price of options granted under the plan may not be less than the fair market value of the underlying shares on the date of grant. 
+In May 2005, our shareholders approved the adoption of the 2005 Equity Incentive Plan. In May 2010, our shareholders approved an amendment to the 2005 Equity Incentive Plan to increase the number of shares of common stock which may be subject to awards granted under the plan from 600,000 to its current level of 1,200,000. No new awards will be available for future issuance under any of our existing equity plans other than the 2005 Equity Incentive Plan. 
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Certain Relationships and Related Transactions.” 
+Item 14. Principal Accountant Fees and Services. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Independent Registered Public Accounting Firm’s Services and Fees.” 
+PART IV 
+Item 15. Exhibits. 
+The exhibits filed as a part of this report are listed in the accompanying Index to Exhibits. 
+27 
+Table of Contents 
+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. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+By: 
+/s/ Bart C. Shuldman 
+Name: 
+Bart C. Shuldman 
+Title: 
+Chairman of the Board and Chief Executive Officer 
+Date: March 18, 2011 
+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/ Bart C. Shuldman 
+Chairman of the Board 
+March 18, 2011 
+Bart C. Shuldman 
+and Chief Executive Officer, 
+(Principal Executive Officer) 
+/s/ Steven A. DeMartino 
+President, Chief Financial Officer, 
+March 18, 2011 
+Steven A. DeMartino 
+Treasurer and Secretary 
+(Principal Financial Officer) 
+/s/ Christopher Galletta 
+Corporate Controller 
+March 18, 2011 
+Christopher Galletta 
+(Principal Accounting Officer) 
+/s/ Charles A. Dill 
+Director 
+March 18, 2011 
+Charles A. Dill 
+/s/ Thomas R. Schwarz 
+Director 
+March 18, 2011 
+Thomas R. Schwarz 
+/s/ Graham Y. Tanaka 
+Director 
+March 18, 2011 
+Graham Y. Tanaka 
+28 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX TO FINANCIAL STATEMENTS 
+Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Consolidated balance sheets as of December 31, 2010 and 20 0 9 
+F-3 
+Consolidated statements of income for the years ended December 31, 2010, 2009 and 200 8 
+F-4 
+Consolidated statements of changes in shareholders' equity and comprehensive income for the years ended December 31, 2010, 2009 and 200 8 
+F-5 
+Consolidated statements of cash flows for the years ended December 31, 2010, 2009 and 200 8 
+F-6 
+Notes to consolidated financial statements 
+F-7 
+All other financial statement schedules are omitted because they are not applicable or the required information is shown in the consolidated financial statements or notes thereto. 
+F-1 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To the Board of Directors and Shareholders of TransAct Technologies Incorporated: 
+In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TransAct Technologies Incorporated and its subsidiaries at December 31, 2010 and December 31, 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. 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 of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. 
+/s/ PricewaterhouseCoopers LLP 
+Hartford, Connecticut 
+March 18, 2011 
+F-2 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+December 31, 
+2010 
+2009 
+Assets: 
+Current assets: 
+Cash and cash equivalents 
+$ 
+11,285 
+$ 
+10,017 
+Receivables, net 
+10,864 
+8,996 
+Inventories 
+12,795 
+5,952 
+Refundable income taxes 
+- 
+270 
+Deferred tax assets 
+1,705 
+2,240 
+Other current assets 
+403 
+521 
+Total current assets 
+37,052 
+27,996 
+Fixed assets, net 
+4,200 
+4,551 
+Goodwill 
+1,469 
+1,469 
+Deferred tax assets 
+789 
+669 
+Intangible and other assets, net of accumulated amortization of $475 and $390, respectively 
+111 
+214 
+6,569 
+6,903 
+Total assets 
+$ 
+43,621 
+$ 
+34,899 
+Liabilities and Shareholders’ Equity: 
+Current liabilities: 
+Accounts payable 
+$ 
+8,342 
+$ 
+5,052 
+Accrued liabilities 
+2,865 
+1,890 
+Deferred revenue 
+320 
+580 
+Total current liabilities 
+11,527 
+7,522 
+Deferred revenue, net of current portion 
+295 
+501 
+Deferred rent, net of current portion 
+393 
+385 
+Other liabilities 
+272 
+137 
+960 
+1,023 
+Total liabilities 
+12,487 
+8,545 
+Commitments and contingencies (Note 11) 
+Shareholders’ equity: 
+Preferred stock, $0.01 par value, 4,800,000 authorized, none issued and outstanding 
+- 
+- 
+Preferred stock, Series A, $0.01 par value, 200,000 authorized, none issued and outstanding 
+- 
+- 
+Common stock, $0.01 par value, 20,000,000 authorized at December 31, 2010 and 2009; 10,612,881 and 10,528,209 shares issued; 9,426,443 and 9,364,109 shares outstanding, at December 31, 2010 and 2009, respectively 
+106 
+105 
+Additional paid-in capital 
+22,875 
+21,820 
+Retained earnings 
+16,937 
+13,033 
+Accumulated other comprehensive loss, net of tax 
+(69 
+) 
+(66 
+) 
+Treasury stock, 1,186,438 and 1,164,100 shares, at cost 
+(8,715 
+) 
+(8,538 
+) 
+Total shareholders’ equity 
+31,134 
+26,354 
+Total liabilities and shareholders’ equity 
+$ 
+43,621 
+$ 
+34,899 
+See accompanying notes to consolidated financial statements. 
+F-3 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF INCOME 
+(In thousands, except per share data) 
+Year Ended December 31, 
+2010 
+2009 
+2008 
+Net sales 
+$ 
+63,194 
+$ 
+58,346 
+$ 
+62,207 
+Cost of sales 
+40,646 
+39,517 
+41,257 
+Gross profit 
+22,548 
+18,829 
+20,950 
+Operating expenses: 
+Engineering, design and product development 
+3,000 
+2,788 
+2,942 
+Selling and marketing 
+6,407 
+5,821 
+6,078 
+General and administrative 
+7,280 
+6,924 
+7,040 
+Legal fees associated with lawsuit (See Note 11) 
+- 
+- 
+3,029 
+16,687 
+15,533 
+19,089 
+Operating income 
+5,861 
+3,296 
+1,861 
+Interest and other income (expense): 
+Interest expense 
+(96 
+) 
+(70 
+) 
+(70 
+) 
+Interest income 
+87 
+20 
+59 
+Other, net 
+(25 
+) 
+(33 
+) 
+368 
+(34 
+) 
+(83 
+) 
+357 
+Income before income taxes 
+5,827 
+3,213 
+2,218 
+Income tax provision 
+1,923 
+1,073 
+774 
+Net income 
+$ 
+3,904 
+$ 
+2,140 
+$ 
+1,444 
+Net income per common share: 
+Basic 
+$ 
+0.42 
+$ 
+0.23 
+$ 
+0.16 
+Diluted 
+$ 
+0.41 
+$ 
+0.23 
+$ 
+0.15 
+Shares used in per-share calculation: 
+Basic 
+9,390 
+9,289 
+9,308 
+Diluted 
+9,590 
+9,377 
+9,489 
+See accompanying notes to consolidated financial statements. 
+F-4 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME 
+(In thousands, except share data) 
+Common Stock 
+Additional Paid-in 
+Retained 
+Treasury 
+Accumulated Other Comprehensive 
+Total Comprehensive 
+Shares 
+Amount 
+Capital 
+Earnings 
+Stock 
+Income (Loss) 
+Total 
+Income 
+Balance, December 31, 2007 
+9,365,866 
+$ 
+104 
+$ 
+19,872 
+$ 
+9,449 
+$ 
+(7,995 
+) 
+$ 
+178 
+$ 
+21,608 
+Cancellation of restricted stock 
+(1,250 
+) 
+- 
+- 
+- 
+- 
+- 
+- 
+Issuance of shares from exercise of stock options 
+66,972 
+1 
+313 
+- 
+- 
+- 
+314 
+Tax charge related to vesting of restricted stock 
+- 
+- 
+(98 
+) 
+- 
+- 
+- 
+(98 
+) 
+Purchase of treasury stock 
+(130,100 
+) 
+- 
+- 
+- 
+(543 
+) 
+- 
+(543 
+) 
+Share-based compensation expense 
+- 
+- 
+803 
+- 
+- 
+- 
+803 
+Comprehensive income (loss): 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(246 
+) 
+(246 
+) 
+$ 
+(246 
+) 
+Net income 
+- 
+- 
+- 
+1,444 
+- 
+- 
+1,444 
+1,444 
+Balance, December 31, 2008 
+9,301,488 
+105 
+20,890 
+10,893 
+(8,538 
+) 
+(68 
+) 
+23,282 
+$ 
+1,198 
+Cancellation of restricted stock 
+(500 
+) 
+- 
+- 
+- 
+- 
+- 
+- 
+Issuance of shares from exercise of stock options 
+63,121 
+- 
+211 
+- 
+- 
+- 
+211 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+79 
+- 
+- 
+- 
+79 
+Share-based compensation expense 
+- 
+- 
+640 
+- 
+- 
+- 
+640 
+Comprehensive income: 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+2 
+2 
+$ 
+2 
+Net income 
+- 
+- 
+- 
+2,140 
+- 
+- 
+2,140 
+2,140 
+Balance, December 31, 2009 
+9,364,109 
+105 
+21,820 
+13,033 
+(8,538 
+) 
+(66 
+) 
+26,354 
+$ 
+2,142 
+Issuance of shares from exercise of stock options 
+84,672 
+1 
+392 
+- 
+- 
+- 
+393 
+Issuance of deferred stock units 
+- 
+- 
+77 
+- 
+- 
+- 
+77 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+21 
+- 
+- 
+- 
+21 
+Purchase of treasury stock 
+(22,338 
+) 
+- 
+- 
+- 
+(177 
+) 
+- 
+(177 
+) 
+Share-based compensation expense 
+- 
+- 
+565 
+- 
+- 
+- 
+565 
+Comprehensive income: 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(3 
+) 
+(3 
+) 
+$ 
+(3 
+) 
+Net income 
+- 
+- 
+- 
+3,904 
+- 
+- 
+3,904 
+3,904 
+Balance, December 31, 2010 
+9,426,443 
+$ 
+106 
+$ 
+22,875 
+$ 
+16,937 
+$ 
+(8,715 
+) 
+$ 
+(69 
+) 
+$ 
+31,134 
+$ 
+3,901 
+See accompanying notes to consolidated financial statements. 
+F-5 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+Year Ended December 31, 
+2010 
+2009 
+2008 
+Cash flows from operating activities: 
+Net income 
+$ 
+3,904 
+$ 
+2,140 
+$ 
+1,444 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Share-based compensation expense 
+565 
+640 
+803 
+Incremental tax benefits from stock options exercised 
+(21 
+) 
+(79 
+) 
+- 
+Depreciation and amortization 
+1,549 
+1,757 
+1,847 
+Deferred income taxes 
+540 
+1,002 
+592 
+Loss on sale of fixed assets 
+2 
+- 
+3 
+Foreign currency transaction (gain) loss 
+21 
+33 
+(368 
+) 
+Changes in operating assets and liabilities: 
+Receivables 
+(1,878 
+) 
+(263 
+) 
+(2,611 
+) 
+Inventories 
+(6,851 
+) 
+3,968 
+(1,257 
+) 
+Refundable income taxes 
+270 
+(235 
+) 
+14 
+Other current assets 
+116 
+(169 
+) 
+8 
+Other assets 
+1 
+34 
+29 
+Accounts payable 
+3,289 
+187 
+178 
+Accrued liabilities and other liabilities 
+625 
+(642 
+) 
+19 
+Net cash provided by operating activities 
+2,132 
+8,373 
+701 
+Cash flows from investing activities: 
+Purchases of fixed assets 
+(1,107 
+) 
+(643 
+) 
+(979 
+) 
+Proceeds from sale of assets 
+10 
+- 
+- 
+Net cash used in investing activities 
+(1,097 
+) 
+(643 
+) 
+(979 
+) 
+Cash flows from financing activities: 
+Proceeds from stock option exercises 
+393 
+211 
+314 
+Purchases of common stock for treasury 
+(177 
+) 
+- 
+(543 
+) 
+Incremental tax benefits from stock options exercised 
+21 
+79 
+- 
+Net cash provided by (used in) financing activities 
+237 
+290 
+(229 
+) 
+Effect of exchange rate changes on cash 
+(4 
+) 
+(3 
+) 
+(54 
+) 
+Increase (decrease) in cash and cash equivalents 
+1,268 
+8,017 
+(561 
+) 
+Cash and cash equivalents, beginning of period 
+10,017 
+2,000 
+2,561 
+Cash and cash equivalents, end of period 
+$ 
+11,285 
+$ 
+10,017 
+$ 
+2,000 
+Supplemental cash flow information: 
+Interest paid 
+$ 
+51 
+$ 
+51 
+$ 
+51 
+Income taxes paid 
+740 
+482 
+34 
+See accompanying notes to consolidated financial statements. 
+F-6 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. Description of business 
+TransAct Technologies Incorporated (“TransAct” or the “Company”), which has its headquarters in Hamden, CT and its primary operating facility in Ithaca, NY, operates in one operating segment: market-specific printers for transaction-based industries. These industries include casino, gaming, lottery, banking, kiosk and point-of-sale. Our printers are designed based on market-specific requirements and are sold under the Ithaca® and Epic product brands. We distribute our products through OEMs, value-added resellers, selected distributors, and directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. We also generate revenue from the after-market side of the business, providing printer service, supplies and spare parts. 
+2. Summary of significant accounting policies 
+Principles of consolidation: The accompanying consolidated financial statements were prepared on a consolidated basis to include the accounts of TransAct and its wholly-owned subsidiaries. All intercompany accounts, transactions and unrealized profit were eliminated in consolidation. 
+Reclassifications: Certain amounts in the prior years’ financial statements have been reclassified to conform to the current year’s presentation. 
+Use of estimates: The accompanying consolidated financial statements were prepared using estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 
+Segment reporting: We apply the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” We view our operations and manage our business as one segment: the design, development, manufacture and sale of transaction-based printers and printer-related service, supplies and replacement parts . Factors used to identify TransAct’s single operating segment include the organizational structure of the Company and the financial information available for evaluation by the chief operating decision-maker in making decisions about how to allocate resources and assess performance. 
+Cash and cash equivalents: We consider all highly liquid investments with a maturity date of three months or less at date of purchase to be cash equivalents. 
+Allowance for doubtful accounts: We establish an allowance for doubtful accounts to ensure trade receivables are valued appropriately. We maintain an allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, significant one-time events and historical experience. We record a specific allowance for individual accounts when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, we would further adjust estimates of the recoverability of receivables. Allowances for doubtful accounts on accounts receivable balances were $57,000 as of December 31, 2010 and 2009. 
+The following table summarizes the activity recorded in the valuation account for accounts receivable: 
+Year ended December 31, 
+(In thousands) 
+2010 
+2009 
+2008 
+Balance, beginning of period 
+$ 
+57 
+$ 
+55 
+$ 
+62 
+Additions charged to costs and expenses 
+- 
+3 
+- 
+Deductions 
+- 
+(1 
+) 
+(7 
+) 
+Balance, end of period 
+$ 
+57 
+$ 
+57 
+$ 
+55 
+Inventories: Inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. 
+Fixed assets: Fixed assets are stated at cost. Depreciation is recorded using the straight-line method over the estimated useful lives. The estimated useful life of tooling is five years; machinery and equipment is ten years; furniture and office equipment is five to ten years; and computer software and equipment is three to seven years. Leasehold improvements are amortized over the shorter of the term of the lease or the useful life of the asset. Costs related to repairs and maintenance are expensed as incurred. The costs of sold or retired assets are removed from the related asset and accumulated depreciation accounts and any gain or loss is recognized. Depreciation expense was $1,446,000, $1,655,000 and $1,744,000 in 2010, 2009 and 2008, respectively. 
+F-7 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Leases: Rent expense under non-cancelable operating leases with scheduled rent increases or free rent periods are accounted for on a straight-line basis over the lease term, beginning on the date of control of physical use of the asset or of initial possession. The amount of the excess of straight-line rent expense over scheduled payments is recorded as a deferred liability. Construction allowances and other such lease incentives are recorded as deferred credits, and are amortized on a straight-line basis as a reduction of rent expense beginning in the period they are deemed to be earned, which generally coincides with the occupancy date. 
+Goodwill: We account for goodwill in accordance with the provisions of ASC 350, “Intangibles - Goodwill and Other.” We test goodwill annually for impairment, or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. We have performed an impairment test as of December 31, 2010 and determined that no impairment has occurred. 
+Revenue recognition: Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within ASC 605, “Revenue Recognition” (ASC 605). Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms, which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We account for all revenue arrangements involving multiple deliverables in accordance with ASC 605-25, “Multiple-Element Arrangements.” For these arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Concentration of credit risk: Financial instruments that potentially expose TransAct to concentrations of credit risk are limited to cash and cash equivalents held by our banks in excess of insured limits and accounts receivable. 
+Accounts receivable from customers representing 10% or more of total accounts receivable were as follows: 
+December 31, 
+2010 
+2009 
+Customer A 
+17 
+% 
+24 
+% 
+Customer B 
+22 
+% 
+18 
+% 
+F-8 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Sales to customers representing 10% or more of total net sales were as follows: 
+Year ended December 31, 
+2010 
+2009 
+2008 
+Customer A 
+12 
+% 
+19 
+% 
+28 
+% 
+Customer B 
+14 
+% 
+10 
+% 
+* 
+Customer C 
+* 
+12 
+% 
+* 
+* -Customers represent less than 10% of total net sales 
+Warranty: We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. 
+The following table summarizes the activity recorded in the accrued product warranty liability: 
+Year ended December 31, 
+(In thousands) 
+2010 
+2009 
+2008 
+Balance, beginning of period 
+$ 
+233 
+$ 
+393 
+$ 
+500 
+Accruals for warranties issued during the period 
+84 
+112 
+297 
+Changes in estimates 
+172 
+(96 
+) 
+(34 
+) 
+Settlements during the period 
+(240 
+) 
+(176 
+) 
+(370 
+) 
+Balance, end of period 
+$ 
+249 
+$ 
+233 
+$ 
+393 
+Approximately $71,000 and $64,000 of the accrued product warranty liability were classified as long-term at December 31, 2010 and 2009, respectively. 
+Research and development expenses: Research and development expenses include engineering, design and product development expenses incurred in connection with specialized engineering and design to introduce new products and to customize existing products, and are expensed as a component of operating expenses as incurred. We recorded approximately $3,000,000, $2,788,000 and $2,942,000 of research and development expenses in 2010, 2009 and 2008, respectively. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established for the product. Once technological feasibility is established, all material software costs are capitalized within Intangible and other assets in our consolidated balance sheet until the product is available for general release to customers. Judgment is required in determining when technological feasibility of a product is established. We have determined that technological feasibility for our software products is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of revenue over the estimated life of the product. During 2010 we began the development of a new software product that enables casino customers to print coupons and promotions at the slot machine. As of December 31, 2010, we have capitalized $130,000 of developments costs for such software; there has been no amortization of capitalized software development costs. 
+Advertising: Advertising costs are expensed as incurred. Advertising expenses, which are included in selling and marketing expense on the accompanying consolidated statements of operations, for 2010, 2009 and 2008 totaled $824,000, $763,000 and $916,000, respectively. These expenses include items such as consulting and professional services, tradeshows, and print advertising. 
+Restructuring: We continually evaluate our cost structure to ensure that it is appropriately positioned to respond to changing market conditions. We record pre-tax restructuring charges in accordance with ASC 420-10-25-4, “Exit or Disposal Cost Obligations.” 
+Income taxes: The income tax amounts reflected in the accompanying financial statements are accounted for under the liability method in accordance with ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. We assess the likelihood that net deferred tax assets will be realized 
+F-9 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. In accordance with ASC 740, we identified, evaluated and measured the amount of benefits to be recognized for our tax return positions. See Note 13 for information regarding our accounting for income taxes. 
+Foreign currency translation: The financial position and results of operations of our foreign subsidiary in the United Kingdom are measured using local currency as the functional currency. Assets and liabilities of such subsidiary have been translated into U.S. dollars at the year-end exchange rate, related revenues and expenses have been translated at the average exchange rate for the year, and shareholders’ equity has been translated at historical exchange rates. The resulting translation gains or losses, net of tax, are recorded in stockholders’ equity as a cumulative translation adjustment, which is a component of accumulated other comprehensive income. Foreign currency transaction gains and losses, including those related to intercompany balances, are recognized in other income (expense). 
+Comprehensive income: ASC 220, “Comprehensive Income,” requires that items defined as comprehensive income or loss be separately classified in the financial statements and that the accumulated balance of other comprehensive income or loss be reported separately from accumulated deficit and additional paid-in-capital in the equity section of the balance sheet. We include the foreign currency translation adjustment, net of tax, related to our subsidiary in the United Kingdom within our calculation of comprehensive income. 
+Share-based Payments: At December 31, 2010, we had stock-based employee compensation plans, which are described more fully in Note 12 - Stock incentive plans. We account for those plans under the recognition and measurement principles of ASC 718, “Compensation – Stock Compensation.” Share-based compensation expense is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. We have no awards with market or performance conditions. 
+We use the Black-Scholes option-pricing model to calculate the fair value of share based awards. The key assumptions for this valuation method include the expected term of the option, stock price volatility, risk-free interest rate, dividend yield, market price of our underlying stock and exercise price. Many of these assumptions are judgmental and highly sensitive in the determination of compensation expense. In addition, we estimate forfeitures when recognizing compensation expense, and we adjust our estimate of forfeitures over the requisite service period based on the extent to which actual forfeitures differ, or are expected to differ, from such estimates. Changes in estimated forfeitures are recognized through a cumulative true-up adjustment in the period of change and also impacts the amount of compensation expense to be recognized in future periods. 
+Net income and loss per share: We report net income or loss per share in accordance with ASC 260, “Earnings per Share (EPS).” Under this guidance, basic EPS, which excludes dilution, is computed by dividing income or loss available to common shareholders by the weighted average number of common shares outstanding for the period. Unvested restricted stock is excluded from the calculation of weighted average common shares for basic EPS. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted EPS includes restricted stock and in-the-money stock options using the treasury stock method. During a loss period, the assumed exercise of in-the-money stock options has an anti-dilutive effect, and therefore, these instruments are excluded from the computation of dilutive EPS. See Note 14 - Earnings per Share. 
+3. Recently issued accounting pronouncements 
+Multiple-Deliverable Revenue Arrangements: In October 2009, the FASB established the accounting and reporting guidance for arrangements including multiple revenue-generating activities. This guidance provides amendments to the criteria for separating deliverables, measuring and allocating arrangement consideration to one or more units of accounting. The amendments also establish a selling price hierarchy for determining the selling price of a deliverable. Significantly enhanced disclosures are also required to provide information about a vendor’s multiple-deliverable revenue arrangements, including information about the nature and terms, significant deliverables, and its performance within arrangements. The amendments also require providing information about the significant judgments made and changes to those judgments and about how the application of the relative selling-price method affects the timing or amount of revenue recognition. The amendments are effective prospectively for revenue arrangements entered into or materially modified in the fiscal years beginning on or after June 15, 2010. Early application is permitted. Currently these provisions do not have an impact on our consolidated financial statements and we do not anticipate these provisions will have a material impact on our consolidated financial statements. 
+Financing Receivables: In July 2010 the FASB issued new accounting guidance to improve the disclosures that an entity provides about the credit quality of its financing receivables and the related allowance for credit losses. Accounts receivable with terms exceeding one year are considered finance receivables subject to the provisions of this standard. Our trade receivables, which arose from the sale of goods or services, 
+F-10 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+3. Recently issued accounting pronouncements (continued) 
+have a contractual maturity of one year or less and therefore are not subject to the provisions of this standard. We do not have any significant receivables with a term exceeding one year and as a result, the standard does not have a material impact on us. 
+4. Inventories 
+The components of inventories are: 
+December 31, 
+(In thousands) 
+2010 
+2009 
+Raw materials and purchased component parts 
+$ 
+5,077 
+$ 
+4,466 
+Work-in-process 
+2 
+2 
+Finished goods 
+7,716 
+1,484 
+$ 
+12,795 
+$ 
+5,952 
+5. Fixed assets 
+The components of fixed assets, net are: 
+December 31, 
+(In thousands) 
+2010 
+2009 
+Tooling, machinery and equipment 
+$ 
+12,825 
+$ 
+13,721 
+Furniture and office equipment 
+1,659 
+1,704 
+Computer software and equipment 
+5,124 
+4,922 
+Leasehold improvements 
+1,888 
+1,874 
+21,496 
+22,221 
+Less: Accumulated depreciation and amortization 
+(17,296 
+) 
+(17,670 
+) 
+$ 
+4,200 
+$ 
+4,551 
+6. Intangible assets 
+Identifiable intangible assets are recorded in Intangible and other assets in the accompanying consolidated balance sheets. Identifiable intangible assets are comprised of the following: 
+December 31, 
+2010 
+2009 
+(In thousands) 
+Gross Amount 
+Accumulated Amortization 
+Gross Amount 
+Accumulated Amortization 
+Purchased technology 
+$ 
+364 
+$ 
+(334 
+) 
+$ 
+364 
+$ 
+(273 
+) 
+Covenant not to compete 
+146 
+(115 
+) 
+146 
+(94 
+) 
+Patents 
+57 
+(26 
+) 
+57 
+(23 
+) 
+Total 
+$ 
+567 
+$ 
+(475 
+) 
+$ 
+567 
+$ 
+(390 
+) 
+Amortization expense was $85,000 in 2010 and $84,000 in 2009 and 2008, respectively. Amortization expense for each of the next five years ending December 31 is expected to be as follows: $54,000 in 2011; $13,000 in 2012; $3,000 in 2013; $3,000 in 2014; $3,000 in 2015; and $16,000 thereafter. 
+7. Accrued liabilities 
+The components of accrued liabilities (current portion) are: 
+F-11 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+7. Accrued liabilities (continued) 
+December 31, 
+(In thousands) 
+2010 
+2009 
+Payroll and fringe benefits 
+$ 
+1,736 
+$ 
+1,189 
+Income taxes 
+359 
+6 
+Warranty 
+178 
+169 
+Professional and consulting 
+111 
+171 
+Other 
+481 
+355 
+$ 
+2,865 
+$ 
+1,890 
+8. Accrued business consolidation and restructuring expenses 
+In 2009, due to an adverse economic climate, and in 2010, due to the completion of the move of a substantial portion of our printer production to a contract manufacturer in China, we initiated and completed certain restructuring programs to better utilize our workforce. These restructuring activities reduced the number of employees and caused us to incur costs for employee termination benefits related to the employee reductions. During 2010 and 2009, we recorded pre-tax restructuring charges of approximately $156,000 and $211,000, respectively, in accordance with ASC 420-10-25-4, “Exit or Disposal Cost Obligations.” These one-time termination benefit charges have been included within general and administrative expenses in the accompanying consolidated statements of income. The restructuring activity during 2010 and 2009 included severance costs related to the termination of 16 and 17 employees, respectively. 
+The following table summarizes the activity recorded in accrued restructuring expenses during 2010 and 2009, and is included in accrued liabilities in the accompanying consolidated balance sheets. 
+December 31, 
+(In thousands) 
+2010 
+2009 
+Accrual balance, beginning of period 
+$ 
+13 
+$ 
+18 
+Severance charges 
+156 
+211 
+Cash payments 
+(169 
+) 
+(216 
+) 
+Accrual balance, end of period 
+$ 
+- 
+$ 
+13 
+9. Retirement savings plan 
+We maintain a 401(k) plan under which all full-time employees are eligible to participate at the beginning of each month immediately following their date of hire. We match employees’ contributions at a rate of 50% of employees’ contributions up to the first 6% of the employees’ compensation contributed to the 401(k) plan. Our matching contributions were $223,000, $237,000 and $244,000 in 2010, 2009 and 2008, respectively. 
+10. Borrowings 
+On November 28, 2006, we signed a five-year $20,000,000 credit facility (the “TD Bank Credit Facility”) with TD Bank. The TD Bank Credit Facility provides for a $20,000,000 revolving credit line expiring on November 28, 2011. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent and are collateralized by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the revolving credit line. The total deferred financing costs relating to expenses incurred to complete the TD Bank Credit Facility was $94,000. The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur indebtedness, the payment of dividends on our common stock and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2010. 
+As of December 31, 2010, we had no outstanding borrowings on the revolving credit line. Undrawn commitments under the TD Bank Credit Facility were $20,000,000 at December 31, 2010. 
+11. Commitments and contingencies 
+We had been involved in patent litigation with FutureLogic, Inc. (“FutureLogic”) with respect to our patents U.S. Patent 6,924,903 and U.S. Patent 7,099,035. On May 13, 2008, we signed a Patent License and Settlement Agreement with FutureLogic that settled the current patent litigation and all other legal matters outstanding between the two parties. Under the Patent License and Settlement Agreement, FutureLogic agreed to license our dual port technology for printers and upgrade kits that utilize the patented technology. The license grants FutureLogic worldwide, perpetual rights for U.S. Patent 6,924,903, U.S. Patent 7,099,035, related applications and patents, and foreign counterparts. 
+F-12 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+11. Commitments and contingencies (continued) 
+At December 31, 2010, we were the lessee on operating leases for equipment and real property. Rent expense was approximately $1,047,000, $1,024,000 and $1,030,000 in 2010, 2009 and 2008, respectively. Minimum aggregate rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2010 are as follows: $952,000 in 2011; $598 ,000 in 2012; $360,000 in 2013; $365,000 in 2014; $375,000 in 2015; and $460,000 thereafter. 
+12. Stock incentive plans 
+Stock incentive plans . We currently have four primary stock incentive plans: the 1996 Stock Plan, which provided for the grant of awards to officers and other key employees of the Company; the 1996 Directors’ Stock Plan, which provided for non-discretionary awards to non-employee directors; the 2001 Employee Stock Plan, which provided for the grant of awards to key employees of the Company and other non-employees who provided services to the Company; and the 2005 Equity Incentive Plan, which provides for awards to executives, key employees, directors and consultants. The plans generally provide for awards in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units, (v) stock appreciation rights or (vi) limited stock appreciation rights. However, the 2001 Employee Stock Plan does not provide for incentive stock option awards. Options granted under these plans have exercise prices equal to 100% of the fair market value of the common stock at the date of grant. Options granted have a ten-year term and generally vest over a three- to five-year period, unless automatically accelerated for certain defined events. As of May 2005, no new awards will be made under the 1996 Stock Plan, the 1996 Directors’ Stock Plan or the 2001 Employee Stock Plan. Under our 2005 Equity Incentive Plan, we may authorize up to 1,200,000 of shares of TransAct common stock. At December 31, 2010, approximately 534,196 shares of common stock remained available for issuance under the 2005 Equity Incentive Plan. 
+Under the assumptions indicated below, the weighted-average fair value of stock option grants for the years ended December 31, 2010, 2009 and 2008 was $7.45, $2.56 and $5.85, respectively. The table below indicates the key assumptions used in the option valuation calculations for options granted in the years ended December 31, 2010, 2009 and 2008 and a discussion of our methodology for developing each of the assumptions used in the valuation model: 
+Year ended December 31, 
+2010 
+2009 
+2008 
+Expected option term 
+6.1 years 
+6.0 years 
+5.7 years 
+Expected volatility 
+66.8 
+% 
+67.4 
+% 
+61.7 
+% 
+Risk-free interest rate 
+2.3 
+% 
+2.0 
+% 
+3.0 
+% 
+Dividend yield 
+0 
+% 
+0 
+% 
+0 
+% 
+Expected Option Term - This is the weighted average period of time over which the options granted are expected to remain outstanding giving consideration to our historical exercise patterns. Options granted have a maximum term of ten years. An increase in the expected term will increase compensation expense. 
+Expected Volatility – The stock volatility for each grant is measured using the weighted average of historical daily price changes of our common stock over the most recent period approximately equal to the expected option term of the grant. An increase in the expected volatility factor will increase compensation expense. 
+Risk-Free Interest Rate - This is the U.S. Treasury rate in effect at the time of grant having a term approximately equal to the expected term of the option. An increase in the risk-free interest rate will increase compensation expense. 
+Dividend Yield - We have not made any dividend payments on our common stock, and we have no plans to pay dividends in the foreseeable future. An increase in the dividend yield will decrease compensation expense. 
+For the years ending December 31, 2010, 2009 and 2008, we recorded $565,000, $640,000, and $803,000 of share-based compensation costs, respectively, in our consolidated statements of income. We recorded income tax benefits of $186,000, $214,000, and $280,000 in 2010, 2009, and 2008 respectively, related to share-based compensation. At December 31, 2010, these benefits are recorded as a deferred tax asset in the consolidated balance sheet. 
+The 1996 Stock Plan, 1996 Directors’ Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan option activity is summarized below: 
+F-13 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+12. Stock incentive plans (continued) 
+Number of Shares 
+Weighted Average Exercise Price 
+Weighted Average Remaining Contractual Term 
+Aggregate Intrinsic Value 
+Outstanding at December 31, 2009 
+939,028 
+$ 
+6.37 
+Granted 
+127,500 
+7.45 
+Exercised 
+(84,672 
+) 
+4.64 
+Forfeited 
+(28,900 
+) 
+5.04 
+Expired 
+(10,000 
+) 
+8.35 
+Outstanding at December 31, 2010 
+942,956 
+$ 
+6.69 
+5.4 years 
+$ 
+3,376,000 
+Options exercisable at December 31, 2010 
+550,956 
+$ 
+7.27 
+3.5 years 
+$ 
+1,983,000 
+Options vested or expected to vest 
+905,402 
+$ 
+6.72 
+5.2 years 
+$ 
+3,249,000 
+Shares that are issued upon exercise of employee stock options are newly issued shares and not issued from treasury stock. As of December 31, 2010, unrecognized compensation cost related to stock options totaled $1,019,000, which is expected to be recognized over a weighted average period of 3.2 years. 
+The total intrinsic value of stock options exercised was $299,000, $161,000 and $402,000 and the total fair value of stock options vested was $424,000, $341,000, and $247,000 during the years ended December 31, 2010, 2009 and 2008, respectively. Cash received from option exercises were $393,000, $211,000 and $314,000 for 2010, 2009 and 2008, respectively. We recorded a realized tax benefit in 2010 from equity-based awards of $21,000 related to options exercised which has been included as a component of cash flows from financing activities in the consolidated statement of cash flows. 
+Restricted stock: Under the 1996 Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan, we have granted shares of restricted common stock, for no consideration, to our officers, directors and certain key employees. R estricted stock activity for the 1996 Stock Plan , 2001 Employee Stock Plan and 2005 Equity Incentive Plan is summarized below: 
+Shares 
+Weighted Average Grant Date Fair Values 
+Nonvested shares at December 31, 2009 
+23,000 
+$ 
+10.97 
+Granted 
+- 
+- 
+Vested 
+(20,000 
+) 
+10.55 
+Canceled 
+- 
+- 
+Nonvested shares at December 31, 2010 
+3,000 
+$ 
+13.78 
+As of December 31, 2010, unrecognized compensation cost related to restricted stock totaled $20,000, which is expected to be recognized over a weighted average period of less than 1 year. 
+We paid a portion of the 2009 incentive bonus for the chief executive officer and chief financial officer in the form of 10,204 deferred stock units with a corresponding credit recorded to Additional Paid in Capital in the amount of $77,000. Such deferred stock units were granted in March 2010 and were fully vested at the time of grant. These units will be converted three years from the grant date to shares of the Company’s common stock on a one-for-one basis. The weighted average exercise price of the deferred stock units was $7.54, the aggregate intrinsic value was $19,000 and the weighted average remaining contractual term was 2.2 years. 
+13. Income taxes 
+The components of the income tax provision are as follows: 
+F-14 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Income taxes (continued) 
+Year Ended December 31, 
+(In thousands) 
+2010 
+2009 
+2008 
+Current: 
+Federal 
+$ 
+1,297 
+$ 
+53 
+$ 
+- 
+State 
+51 
+13 
+16 
+Foreign 
+35 
+5 
+166 
+Deferred: 
+Federal 
+457 
+891 
+386 
+State 
+82 
+110 
+207 
+Foreign 
+1 
+1 
+(1 
+) 
+Income tax provision 
+$ 
+1,923 
+$ 
+1,073 
+$ 
+774 
+At December 31, 2010, we have $285,000 of state net operating loss carryforwards that begin to expire in 2027, and no federal net operating loss carryforwards. We also have approximately $99,000 in state tax credit carryforwards that begin to expire in 2010. We had foreign income (loss) before taxes of $35,000, ($49,000) and $541,000 in 2010, 2009 and 2008, respectively. 
+Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Our gross deferred tax assets and liabilities were comprised of the following: 
+December 31, 
+(In thousands) 
+2010 
+2009 
+Deferred tax assets: 
+Net operating losses 
+$ 
+114 
+$ 
+129 
+Capitalized research and development 
+273 
+342 
+Inventory reserves 
+1,210 
+1,066 
+Deferred revenue 
+176 
+91 
+Warranty reserve 
+87 
+82 
+Stock compensation expense 
+586 
+421 
+Foreign tax and other credits 
+65 
+913 
+Other liabilities and reserves 
+562 
+435 
+Gross deferred tax assets 
+3,073 
+3,479 
+Valuation allowance 
+(125 
+) 
+(76 
+) 
+Net deferred tax assets 
+2,948 
+3,403 
+Gross deferred tax liabilities: 
+Depreciation 
+392 
+453 
+Other 
+62 
+41 
+Net deferred tax liabilities 
+454 
+494 
+Total net deferred tax assets 
+$ 
+2,494 
+$ 
+2,909 
+The following table summarizes the activity recorded in the valuation allowance on the deferred tax assets: 
+Year ended December 31, 
+(In thousands) 
+2010 
+2009 
+2008 
+Balance, beginning of period 
+$ 
+76 
+$ 
+26 
+$ 
+- 
+Additions charged to income tax expense 
+55 
+50 
+26 
+Reductions credited to income tax expense 
+(6 
+) 
+- 
+- 
+Balance, end of period 
+$ 
+125 
+$ 
+76 
+$ 
+26 
+Differences between the U.S. statutory federal income tax rate and our effective income tax rate are analyzed below: 
+F-15 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Income taxes (continued) 
+Year Ended December 31, 
+2010 
+2009 
+2008 
+Federal statutory tax rate 
+34.0 
+% 
+34.0 
+% 
+34.0 
+% 
+State income taxes, net of federal income taxes 
+1.5 
+2.5 
+6.6 
+Tax benefit from tax credits, net of valuation allowance 
+(2.9 
+) 
+(4.5 
+) 
+(5.6 
+) 
+Foreign rate differential 
+- 
+- 
+(2.4 
+) 
+Valuation allowance and tax accruals 
+0.8 
+0.8 
+1.2 
+Permanent items 
+(0.2 
+) 
+0.7 
+1.4 
+Other 
+(0.2 
+) 
+- 
+(0.3 
+) 
+Effective tax rate 
+33.0 
+% 
+33.5 
+% 
+34.9 
+% 
+At December 31, 2010 and 2009, we had approximately $201,000 and $189,000 of total gross unrecognized tax benefits that, if recognized, would favorably affect the effective income tax rate in any future periods. We are not aware of any events that could occur within the next twelve months that could cause a significant change in the total amount of unrecognized tax benefits. A tabular reconciliation of the gross amounts of unrecognized tax benefits at the beginning and end of the year is as follows: 
+(In thousands) 
+2010 
+2009 
+Unrecognized tax benefits as of January 1 
+$ 
+189 
+$ 
+160 
+Tax positions taken during the current period 
+61 
+29 
+Settlements 
+- 
+- 
+Lapse of statute of limitations 
+(49 
+) 
+- 
+Unrecognized tax benefits as of December 31 
+$ 
+201 
+$ 
+189 
+We are subject to U.S. federal income tax as well as income tax of certain state and foreign jurisdictions. We have substantially concluded all U.S. federal income tax, state and local, and foreign tax matters through 2003. During 2008, a limited scope examination of our 2005 and 2006 federal tax returns was completed. However, our federal tax returns for the years 2004 through 2009 remain open to examination. Various state and foreign tax jurisdiction tax years remain open to examination as well, though we believe that any additional assessment would be immaterial to the consolidated financial statements. No federal, state or foreign tax jurisdiction income tax returns are currently under examination. 
+We do not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2011. 
+We recognize interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2010 and 2009, we have approximately $4,000 and $12,000 of accrued interest and penalties related to uncertain tax positions. 
+14. Earnings per share 
+For 2010, 2009 and 2008, earnings per share were computed as follows (in thousands, except per share amounts): 
+F-16 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+14. Earnings per share (continued) 
+Year Ended December 31, 
+2010 
+2009 
+2008 
+Net income 
+$ 
+3,904 
+$ 
+2,140 
+$ 
+1,444 
+Shares: 
+Basic: Weighted average common shares outstanding 
+9,390 
+9,289 
+9,308 
+Add: Dilutive effect of outstanding options as determined by the treasury stock method 
+200 
+88 
+181 
+Diluted: Weighted average common and common equivalent shares outstanding 
+9,590 
+9,377 
+9,489 
+Net income per common share: 
+Basic 
+$ 
+0.42 
+$ 
+0.23 
+$ 
+0.16 
+Diluted 
+0.41 
+0.23 
+0.15 
+We compute earnings per share using the two-class method, which is an earnings allocation formula that determines earnings per share for common stock and participating securities. Restricted stock granted by the Company is considered a participating security since it contains a non-forfeitable right to dividends. 
+Certain stock-based awards were not included in the full year computation of earnings per diluted share because the effect would be anti-dilutive. Anti-dilutive stock options, restricted shares and deferred stock units excluded from the computation of earnings per dilutive share were 367,750, 525,500, and 258,250, at December 31, 2010, 2009 and 2008 respectively. 
+15. Stock repurchase program 
+On May 27, 2010, our Board of Directors approved a new stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we are authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending May 27, 2013, depending on market conditions, share price and other factors. As of December 31, 2010, we repurchased a total of 22,338 shares of common stock for approximately $177,000 under this program, at an average price of $7.95 per share. As of December 31, 2010, we repurchased a total of 1,186,438 shares of common stock for approximately $8,715,000 under all of our stock repurchase programs, at an average price of $7.35 per share. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. 
+16. Geographic Area Information 
+Information regarding our operations by geographic area is contained in the following table. These amounts in the geographic area table are based on the location of the customer and vendor. 
+Year Ended December 31, 
+(In thousands) 
+2010 
+2009 
+2008 
+Net sales: 
+United States 
+$ 
+44,101 
+$ 
+45,890 
+$ 
+52,081 
+International 
+19,093 
+12,456 
+10,126 
+Total 
+$ 
+63,194 
+$ 
+58,346 
+$ 
+62,207 
+Fixed assets, net: 
+United States 
+$ 
+2,823 
+$ 
+3,395 
+$ 
+4,190 
+International 
+1,377 
+1,156 
+1,373 
+Total 
+$ 
+4,200 
+$ 
+4,551 
+$ 
+5,563 
+Sales to international customers were 30%, 21%, and 16% in 2010, 2009, and 2008 respectively. Sales to Europe represented 43%, 45%, and 56%, sales to the Pacific Rim (which includes Australia and Asia) represented 18%, 31%, and 21%, and sales to Canada represented 20%, 11%, and 8% of total international sales in 2010, 2009, and 2008 respectively. International long-lived assets consist of net fixed assets located at our foreign subsidiary in the United Kingdom as well as our contract manufacturers in China, Malaysia and Mexico. 
+F-17 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+17. Quarterly results of operations (unaudited) 
+Our quarterly results of operations for 2010 and 2009 are as follows: 
+Quarter Ended 
+(In thousands, except per share amounts) 
+March 31 
+June 30 
+September 30 
+December 31 
+2010: 
+Net sales 
+$ 
+14,208 
+$ 
+16,443 
+$ 
+16,369 
+$ 
+16,174 
+Gross profit 
+5,189 
+6,155 
+5,557 
+5,647 
+Net income 
+629 
+1,145 
+1,052 
+1,078 
+Net income per share: 
+Basic 
+0.07 
+0.12 
+0.11 
+0.12 
+Diluted 
+0.07 
+0.12 
+0.11 
+0.11 
+2009: 
+Net sales 
+$ 
+12,202 
+$ 
+14,236 
+$ 
+17,982 
+$ 
+13,926 
+Gross profit 
+4,126 
+4,856 
+5,525 
+4,322 
+Net income 
+121 
+649 
+1,184 
+186 
+Net income per share: 
+Basic 
+0.01 
+0.07 
+0.13 
+0.02 
+Diluted 
+0.01 
+0.07 
+0.13 
+0.02 
+F-18 
+Table of Contents 
+Index to Exhibits 
+3.1(a) 
+Certificate of Incorporation of TransAct Technologies Incorporated (“TransAct” or the “Company”), filed with the Secretary of State of Delaware on June 17, 1996. 
+(2) 
+3.1(b) 
+Certificate of Amendment of Certificate of Incorporation of the Company, filed with the Secretary of State of Delaware on June 4, 1997. 
+(4) 
+3.1(c) 
+Certificate of Designation, Series A Preferred Stock, filed with the Secretary of State of Delaware on December 2, 1997. 
+(5) 
+3.1(d) 
+Certificate of Designation, Series B Preferred Stock, filed with the Secretary of State of Delaware on April 6, 2000. 
+(8) 
+3.2 
+Amended and Restated By-laws of the Company. 
+(6) 
+4.1 
+Specimen Common Stock Certificate. 
+(2) 
+10.1(x) 
+1996 Stock Plan, effective July 30, 1996. 
+(3) 
+10.2(x) 
+Non-Employee Directors’ Stock Plan, effective August 22, 1996. 
+(3) 
+10.3(x) 
+2001 Employee Stock Plan. 
+(9) 
+10.4(x) 
+2005 Equity Incentive Plan. 
+(14) 
+10.5(x) 
+Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. Shuldman. 
+(2) 
+10.6(x) 
+Severance Agreement by and between TransAct and Michael S. Kumpf, dated September 4, 1996. 
+(3) 
+10.7(x) 
+Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, 2004. 
+(13) 
+10.8(x) 
+Severance Agreement by and between TransAct and Tracey S. Chernay, dated July 29, 2005. 
+(18) 
+10.9(x) 
+Amendment to Employment Agreement, effective January 1, 2008, by and between TransAct and Bart C. Shuldman. 
+(19) 
+10.10(x) 
+Amendment to Severance Agreement by and between TransAct and Michael S. Kumpf, effective January 1, 2008. 
+(19) 
+10.11(x) 
+Amendment to Severance Agreement by and between TransAct and Steven A. DeMartino, effective January 1, 2008. 
+(19) 
+10.12(x) 
+Amendment to Severance Agreement by and between TransAct and Tracey S. Chernay, effective January 1, 2008. 
+(19) 
+10.13 
+Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, 1992. 
+(2) 
+10.14 
+Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated December 2, 1996. 
+(4) 
+10.15 
+Agreement regarding the Continuation and Renewal of Lease by and between Bomax Properties, LLC and TransAct, dated July 18, 2001. 
+(11) 
+10.16 
+Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated December 2, 2004. 
+(13) 
+10.17 
+First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 
+(20) 
+10.18 
+Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated November 27, 2006. 
+(16) 
+10.19 
+OEM Purchase Agreement by and between GTECH Corporation, TransAct and Magnetec Corporation commencing July 14, 1999. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(7) 
+10.20 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct commencing July 2, 2002. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(10) 
+10.21 
+Amendment to OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated February 17, 2006. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(15) 
+10.22 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated November 20, 2009. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy) 
+(20) 
+10.23 
+Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. dated November 28, 2006 
+(16) 
+10.24 
+First Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. effective September 30, 2007. 
+(17) 
+Table of Contents 
+10.25 
+License Agreement between Seiko Epson Corporation and TransAct dated May 17, 2004 (Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(12) 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+(1) 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+(1) 
+These exhibits are filed herewith. 
+(2) 
+These exhibits, which were previously filed with the Company’s Registration Statement on Form S-1 (No. 333-06895), are incorporated by reference. 
+(3) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1996, are incorporated by reference. 
+(4) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1997, are incorporated by reference. 
+(5) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed February 18, 1999, is incorporated by reference. 
+(6) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1998, is incorporated by reference. 
+(7) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 25, 1999, is incorporated by reference. 
+(8) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended March 25, 2000, are incorporated by reference. 
+(9) 
+This exhibit, which was previously filed with the Company’s Registration Statement on Form S-8 (No. 333-59570), is incorporated by reference. 
+(10) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002, is incorporated by reference. 
+(11) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003, is incorporated by reference. 
+(12) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004, is incorporated by reference. 
+(13) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, are incorporated by reference. 
+(14) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed June 1, 2005, is incorporated by reference. 
+(15) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, is incorporated by reference. 
+(16) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, are incorporated by reference. 
+(17) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1997, is incorporated by reference. 
+(18) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, is incorporated by reference. 
+(19) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, is incorporated by reference. 
+(20) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, is incorporated by reference. 
+Table of Contents 
+(x) 
+Management contract or compensatory plan or arrangement. 
+Table of Contents 
+EXHIBIT LIST 
+The following exhibits are filed herewith. 
+Exhibit 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/filing_metadata.csv b/raw/filings/0001017303/2010/0001017303-11-000006/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..ad24f45db39c457e5186ae3d7ca1ae661c14c334
--- /dev/null
+++ b/raw/filings/0001017303/2010/0001017303-11-000006/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
+0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2011-03-18,2010-12-31,2011-03-18T19:42:34.000Z,0001017303-11-000006,form10k.htm,FORM 10-K,1847010,0,0,https://www.sec.gov/Archives/edgar/data/1017303/000101730311000006/form10k.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730311000006/,2010,2010,1
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/item1.txt b/raw/filings/0001017303/2010/0001017303-11-000006/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5c6c6add45eef51ca63e21ce83239714128b994f
--- /dev/null
+++ b/raw/filings/0001017303/2010/0001017303-11-000006/item1.txt
@@ -0,0 +1,81 @@
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops, assembles, markets and services world-class transaction-based printers under the Epic and Ithaca® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers generate top-quality transaction records such as receipts, tickets, coupons, register journals and other documents. We focus on the following core markets: banking and point-of-sale (“POS”), casino and gaming, and lottery. We sell our products to original equipment manufacturers ("OEMs"), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, Latin America, the Caribbean Islands and the South Pacific. Beyond printers, TransAct is a leader in providing printing supplies to the full transaction printer market. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the hospitality, banking, retail, gaming, and government markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating facility and eastern region service center located in Ithaca, NY, our printer sales headquarters and western region service center in Las Vegas, NV, a printhead manufacturing and repair center located in New Britain, CT, a European sales and service center in the United Kingdom, a sales office located in Macau and two other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518, with a telephone number of (203) 859-6800. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction-based printers and printer-related service, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers 
+TransAct designs, develops, assembles and markets a broad array of transaction-based printers utilizing inkjet, thermal and impact printing technology for applications requiring up to 60 character columns, primarily in the banking, POS, casino, gaming and lottery markets. Our printers are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Banking and POS: Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of our internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals that print tickets or receipts instead of issuing coins at casinos, racetracks and other gaming establishments worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that allows casinos to print coupons and promotions. In addition, we sell printers using thermal and impact printing technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through regional distributors (four in the United States and Asia, one in Europe and Africa, two in Latin America and one in Australia). We also maintain a dedicated internal sales force to solicit sales from slot manufacturers and casinos, as well as to manage sales through our distributors. 
+1 
+Table of Contents 
+TSG 
+Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper and other transaction supplies), replacement parts and maintenance services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. During 2009, we completed a program to transfer final assembly for approximately 70% of our total printer production to a third-party contract manufacturer in China. We continue to perform final assembly for the remaining 30% of our products in our Ithaca, NY facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY. Critical component parts and subassemblies include inkjet, thermal and impact printheads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturer, purchases of component parts have declined while purchases of fully-assembled printers produced by our contract manufacturer have increased. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturer, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2011 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges that are compatible with the HP inkjet cartridge are available, the loss of the supply of HP inkjet cartridges could have a material adverse effect on both the sale of our inkjet printers and TSG consumable products. Our relationship with HP remains strong and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be any less favorable than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+Patents and Proprietary Information 
+We have significantly expanded our patent portfolio since 2002, and expect to continue to do so in the future. We also believe our patent portfolio could provide additional opportunities to license our intellectual property in the future. We hold 25 United States and 26 foreign patents and have 14 United States and 28 foreign patent applications pending pertaining to our products. The duration of these patents range from 7 to 15 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain 
+manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+2 
+Table of Contents 
+Seasonality 
+Retailers typically reduce purchases of new POS equipment in the fourth quarter due to the increased volume of consumer transactions in that holiday period, and our sales of printers in the POS market historically have increased in the third quarter and decreased in the fourth quarter. Similarly, installations of lottery terminals are typically reduced in the fourth quarter, resulting in decreased sales of lottery printers. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH is our most significant customer. We currently have an ongoing OEM purchase agreement, as amended in February 2006 (the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of thermal on-line lottery printers and spare parts, at fixed prices, through June 28, 2012. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH New Thermal Printer Agreement”). Under the terms of the new agreement, we will provide GTECH with their next generation thermal lottery printers for various lottery applications. The terms of the new agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH. The exclusivity period will extend for four years from the start of production of the new printer, which began in January 2011. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2010 
+2009 
+2008 
+GTECH 
+12 
+% 
+19 
+% 
+28 
+% 
+Customer A 
+14 
+% 
+10 
+% 
+* 
+Customer B 
+* 
+12 
+% 
+* 
+* Customers represented less than 10% of total net sales 
+Backlog 
+Our backlog of firm orders was approximately $12,764,000 as of February 28, 2011, compared to $6,976,000 as of February 26, 2010. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2011. 
+Competition 
+The market for transaction-based printers is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group, Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreements with GTECH. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including internet resellers, depending on the geographic area. 
+3 
+Table of Contents 
+Our strategy for competing in our markets is to continue to develop new products and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $3,000,000, $2,788,000 and $2,942,000 in 2010, 2009 and 2008, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new products and to customize or improve existing products. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established for the product. Once technological feasibility is established, all material software costs are capitalized within Intangible and other assets in our consolidated balance sheet until the product is available for general release to customers. Judgment is required in determining when technological feasibility of a product is established. We have determined that technological feasibility for our software products is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of revenue over the estimated life of the product. During 2010 we began the development of a new software product that enables casino customers to print coupons and promotions at the slot machine. As of December 31, 2010, we have capitalized $130,000 of developments costs for such software; there has been no amortization of capitalized software development costs. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of February 28, 2011, TransAct and our subsidiaries employed 124 persons, of whom 123 were full-time and one was a temporary employee. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 16 – Geographic Area Information in the Notes to the Consolidated Financial Statements. Risks attendant to our foreign operations are described in Item 1A below. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. You may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/item13.txt b/raw/filings/0001017303/2010/0001017303-11-000006/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..04c167e20adc5eb1e001215326abd59fdd7e4809
--- /dev/null
+++ b/raw/filings/0001017303/2010/0001017303-11-000006/item13.txt
@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Certain Relationships and Related Transactions.”
\ No newline at end of file
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/item9a.txt b/raw/filings/0001017303/2010/0001017303-11-000006/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..0bdfff165e7e69bca788052c0955abb748ba6e53
--- /dev/null
+++ b/raw/filings/0001017303/2010/0001017303-11-000006/item9a.txt
@@ -0,0 +1,9 @@
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2010, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2010. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Annual Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2010. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 
+Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2010. 
+This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/rp_note.txt b/raw/filings/0001017303/2010/0001017303-11-000006/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2010/0001017303-11-000006/rpt_disclosure.txt b/raw/filings/0001017303/2010/0001017303-11-000006/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..a57c8bb0e91fbd67148b9eb966bc84150d4a7dc1
--- /dev/null
+++ b/raw/filings/0001017303/2010/0001017303-11-000006/rpt_disclosure.txt
@@ -0,0 +1,4 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+The Company maintains policies that relate to the identification, review and approval of related party transactions. As part of a review of possible related person transactions, the Company annually distributes and collects questionnaires that solicit information about any direct or indirect transactions with the Company from each of our directors and officers. 
+Our Standards of Business Conduct require all directors, officers and employees to avoid any situation that involves an actual or apparent conflict of interest in personal and professional relationships or with their duty to, or with any interest of, the Company. Under the Standards of Business Conduct, situations that involve, or may reasonably be inferred to involve, a conflict between a director, officer or employee’s personal interests and the interests of the Company should be disclosed to the Chair of the Audit Committee. The Audit Committee is then responsible for reviewing the related party transaction. No related party transaction shall be approved or ratified if such transaction is contrary to the best interests of the Company. In determining whether to approve or ratify a related party transaction, the Audit Committee takes into account such factors as it deems appropriate, which may include whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the related person’s interest in the transaction. 
+From January 1, 2010 to the date of this proxy statement, there have not been any transactions subject to the Company’s related party transaction policy or of the type described in Item 404 of Regulation S-K, and currently no such transactions are proposed.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/filing.txt b/raw/filings/0001017303/2011/0001017303-12-000013/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..3c14eac01ce7af94d36207b52f9bd0c5c3e230ee
--- /dev/null
+++ b/raw/filings/0001017303/2011/0001017303-12-000013/filing.txt
@@ -0,0 +1,3699 @@
+10-K
+1
+form10k.htm
+FORM 10-K
+form10k.htm 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2011 
+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: 0-21121 
+______________________________________________________________________ 
+______________________________________________________________________ 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+06-1456680 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT 
+06518 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code 203-859-6800 
+______________________________________________________________________ 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class 
+Name of Exchange on which Registered 
+Common Stock, par value $.01 per share 
+NASDAQ Global 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 o 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 o 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 o 
+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 (§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 ý No o 
+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. 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer o 
+Accelerated filer ý 
+Non-accelerated filer o (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 Exchange Act). Yes o No ý 
+The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the Registrant was approximately $104,500,000 based on the last sale price on June 30, 2011. 
+As of February 29, 2012, the registrant had outstanding 9,410,562 shares of common stock, $0.01 par value. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the TransAct Technologies Incorporated Proxy Statement to be filed with the Securities and Exchange Commission (SEC) within 120 days after the year covered by this Form 10-K with respect to the 2012 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX 
+PART I. 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+5 
+Item 1B. 
+Unresolved Staff Comments 
+10 
+Item 2. 
+Properties 
+10 
+Item 3. 
+Legal Proceedings 
+10 
+Item 4. 
+Mine Safety Disclosures 
+10 
+PART II. 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+10 
+Item 6. 
+Selected Financial Data 
+12 
+Item 7. 
+Management's Discussion and Analysis of Financial Condition and Results of Operations 
+12 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+25 
+Item 8. 
+Financial Statements and Supplementary Data 
+25 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+25 
+Item 9A. 
+Controls and Procedures 
+26 
+Item 9B. 
+Other Information 
+26 
+PART III. 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+26 
+Item 11. 
+Executive Compensation 
+27 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+27 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+28 
+Item 14. 
+Principal Accountant Fees and Services 
+28 
+PART IV. 
+Item 15. 
+Exhibits 
+28 
+SIGNATURES 
+Signatures 
+29 
+CONSOLIDATED FINANCIAL STATEMENTS 
+Index to Consolidated Financial Statements 
+F-1 
+EXHIBITS 
+Index to Exhibits 
+Table of Contents 
+PART I 
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops, assembles, markets and services world-class transaction printers under the Epic, Ithaca® and Printrex® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers generate top-quality transaction records such as receipts, tickets, coupons, register journals and other documents as well as printed logging and plotting of data. We focus on the following core markets: banking and point-of-sale (“POS”), casino and gaming, lottery, oil and gas and medical and mobile. We sell our products to original equipment manufacturers ("OEMs"), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. Beyond printers, TransAct is a leader in providing printing supplies to the full transaction printer market. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the hospitality, banking, retail, gaming, government and oil and gas exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating facility and eastern region service center located in Ithaca, NY, our printer sales headquarters and western region service center in Las Vegas, NV, a manufacturing facility located in San Jose, CA, which will be closed and incorporated into our Ithaca facility by August 2012, a European sales and service center in the United Kingdom, a sales office located in Macau and two other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518, with a telephone number of (203) 859-6800. 
+On August 19, 2011, we completed the acquisition of Printrex, Inc. (“Printrex”) for $4,000,000 in cash and potential future contingent consideration. Printrex is a leading manufacturer of specialty printers primarily sold into the oil and gas exploration and medical and mobile markets. Printrex serves commercial and industrial customers primarily in the United States, Canada, Europe and Asia. This acquisition was completed to complement our existing product offerings. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction and specialty printers and printer-related service, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers 
+TransAct designs, develops, assembles and markets a broad array of transaction-based and specialty printers utilizing inkjet, thermal and impact printing technology for applications, primarily in the banking, POS, casino and gaming, lottery, oil and gas and medical and mobile markets. Our printers are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Banking and POS: Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of our internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals that print tickets or receipts instead of issuing coins at casinos, racetracks and other gaming establishments worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that enables casinos to print coupons and promotions. In addition, we sell printers using thermal and impact printing 
+1 
+Table of Contents 
+technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through regional distributors (four in the United States and Asia, one in Europe and Africa, two in Latin America and one in Australia). We also maintain a dedicated internal sales force to solicit sales from slot manufacturers and casinos, as well as to manage sales through our distributors. 
+We have also developed a new software solution, the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that will allow casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. With EPICENTRAL TM , casinos will be able to utilize the system to create multiple promotions and incentives to either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. 
+Printrex: Printrex printers include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. In addition, we sell wide format thermal printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. We primarily sell our Printrex products directly to drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. We also maintain a dedicated internal sales force and one manufacturer’s representative located in Texas. 
+TSG 
+Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper and other transaction supplies), replacement parts and maintenance services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. Approximately 80% of our printer production is through two third-party contract manufacturers in China, with the remaining 20% of products assembled in our Ithaca, NY and San Jose, CA facilities largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY and San Jose, CA. Critical component parts and subassemblies include inkjet, thermal and impact printheads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, purchases of component parts have declined while purchases of fully-assembled printers produced by our contract manufacturers have increased. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer, and to a much lesser extent, a second foreign contract manufacturer. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturer, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2012 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges that are compatible with the HP inkjet cartridge are available, the loss of the supply of HP inkjet cartridges could have a material adverse effect on both the sale of our inkjet 
+2 
+Table of Contents 
+printers and TSG consumable products. Our relationship with HP remains stable and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be any less favorable than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+Patents and Proprietary Information 
+We have significantly expanded our patent portfolio over the past ten years, and expect to continue to do so in the future. We also believe our patent portfolio could provide additional opportunities to license our intellectual property in the future. We hold 27 United States and 20 foreign patents and have 8 United States and 25 foreign patent applications pending pertaining to our products. The duration of these patents range from 6 to 16 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+Seasonality 
+Retailers typically reduce purchases of new POS equipment in the fourth quarter due to the increased volume of consumer transactions in that holiday period, and our sales of printers in the POS market historically have increased in the third quarter and decreased in the fourth quarter. Similarly, installations of lottery terminals are typically reduced in the fourth quarter, resulting in decreased sales of lottery printers. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH is our most significant customer. We currently have an ongoing OEM purchase agreement, as amended in February 2006 (the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of thermal on-line lottery printers and spare parts, at fixed prices, through June 28, 2012. We expect to renew this agreement prior to its expiration in 2012. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH New Thermal Printer Agreement”). Under the terms of the new agreement, we will provide GTECH with their next generation thermal lottery printers for various lottery applications. The terms of the new agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH through January 2015. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2011 
+2010 
+2009 
+GTECH 
+26 
+% 
+12 
+% 
+19 
+% 
+Customer A 
+13 
+% 
+14 
+% 
+10 
+% 
+Customer B 
+* 
+* 
+12 
+% 
+* Customers represented less than 10% of total net sales 
+Backlog 
+Our backlog of firm orders was approximately $7,261,000 as of February 29, 2012, compared to $12,764,000 as of February 28, 2011. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2012. 
+Competition 
+The market for transaction-based and specialty printers is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+3 
+Table of Contents 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group (“TPG”), Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreements with GTECH. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+In the Printrex market, we compete with the Imaging Systems Group, Inc. (“iSys”), GSI Group and others. We compete in this market based largely on our ability to provide specialized, custom-engineered products. 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including POS and internet resellers, depending on the geographic area. 
+Our strategy for competing in our markets is to continue to develop new products (hardware and software) and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $3,418,000, $3,000,000 and $2,788,000 in 2011, 2010 and 2009, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new products and to customize or improve existing products. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. During 2010 we began the development of EPICENTRAL TM , that enables casino customers to print coupons and promotions at the slot machine. Unamortized development costs for such software were approximately $682,000 and $129,000 as of December 31, 2011 and 2010, respectively. The total amount charged to cost of sales for capitalized software development costs was approximately $62,000 in 2011 with no such charges in 2010. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of December 31, 2011, TransAct and our subsidiaries employed 134 persons, of whom 130 were full-time and 4 were temporary employees. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 17 – Geographic Area Information in the Notes to the Consolidated Financial Statements. Risks attendant to our foreign operations are described in Item 1A below. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is 
+4 
+Table of Contents 
+electronically filed with or furnished to the SEC. You may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800. 
+Item 1A. Risk Factors 
+Investors should carefully consider the risks, uncertainties and other factors described below, as well as other disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, because they could have a material adverse effect on our business, financial condition, operating results, and growth prospects. The risks described below are not the only ones facing our Company. Additional risks not known to us now or that we currently deem immaterial may also impair our business operations. 
+We assume no obligation (and specifically disclaim any such obligation) to update these Risk Factors or any other forward-looking statements contained in this Annual Report to reflect actual results, changes in assumptions or other factors affecting such forward-looking statements, except as required by law. 
+Our operating results and financial condition may fluctuate. 
+Our operating results and financial condition may fluctuate from quarter to quarter and year to year and are likely to continue to vary due to a number of factors, many of which are not within our control. If our operating results do not meet the expectations of securities analysts or investors, who may derive their expectations by extrapolating data from recent historical operating results, the market price of our common stock will likely decline. Fluctuations in our operating results and financial condition may be due to a number of factors, including, but not limited to, those identified throughout this “Risk Factors” section: 
+· 
+market acceptance of our products, both domestically and internationally; 
+· 
+development of new competitive printers by others; 
+· 
+our responses to price competition; 
+· 
+our level of research and development activities; 
+· 
+changes in the amount that we spend to develop, acquire or license new products, consumables, technologies or businesses; 
+· 
+changes in the amount we spend to promote our products and services; 
+· 
+changes in the cost of satisfying our warranty obligations and servicing our installed base of printers; 
+· 
+delays between our expenditures to develop and market new or enhanced printers and consumables and the generation of sales from those products; 
+· 
+the geographic distribution of our sales; 
+· 
+availability of third-party components at reasonable prices; 
+· 
+general economic and industry conditions, including changes in interest rates affecting returns on cash balances and investments, that affect customer demand; 
+· 
+severe weather events (such as hurricanes) that can disrupt or interrupt the operation of our customers or suppliers facilities; and 
+· 
+changes in accounting rules. 
+Due to all of the foregoing factors, and the other risks discussed in this report, quarter-to-quarter comparisons of our operating results may not be an indicator of future performance. 
+Our business could be negatively affected as a result of actions by activist shareholders. 
+We recently received a notice from a significant shareholder that encourages our Board of Directors to undertake an extensive review of all strategic opportunities that, in the opinion of such shareholder, would best position us for future growth in addition to maximizing shareholder value. If shareholder activism continues or increases, particularly with respect to matters which our Board of Directors, in exercising their fiduciary duties, disagree with or have determined not to pursue, our business could be adversely affected because: 
+· 
+responding to actions by activist shareholders can be costly and time-consuming, disrupting our operations and diverting the attention of management; and 
+· 
+perceived uncertainties as to our future direction may result in the loss of potential business opportunities, and may make it more difficult to attract and retain qualified personnel and business partners. 
+5 
+Table of Contents 
+We rely on resellers to sell our products and services. 
+We use a variety of distribution channels, including OEMs and distributors, to market our products. We may be adversely impacted by any conflicts that could arise between and among our various sales channels. 
+Our dependence upon resellers exposes us to numerous risks, including: 
+· 
+loss of channel and the ability to bring new products to market; 
+· 
+concentration of credit risk, including disruption in distribution should the resellers’ financial condition deteriorate; 
+· 
+reduced visibility to end user demand and pricing issues which makes forecasting more difficult; 
+· 
+resellers leveraging their buying power to change the terms of pricing, payment and product delivery schedules; and 
+· 
+direct competition should a reseller decide to manufacture printers internally or source printers from a competitor. 
+We cannot guarantee that resellers will not reduce, delay or eliminate purchases from us, which could have a material adverse effect upon the business, consolidated results of operations and financial condition. 
+General economic conditions and the related deterioration in the global business environment could have a material adverse effect on our business, operating results and financial condition. 
+Global consumer confidence has eroded amidst concerns over, among other things, declining asset values, inflation, volatility in energy costs, geopolitical issues, the availability and cost of credit, rising unemployment, and the stability and solvency of financial institutions, financial markets, businesses and sovereign nations. These concerns have slowed global economic growth and have resulted in recessions in numerous countries, including many of those in North America, Europe and Asia, where the Company does substantially all of its business. As these economic conditions continue to persist, or if they worsen, a number of negative effects on our business could result, including customers or potential customers reducing or delaying orders, the insolvency of key suppliers which could result in production delays, the inability of customers to obtain credit, and the insolvency of one or more customers. Any of these effects could impact our ability to effectively manage inventory levels and collect receivables, create unabsorbed costs due to lower net sales, and ultimately decrease our net sales and profitability including write-downs of assets. 
+In the lottery market, we have been dependent on sales to one large customer; the loss of this customer or reduction in orders from this customer could materially affect our sales. 
+We expect that sales to one large customer will continue to represent a significant percentage of our net sales for the foreseeable future. A reduction, delay or cancellation in orders from this customer, including reductions or delays due to market, economic, or competitive conditions in the industries in which we serve, could have a material adverse effect upon our results of operations. 
+Our success will depend on our ability to sustain and manage growth. 
+As part of our business strategy, we intend to pursue a growth strategy. Assuming this growth occurs, it will require the expansion of distribution relationships in international markets, the successful development and marketing of new products for our existing and new markets, expanded customer service and support, and the continued implementation and improvement of our operational, financial and management information systems. 
+To the extent that we seek growth through acquisitions, our ability to manage our growth will also depend on our ability to integrate businesses that have previously operated independently. We may not be able to achieve this integration without encountering difficulties or experiencing the loss of key employees, customers or suppliers. It may be difficult to design and implement effective financial controls for combined operations and differences in existing controls for each business may result in weaknesses that require remediation when the financial controls and reporting functions are combined. As we pursue acquisitions, we may incur legal, accounting and other transaction related expenses for unsuccessful acquisition attempts that could adversely affect our results of operations in the period in which they are incurred. 
+There can be no assurance that we will be able to successfully implement our growth strategy, or that we can successfully manage expanded operations. As we expand, we may from time to time experience constraints that will adversely affect our ability to satisfy customer demand in a timely fashion. Failure to manage growth effectively could adversely affect our results of operations and financial condition. 
+We compete in highly competitive markets, which are likely to become more competitive. Competitors may be able to respond more quickly to new or emerging technology and changes in customer requirements. 
+We face significant competition in developing and selling our printers, transaction supplies and services. Principal competitors have substantial marketing, financial, development and personnel resources. To remain competitive, we believe we must continue to provide: 
+· 
+Technologically advanced printers that satisfy the user demands, 
+· 
+Superior customer service, 
+· 
+High levels of quality and reliability, and 
+6 
+Table of Contents 
+· 
+Dependable and efficient distribution networks. 
+We cannot ensure we will be able to compete successfully against current or future competitors. Increased competition in printers or supplies may result in price reductions, lower gross profit margins and loss of market share, and could require increased spending on research and development, sales and marketing and customer support. Some competitors may make strategic acquisitions or establish cooperative relationships with suppliers or companies that produce complementary products. Any of these factors could reduce our earnings. 
+We have outsourced a large portion of the assembly of our printers to two contract manufacturers and will be dependent on them for the manufacturing of such printers. A failure by these contract manufacturers, or any disruption in such manufacturing, may adversely affect our business results. 
+In an effort to achieve additional cost savings and operation benefits, we have continued to outsource the manufacturing and assembly of our printers to contract manufacturers in Asia. 
+However, to the extent we rely on a third-party service provider for manufacturing services, we may incur increased business continuity risks. We will no longer be able to exercise control over the assembly of certain of our printers or any related operations or processes, including the internal controls associated with operations and processes conducted and the quality of our products assembled by contract manufacturers. If we are unable to effectively develop and implement our outsourcing strategy, we may not realize cost structure efficiencies and our operating and financial results could be materially adversely affected. 
+In addition, if either contract manufacturer experiences business difficulties or fails to meet our manufacturing needs, then we may be unable to meet production requirements, may lose revenue and may not be able to maintain relationships with our customers. Without the contract manufacturers continuing to manufacture our products and the continuing operation of the contract manufacturers’ facilities, we will have limited means for the final assembly of a majority of our printers until we are able to secure the manufacturing capability at another facility or develop an alternative manufacturing facility, which could be costly and time consuming and have a material adverse effect on our operating and financial results. 
+The increased elements of risk that arise from conducting certain operating processes in foreign jurisdictions may lead to an increase in reputational risk. 
+Although we carry business interruption insurance to cover lost revenue and profits in an amount we consider adequate, this insurance does not cover all possible situations. In addition, the business interruption insurance would not compensate us for the loss of opportunity and potential adverse impact, both short-term and long-term, on relations with our existing customers resulting from our inability to produce products for them. 
+The contract manufacturers have access to our intellectual property, which increases the risk of infringement or misappropriation of this intellectual property. 
+We source some of our component parts and consumable products from sole source suppliers; any disruptions may impact our ability to manufacture and sell our products. 
+A disruption in the supply of such component parts and consumable products could have a material adverse effect on our operations and financial results. 
+We sell a significant portion of our products internationally and purchase important components from foreign suppliers. These circumstances create a number of risks. 
+We sell a significant amount of our products to customers outside the United States. Shipments to international customers are expected to continue to account for a material portion of net sales. Risks associated with sales and purchases outside the United States include: 
+· 
+Fluctuating foreign currency rates could restrict sales, or increase costs of purchasing, in foreign countries. 
+· 
+Foreign governments may impose burdensome tariffs, quotas, taxes, trade barriers or capital flow restrictions. 
+· 
+Political and economic instability may reduce demand for our products or put our foreign assets at risk. 
+· 
+Restrictions on the export or import of technology may reduce or eliminate the ability to sell in or purchase from certain markets. 
+· 
+Potentially limited intellectual property protection in certain countries, such as China, may limit recourse against infringing products or cause us to refrain from selling in certain geographic territories. 
+We face risks associated with manufacturing forecasts. 
+If we fail to predict our manufacturing requirements accurately, we could incur additional costs or experience manufacturing delays, which could cause us to lose orders or customers and result in lower net sales. We currently use a rolling 12-month forecast based primarily on our anticipated product orders and our product order history to help determine our requirements for components and materials. It is very important that we accurately predict both the demand for our products and the lead-time required to obtain the necessary components and raw materials. 
+7 
+Table of Contents 
+Lead times for materials and components that we order vary significantly and depend on factors such as the specific supplier, the size of the order, contract terms, and demand for each component at a given time. If we underestimate our requirements, we may have inadequate manufacturing capacity or inventory, which could interrupt manufacturing of our products and result in delays in shipments and net sales. If we overestimate our requirements, we could have excess inventory of parts. In addition, delays in the manufacturing of our products could cause us to lose orders or customers. 
+Our revenue and profitability depend on our ability to continue to develop, on a timely basis, new technologies which are free from hardware or software anomalies and cannot be fraudulently manipulated: 
+The success of a newly introduced technology, such as printing coupons and promotions at the slot machine using our EPICENTRAL™ Print System, is dependent on our casino customers' acceptance of such technology. While we have designed our EPICENTRAL™ Print System to support our customers' existing investment in our Epic 950® thermal casino printers, such acceptance may nevertheless only build gradually over time or not at all. Delays in acceptance by our customers of new technologies may adversely affect our operations. 
+Our success depends upon our ability to adapt our capabilities and processes to meet the demands of producing new and innovative products. Because our newer products are generally more technologically sophisticated than those we have produced in the past, we must continually refine our capabilities to meet the needs of our product innovation. If we cannot efficiently adapt our infrastructure to meet the needs of our product innovations in a timely manner, our business could be negatively impacted. 
+We depend on key personnel, the loss of which could materially impact our business. 
+Our future success will depend in significant part upon the continued service of certain key management and other personnel and our continuing ability to attract and retain highly qualified managerial, technical and sales and marketing personnel. There can be no assurance that we will be able to recruit and retain such personnel. The loss of either Bart C. Shuldman, the Company's Chairman of the Board and Chief Executive Officer, or Steven A. DeMartino, the Company’s President, Chief Financial Officer, Treasurer and Secretary, or the loss of certain groups of key employees, could have a material adverse effect on our results of operations. 
+If we are unable to enforce our patents or if it is determined that we infringe patents held by others it could damage our business. Prosecuting and defending patent lawsuits is very expensive. We are committed to aggressively asserting and defending our technology and related intellectual property, which we have spent a significant amount of money to develop. These factors could cause us to become involved in new patent litigation in the future. The expense of prosecuting or defending these future lawsuits could also have a material adverse effect on our business, financial condition and results of operations. 
+If we were to lose a patent lawsuit in which another party is asserting that our products infringe its patents, we would likely be prohibited from marketing those products and could also be liable for significant damages. Either or both of these results may have a material adverse effect on our business, financial condition and results of operations. If we lose a patent lawsuit in which we are claiming that another party’s products are infringing our patents and thus, are unable to enforce our patents, it may have a material adverse effect on our business, financial condition and results of operations. In addition to disputes relating to the validity or alleged infringement of other parties' rights, we may become involved in disputes relating to our assertion of our own intellectual property rights. Whether we are defending the assertion of intellectual property rights against us or asserting our intellectual property rights against others, intellectual property litigation can be complex, costly, protracted, and highly disruptive to business operations by diverting the attention and energies of management and key technical personnel. Plaintiffs in intellectual property cases often seek injunctive relief, and the measures of damages in intellectual property litigation are complex and often subjective or uncertain. Thus, any adverse determinations in this type of litigation could subject us to significant liabilities and costs. During the course of these lawsuits there may be public announcements of the results of hearings, motions, and other interim proceedings or developments in the litigation. If securities analysts or investors perceive these results to be negative, it could harm the market price of our stock. 
+The inability to protect intellectual property could harm our reputation, and our competitive position may be materially damaged. 
+Our intellectual property is valuable and provides us with certain competitive advantages. Copyrights, patents, trade secrets and contracts are used to protect these proprietary rights. Despite these precautions, it may be possible for third parties to copy aspects of our products or, without authorization, to obtain and use information which we regard as trade secrets. 
+Infringement on the proprietary rights of others could put us at a competitive disadvantage, and any related litigation could be time consuming and costly. 
+Third parties may claim that we violated their intellectual property rights. To the extent of a violation of a third party’s patent or other intellectual property right, we may be prevented from operating our business as planned and may be required to pay damages, to obtain a license, if available, or to use a non-infringing method, if possible, to accomplish our objectives. Any of these claims, with or without merit, could result in costly litigation and divert the attention of key personnel. If such claims are successful, they could result in costly judgments or settlements. 
+8 
+Table of Contents 
+Our stock price may fluctuate significantly. 
+The market price of our common stock could fluctuate significantly in response to variations in quarterly operating results and other factors, such as: 
+· 
+changes in our business, operations or prospects; 
+· 
+developments in our relationships with our customers; 
+· 
+announcements of new products or services by us or by our competitors; 
+· 
+announcement or completion of acquisitions by us or by our competitors; 
+· 
+changes in existing or adoption of additional government regulations; 
+· 
+unfavorable or reduced analyst coverage; and 
+· 
+prevailing domestic and international market and economic conditions. 
+In addition, the stock market has experienced significant price fluctuations in recent years. Broad market fluctuations, general economic conditions and specific conditions in the industries in which we operate may adversely affect the market price of our common stock. 
+Limited trading volume of our capital stock may contribute to its price volatility. 
+Our common stock is traded on the NASDAQ Global Market. During the year ended December 31, 2011, the average daily trading volume for our common stock as reported by the NASDAQ Global Market was approximately 25,000 shares. We are uncertain whether a more active trading market in our common stock will develop. In addition, many investment banks no longer find it profitable to provide securities research on micro-cap and small-cap companies. If any analyst were to discontinue coverage of our common stock, our trading volume may be further reduced. As a result, relatively small trades may have a significant impact on the market price of our common stock, which could increase the volatility and depress the price of our common stock. 
+Future sales of our common stock may cause our stock price to decline. 
+In the future, we may sell additional shares of our common stock in public or private offerings, and we may also issue additional shares of our common stock to finance future acquisitions. Shares of our common stock are also available for future sale pursuant to stock options that we have granted to our employees, and in the future we may grant additional stock options and other forms of equity compensation to our employees. Sales of our common stock or the perception that such sales could occur may adversely affect prevailing market prices for shares of our common stock and could impair our ability to raise capital through future offerings. 
+If market conditions deteriorate or future results of operations are less than expected, a valuation allowance may be required for all or a portion of our deferred tax assets. 
+We currently have significant deferred tax assets, which may be used to reduce taxable income in the future. We assess the realization of these deferred tax assets on a quarterly basis, and if we determine that it is more likely than not that some portion of these assets will not be realized, an income tax valuation allowance is recorded. If market conditions deteriorate or future results of operations are less than expected, or there is a change to applicable tax rules, future assessments may result in a determination that it is more likely than not that some or all of our net deferred tax assets are not realizable. As a result, we may need to establish a valuation allowance for all or a portion of our net deferred tax assets, which may have a material adverse effect on our business, results of operations and financial condition. 
+We cannot provide any assurance that current laws, or any laws enacted in the future, will not have a material adverse effect on our business. 
+Our operations are subject to laws, rules, regulations, including environmental regulations, government policies and other requirements in each of the jurisdictions in which we conduct business. Changes in laws, rules, regulations, policies or requirements could result in the need to modify our products and could affect the demand for our products, which may have an adverse impact on our future operating results. If we do not comply with applicable laws, rules and regulations we could be subject to costs and liabilities and our business may be adversely impacted. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. It is possible that terrorist attacks could be directed at important locations for the gaming industry. Heightened security measures and other efforts to combat terrorism may also have an adverse effect on the gaming industry by reducing tourism. Any of these developments could also negatively affect the general economy and consumer confidence. Any downturn in the economy or in the gaming industry in particular could reduce demand for our products and adversely affect our business and results of operations. In addition, heightened security measures may cause certain governments to restrict the import/export of goods, which may have an adverse effect on our ability to buy/sell goods. 
+9 
+Table of Contents 
+Intangible computer software costs may not be recoverable. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. To the extent technological feasibility of products is not achieved, related capitalized computer software costs may not be recoverable. 
+Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial also may adversely impact our business. Should any risks or uncertainties develop into actual events, these developments could have material adverse effects on our business, financial condition, and results of operations. 
+Item 1B. Unresolved Staff Comments. 
+Not applicable. 
+Item 2. Properties. 
+Our principal facilities as of December 31, 2011 are listed below and we believe that all facilities generally are in good condition, adequately maintained and suitable for their present and currently contemplated uses. 
+Location 
+Operations Conducted 
+Size 
+(Approx. Sq. Ft.) 
+Owned or 
+Leased 
+Lease Expiration 
+Date 
+Hamden, Connecticut 
+Executive offices and Printrex and TSG sales office 
+11,100 
+Leased 
+April 23, 2017 
+Ithaca, New York 
+Global engineering, design, assembly and service facility 
+73,900 
+Leased 
+June 30, 2012 
+Las Vegas, Nevada 
+Service center and casino and gaming sales office 
+13,700 
+Leased 
+December 31, 2016 
+San Jose, California 
+Manufacturing facility 
+8,730 
+Leased 
+August 19, 2012 
+Doncaster, United Kingdom 
+Sales office and service center 
+2,800 
+Leased 
+August 1, 2016 
+Georgia and New York 
+Two regional sales offices 
+300 
+Leased 
+Various 
+Macau, China 
+Sales office 
+180 
+Leased 
+June 30, 2012 
+110,710 
+Item 3. Legal Proceedings. 
+None. 
+Item 4. Mine Safety Disclosures. 
+Not applicable. 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+Our common stock is traded on the NASDAQ Global Market under the symbol TACT. As of February 29, 2012, there were 471 holders of record of the common stock. The high and low sales prices of the common stock reported during each quarter of the years ended December 31, 2011 and 2010 were as follows: 
+Year Ended 
+Year Ended 
+December 31, 2011 
+December 31, 2010 
+High 
+Low 
+High 
+Low 
+First Quarter 
+$ 
+11.89 
+$ 
+9.31 
+$ 
+7.83 
+$ 
+6.25 
+Second Quarter 
+13.03 
+11.06 
+7.90 
+6.88 
+Third Quarter 
+12.44 
+8.08 
+8.16 
+6.83 
+Fourth Quarter 
+8.01 
+5.89 
+9.75 
+7.50 
+No dividends on common stock have been declared and we do not anticipate declaring dividends in the foreseeable future. Our credit agreement with TD Bank prohibits the payment of cash dividends on our common stock for the term of the agreement. 
+10 
+Table of Contents 
+Issuer Purchases of Equity Securities 
+On May 27, 2010, our Board of Directors approved a stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we are authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending May 27, 2013, depending on market conditions, share price and other factors. In March 2012, the Board of Directors approved an increase in our stock repurchase authorization under the Stock Repurchase Program to $15,000,000 from $10,000,000. During the fourth quarter of 2011, we repurchased 92,183 shares of our common stock for approximately $605,000 at an average price per share of $6.56. For the year ended December 31, 2011, we repurchased 275 ,255 shares of common stock for approximately $2,680,000 , at an average price of $9.74 per share, under the Stock Repurchase Program. From January 1, 2005 through December 31, 2011, we repurchased a total of 1,461,693 shares of common stock for approximately $11,395,000 under all of our stock repurchase programs, at an average price of $7.80 per share. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the trade date. At December 31, 2011, approximately $7,143,000 remains authorized for future repurchases under the Stock Repurchase Program. 
+CORPORATE PERFORMANCE GRAPH 
+The following graph compares the cumulative total return on the Company’s Common Stock from December 31, 2006 through December 31, 2011, with the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index. The graph assumes that $100 was invested on December 31, 2006 in each of TransAct’s common stock, the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index, and that all dividends were reinvested. 
+COMPARISON OF CUMULATIVE TOTAL RETURN AMONG 
+TRANSACT TECHNOLOGIES INCORPORATED COMMON STOCK, 
+THE CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.), 
+AND THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX 
+12/31/06 
+12/31/07 
+12/31/08 
+12/31/09 
+12/31/10 
+12/31/11 
+TransAct Technologies Incorporated Common Stock 
+$ 
+100.00 
+$ 
+57.71 
+$ 
+55.30 
+$ 
+83.61 
+$ 
+113.49 
+$ 
+87.47 
+CRSP Total Return Index for the Nasdaq Stock Market (U.S.) 
+$ 
+100.00 
+$ 
+108.47 
+$ 
+66.35 
+$ 
+95.38 
+$ 
+113.19 
+$ 
+113.81 
+Nasdaq Computer Manufacturer Stocks Index 
+$ 
+100.00 
+$ 
+146.29 
+$ 
+61.45 
+$ 
+134.97 
+$ 
+192.64 
+$ 
+226.04 
+11 
+Table of Contents 
+Item 6. Selected Financial Data (in thousands, except per share amounts) 
+The following is summarized from our audited financial statements of the past five years: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+Consolidated Statement of Operations Data: 
+Net sales 
+$ 
+65,969 
+$ 
+63,194 
+$ 
+58,346 
+$ 
+62,207 
+$ 
+48,766 
+Gross profit 
+24,626 
+22,548 
+18,829 
+20,950 
+15,996 
+Operating expenses 
+17,637 
+16,687 
+15,533 
+19,089 
+19,751 
+Operating income (loss) 
+6,989 
+5,861 
+3,296 
+1,861 
+(3,755 
+) 
+Net income (loss) 
+4,676 
+3,904 
+2,140 
+1,444 
+(2,274 
+) 
+Net income (loss) per share: 
+Basic 
+0.50 
+0.42 
+0.23 
+0.16 
+(0.24 
+) 
+Diluted 
+0.49 
+0.41 
+0.23 
+0.15 
+(0.24 
+) 
+December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+Consolidated Balance Sheet Data: 
+Total assets 
+$ 
+42,740 
+$ 
+43,621 
+$ 
+34,899 
+$ 
+32,234 
+$ 
+30,414 
+Working capital 
+27,222 
+25,525 
+20,474 
+15,051 
+11,338 
+Shareholders’ equity 
+35,313 
+31,134 
+26,354 
+23,282 
+21,608 
+Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 
+This discussion should be read in conjunction with the Consolidated Financial Statements and notes thereto. 
+Forward Looking Statements 
+Certain statements included in this report, including without limitation statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, which are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements generally can be identified by the use of forward-looking terminology, such as “may”, “will”, “expect”, “intend”, ”estimate”, “anticipate”, “believe”, “project” or “continue” or the negative thereof or other similar words. All forward-looking statements involve risks and uncertainties, including, but not limited to those listed in Item 1A of this Annual Report. Actual results may differ materially from those discussed in, or implied by, the forward-looking statements. The forward-looking statements speak only as of the date of this report and we assume no duty to update them. 
+Overview 
+During 2011, we again concentrated our efforts on growing overall revenue in our existing markets, with particular emphasis on gaining market share in the U.S. casino market. In addition, we also focused on increasing our gross profit and leveraging such increase to our operating income. We believe we successfully achieved these objectives in 2011. We increased our overall sales 4% and our U.S. casino and gaming printer sales 19%, despite a decline in the replacement cycle of slot machines within a difficult U.S. economy. Our total printer shipments increased 6% to a record high of approximately 201,000 in 2011. In addition, our gross margin, operating margin and earnings per share for 2011 each increased from 2010 reaching near record highs. In August 2011, we completed the acquisition of Printrex, a worldwide leading manufacturer of high-performance specialty printers primarily sold into the oil and gas exploration and drilling market, for $4,000,000 in cash and potential future contingent consideration. For the year ended December 31, 2011, Printrex contributed approximately $1,892,000 in sales (inclusive of Printrex TSG products) in just over four months and provided gross margins above TransAct’s historical average. 
+We continue to focus on sales growth in our core markets (banking and POS, casino and gaming, lottery, Printrex and TSG) to drive increased profitability. During 2011, our total net sales increased 4% to approximately $65,969,000. See the table below for a breakdown of our sales by market: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2011 
+December 31, 2010 
+$ 
+% 
+Banking and POS 
+$ 
+9,943 
+15.1 
+% 
+$ 
+14,528 
+23.0 
+% 
+$ 
+(4,585 
+) 
+(31.6 
+%) 
+Casino and gaming 
+24,955 
+37.8 
+% 
+25,678 
+40.6 
+% 
+(723 
+) 
+(2.8 
+%) 
+Lottery 
+14,933 
+22.6 
+% 
+8,142 
+12.9 
+% 
+6,791 
+83.4 
+% 
+Printrex 
+1,710 
+2.6 
+% 
+- 
+- 
+% 
+1,710 
+100.0 
+% 
+TSG 
+14,428 
+21.9 
+% 
+14,846 
+23.5 
+% 
+(418 
+) 
+(2.8 
+%) 
+Total net sales 
+$ 
+65,969 
+100.0 
+% 
+$ 
+63,194 
+100.0 
+% 
+$ 
+2,775 
+4.4 
+% 
+12 
+Table of Contents 
+Sales of our banking and POS printers decreased 32% in 2011 compared to 2010. In the banking market, we focus mainly on supplying printers for use in bank teller stations at banks and financial institutions primarily in the U.S. Opportunities in the banking market are project oriented and, as a result, our banking printer sales can fluctuate significantly year-to-year. During 2011, our banking printer sales decreased 37% primarily due to sales to a bank customer to upgrade its bank teller stations utilizing our BANKjet® 2500 bank teller printer in 2010 that did not recur in 2011, somewhat offset by higher sales of our BANKjet® 1500 printers. In the POS market, we focus primarily on supplying printers that print receipts or linerless labels for customers in the restaurant, hospitality and specialty retail markets. Sales of our POS printers decreased 31% in 2011 primarily due to the shipment of a large order for our Ithaca® 280 thermal receipt printer to an existing retail customer as part of a POS system upgrade project in all its U.S. stores in 2010 that did not repeat in 2011. This decrease was coupled with a 33% decrease in sales of our two printer products for McDonald’s for its combined beverage initiative and its POS system upgrade and grill initiative as the rollout to its 14,000 U.S. stores was substantially completed during 2011. We intend to pursue sales to McDonald’s international stores (totaling more than 18,000 stores) during 2012. 
+Sales of our casino and gaming printers decreased 3% in 2011 compared to 2010. In our casino and gaming market, our focus lies primarily in supplying printers for use in slot machines at casinos and racetracks, as well as in other gaming devices that print tickets or receipts, worldwide. Domestic sales of our casino and gaming printers increased 19%, mostly due to market share gains in the casino market, as we believe the overall replacement cycle of slot machines was lower in 2011 as compared to 2010. Our higher domestic sales were more than offset by a 15% decrease in international sales, mostly from lower sales of gaming machines into Italy where the government had approved gambling operators to install approximately 50,000 VLT games in 2010, of which only 30,000 have shipped so far. Since a substantial portion of these games were installed during 2010, installations for 2011 were significantly lower. 
+In the lottery market, we continue to hold a leading position based on our long-term exclusive purchase agreement with GTECH, our largest customer and the world’s largest provider of lottery terminals. GTECH has been our customer since 1995, and we continue to maintain a good relationship with them. In 2009 we expanded our long-standing relationship with GTECH by executing a new exclusive purchase agreement to develop and supply them with their next generation online thermal lottery printer. Pursuant to the new agreement, GTECH will exclusively purchase all of its requirements for thermal on-line lottery printers from us and we will exclusively sell such printers to GTECH through January 2015. Currently, we fulfill substantially all of GTECH’s printer requirements for lottery terminal installations and upgrades worldwide. During 2011, total printer sales to GTECH increased approximately 86%, compared to 2010. Our sales to GTECH each year are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs and are not indicative of GTECH’s overall business or revenue. 
+Sales in the Printrex market include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. Sales in this market also includes wide format printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. Printrex printer sales of approximately $1,710,000 were included from the acquisition date of August 19, 2011 through December 31, 2011. 
+Our TransAct Services Group, which sells service, replacement parts and consumable products, including receipt paper, ribbons and inkjet cartridges, continues to offer a recurring revenue stream for TransAct. TSG sales decreased 3% in 2011 from 2010 primarily due to a decline in service revenue from our paper testing services program. Companies who produce and sell paper products that are used in our printers, utilize this new service for a fee to have their product qualified for use in our printers. 
+Operationally, both our gross margin and operating margin showed significant improvement from 2010. During 2011, our gross margin increased to a record high 37.3% compared to 35.7% in 2010 and our operating margin increased to 10.6% in 2011 compared to 9.3% in 2010. Both our gross margin and operating margin increased due primarily to higher sales volume and a more favorable sales mix combined with a continued effort of cost control, specifically in lower production costs, in addition to sales of higher margin Printrex printers in 2011 compared to 2010. 
+We reported net income of $4,676,000 and net income per diluted share of $0.49 for 2011, compared to net income of $3,904,000 and net income per diluted share of $0.41 in 2010. In terms of cash flow for 2011, we generated $2,096,000 of cash from operating activities and utilized $4,000,000 of cash for the acquisition of Printrex, $2,680,000 for treasury share repurchases and $1,256,000 for capital expenditures and capitalized software development resulting in cash and cash equivalents of $6,863,000 and no debt on our Consolidated Balance Sheet at December 31, 2011. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect both Balance Sheet items and Statement of Income categories. Such estimates and judgments are based upon historical experience and certain assumptions that are believed to be reasonable in the particular circumstances. We evaluate our assumptions on an ongoing basis by comparing actual results with our estimates. Actual results may differ from the original estimates. 
+13 
+Table of Contents 
+The following accounting policies are those that we believe to be most critical in the preparation of our financial statements. These items utilize assumptions and estimates about the effect of future events that are inherently uncertain and are therefore based on our judgment. Please refer to Note 2 – Summary of significant accounting policies in the accompanying Consolidated Financial Statements for a complete listing of our accounting policies. 
+Revenue Recognition – Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within Accounting Standards Codification (“ASC”) 605, “Revenue Recognition” (ASC 605). Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We account for all revenue arrangements involving multiple deliverables in accordance with ASC 605-25, “Multiple-Element Arrangements.” For these arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and recognize revenue as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established, but we cannot guarantee that we will continue to experience return rates consistent with historical patterns. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. However, we cannot guarantee that this minimal level will continue. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Accounts Receivable – We have standardized credit granting and review policies and procedures for all customer accounts, including: credit reviews of all new customer accounts; ongoing credit evaluations of current customers; credit limits and payment terms based on available credit information; and adjustments to credit limits based upon payment history and the customer’s current creditworthiness. We also provide an estimate of doubtful accounts based on historical experience and specific customer collection issues. Our allowance for doubtful accounts as of December 31, 2011 was $70,000, or less than 1.0% of outstanding accounts receivable, which we feel is appropriate considering the overall quality of our accounts receivable. While credit losses have historically been within expectations and the reserves established, we cannot guarantee that our credit loss experience will continue to be consistent with historical experience. 
+Inventories – Our inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Assumptions are reviewed at least quarterly and adjustments are made, as necessary, to reflect changing market conditions. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. Should circumstances change and we determine that additional inventory is subject to obsolescence, additional write-downs of inventory could result in a charge to income. 
+Goodwill and Intangible Assets – We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with Accounting Standards Codification (“ASC”) 350-20 “Goodwill”, acquired goodwill is not amortized but is subject to impairment testing at least annually and when an event occurs or circumstances change, that indicate it is more likely than not an impairment exists. Factors considered that 
+14 
+Table of Contents 
+may trigger an impairment review are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Definite lived intangible assets are amortized and are tested for impairment when appropriate. We reported $2,518,000 of goodwill and $2,861,000 of definite-lived intangible assets at December 31, 2011. We have determined that no goodwill or intangible asset impairment has occurred based on our assessment during 2011. 
+Income Taxes – In preparing our Consolidated Financial Statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. This involves estimating the actual current tax exposure together with assessing temporary differences between the tax basis of certain assets and liabilities and their reported amounts in the financial statements, as well as net operating losses, tax credits and other carryforwards. These differences result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets. We then assess the likelihood that the deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. 
+Significant judgment is required in determining the provision for income taxes and, in particular, any valuation allowance or tax reserves with respect to our deferred tax assets and uncertain tax positions. On a quarterly basis, we evaluate the recoverability of our deferred tax assets based upon historical results and forecasted taxable income over future years, and match this forecast against the basis differences, deductions available in future years and the limitations allowed for net operating loss and tax credit carryforwards to ensure that there is adequate support for the realization of the deferred tax assets. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance or tax reserve, in the event we were to determine that we would not be able to realize all or part of our deferred tax assets in the future, an adjustment to the valuation allowance or tax reserves would be charged as a reduction to income in the period such determination was made. Likewise, should we determine that we would be able to realize future deferred tax assets in excess of its net recorded amount, an adjustment to the valuation allowance or tax reserves would increase net income in the period such determination was made. 
+We account for income taxes in accordance with ASC 740, “Income Taxes.” Among other things this provision prescribes a minimum recognition threshold that an income tax position must meet before it is recorded in the reporting entity’s financial statements. It also requires that the effects of such income tax positions be recognized only if, as of the balance sheet reporting date, it is “more likely than not” (i.e., more than a 50% likelihood) that the income tax position will be sustained based solely on its technical merits. When making this assessment, management must assume that the responsible taxing authority will examine the income tax position and have full knowledge of all relevant facts and other pertinent information. The accounting guidance also clarifies the method of accruing for interest and penalties when there is a difference between the amount claimed, or expected to be claimed, on a company’s income tax returns and the benefits recognized in the financial statements. 
+Warranty – We generally warrant our products for up to 36 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. If actual future product repair rates or the actual costs of material and labor differ from the estimates, adjustments to the accrued warranty liability and related warranty expense would be made. 
+Contingencies – We record an estimated liability related to contingencies based on our estimates of the probable outcomes pursuant to ASC 450, “Contingencies.” On a quarterly basis, we assess the potential liability related to pending litigation, audits and other contingencies and confirm or revise estimates and reserves as appropriate. If the actual liabilities are settled in an amount greater than those recorded on the balance sheet, a charge to income would be recorded. As of December 31, 2011, a contingent liability of $680,000 was recorded in connection with a contingent consideration arrangement entered into as part of the Printrex acquisition. See Note 4 to the Consolidated Financial Statements for further discussion. 
+Share-Based Compensation – We calculate share-based compensation expense in accordance with ASC 718, “Compensation – Stock Compensation” using the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions for this valuation method include the expected term of an option grant, stock price volatility, risk-free interest rate, dividend yield, and forfeiture rate. The determination of these assumptions is based on past history and future expectations, and is subject to a high level of judgment. To the extent any of the assumptions were to change from year to year, the fair value of new option grants may vary significantly. 
+15 
+Table of Contents 
+Results of Operations: Year ended December 31, 2011 compared to year ended December 31, 2010 
+Net Sales. Net sales, which include printer sales and sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2011 and 2010 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2011 
+December 31, 2010 
+$ 
+% 
+Banking and POS 
+$ 
+9,943 
+15.1 
+% 
+$ 
+14,528 
+23.0 
+% 
+$ 
+(4,585 
+) 
+(31.6 
+)% 
+Casino and gaming 
+24,955 
+37.8 
+% 
+25,678 
+40.6 
+% 
+(723 
+) 
+(2.8 
+)% 
+Lottery 
+14,933 
+22.6 
+% 
+8,142 
+12.9 
+% 
+6,791 
+83.4 
+% 
+Printrex 
+1,710 
+2.6 
+% 
+- 
+- 
+% 
+1,710 
+100.0 
+% 
+TSG 
+14,428 
+21.9 
+% 
+14,846 
+23.5 
+% 
+(418 
+) 
+(2.8 
+)% 
+$ 
+65,969 
+100.0 
+% 
+$ 
+63,194 
+100.0 
+% 
+$ 
+2,775 
+4.4 
+% 
+International* 
+$ 
+16,668 
+25.3 
+% 
+$ 
+19,093 
+30.2 
+% 
+$ 
+(2,425 
+) 
+(12.7 
+)% 
+* 
+International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+Net sales for 2011 increased $2,775,000, or 4%, from 2010 due largely to a sales increase in our lottery market (an increase of approximately $6,791,000, or 83%) and $1,710,000 of sales of Printrex printers resulting from the acquisition of Printrex on August 19, 2011. Sales from banking and POS decreased approximately $4,585,000, or 32%, sales from our casino and gaming market decreased approximately $723,000, or 3% and sales from our TSG market decreased approximately $418,000, or 3%. Printer sales volume increased 6% to approximately 201,000 units while the average selling price of our printers remained relatively flat from 2010 to 2011. The increase in unit volume was driven primarily by the lottery market where our unit volume increased 93% compared to 2010, somewhat offset by a 34% decline in unit volume from the banking and POS market. Overall, international sales decreased $2,425,000, or 13%, primarily driven by lower sales to the casino and gaming market. 
+Banking and POS : Revenue from the banking and POS market includes sales of printers used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. Revenue from this market also includes sales of inkjet, thermal and impact printers used primarily by retailers in the restaurant (including fine dining, casual dining and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. A summary of sales of our worldwide banking and POS printers for the years ended December 31, 2011 and 2010 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2011 
+December 31, 2010 
+$ 
+% 
+Domestic 
+$ 
+8,968 
+90.2 
+% 
+$ 
+13,447 
+92.6 
+% 
+$ 
+(4,479 
+) 
+(33.3 
+)% 
+International 
+975 
+9.8 
+% 
+1,081 
+7.4 
+% 
+(106 
+) 
+(9.8 
+)% 
+$ 
+9,943 
+100.0 
+% 
+$ 
+14,528 
+100.0 
+% 
+$ 
+(4,585 
+) 
+(31.6 
+)% 
+The decrease in domestic banking and POS printer revenue from 2010 was primarily driven by lower sales of our POS printers due to the shipment of a large order for our Ithaca® 280 thermal receipt printer to an existing retail customer as part of a POS system upgrade project in all its U.S. stores in 2010 that did not repeat in 2011. This decrease was coupled with a 37% decrease in U.S. sales of our two printer products for McDonald’s for its combined beverage initiative and its POS system upgrade and grill initiatives. We expect U.S. sales for McDonald’s to be lower in 2012 compared to 2011 as McDonald’s has substantially completed of the roll out of both its combined beverage initiative and new POS system (which includes the grill initiative printer upgrades) to its 14,000 U.S. stores . Sales of our banking printers decreased 37% primarily due to sales to a bank customer to upgrade its bank teller stations utilizing our BANKjet® 2500 bank teller printer in 2010 that did not recur in 2011. Although we are currently pursuing several banking opportunities, due to the project-oriented nature of these sales, we cannot predict the level of future sales. 
+International banking and POS printer sales for 2011 decreased 10% from 2010 due primarily to lower sales to international distributors in Europe, Latin America and the Pacific Rim. This decrease was largely offset by the roll out of the McDonald’s POS system upgrade and grill initiative as well as the combined beverage initiative to its Canadian stores in 2011 compared to 2010, which we expect to continue during 2012. 
+Casino and gaming : Revenue from the casino and gaming market includes sales of printers used in slot machines, video lottery terminals (“VLTs”), and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos and racetracks (“racinos”) and other gaming venues worldwide. Revenue from this market also includes sales of printers used in the international 
+16 
+Table of Contents 
+off-premise gaming market in gaming machines such as Amusement with Prizes (“AWP”), Skills with Prizes (“SWP”) and Fixed Odds Betting Terminals (“FOBT”) at non-casino gaming establishments and royalties related to our patented casino and gaming technology. A summary of sales of our worldwide casino and gaming printers for the years ended December 31, 2011 and 2010 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2011 
+December 31, 2010 
+$ 
+% 
+Domestic 
+$ 
+11,007 
+44.1 
+% 
+$ 
+9,287 
+36.2 
+% 
+$ 
+1,720 
+18.5 
+% 
+International 
+13,948 
+55.9 
+% 
+16,391 
+63.8 
+% 
+(2,443 
+) 
+(14.9 
+)% 
+$ 
+24,955 
+100.0 
+% 
+$ 
+25,678 
+100.0 
+% 
+$ 
+(723 
+) 
+(2.8 
+)% 
+The increase in domestic sales of our casino and gaming printers is primarily due to an increase of 16% in sales of our thermal casino printers. We believe that our increased casino printer sales during 2011 resulted from a combination of new casino openings and market share gains, as we believe the overall replacement cycle of slot machines was lower in 2011 as compared to 2010. Even though we anticipate some improvement in the domestic slot machine replacement cycle in 2012, we expect our domestic casino sales to be higher in 2012 than in 2011 as we expect to also benefit from new casino openings we won in 2011 that will install in 2012 and continue to gain market share. However, we believe the current uncertain economic environment could continue to negatively impact the casino industry’s level of capital expenditures in 2012, and as a result, our future sales to the domestic casino and gaming market could be unpredictable and adversely affected. 
+International casino and gaming printer sales decreased due primarily to a 15% decline in thermal casino printer sales resulting largely from a 27% decrease in our thermal casino printer sales to our OEM and distributor customers in Canada and Europe. This decline was primarily due to higher sales of VLT gaming machines into Italy during 2010 from the government-approved installation of approximately 50,000 VLT games, of which only 30,000 have shipped so far. Since the Italian government significantly slowed the pace of installations in 2011, our resulting printer sales were significantly lower in 2011 compared to 2010. Although we expect such sales to resume in 2012, we cannot predict the level of sales as it is dependent on the Italian government. Sales of our off-premise thermal gaming printers decreased 14% in 2011 compared to 2010 due largely to a 16% decrease in sales to a distributor and OEM customer in Australia and Asia as well as an 18% decrease in sales to our European distributor. 
+Lottery: Revenue from the lottery market includes sales of thermal on-line and other lottery printers to GTECH for various lottery applications. A summary of sales of our worldwide lottery printers for the years ended December 31, 2011 and 2010 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2011 
+December 31, 2010 
+$ 
+% 
+Domestic 
+$ 
+14,557 
+97.5 
+% 
+$ 
+7,813 
+96.0 
+% 
+$ 
+6,744 
+86.3 
+% 
+International 
+376 
+2.5 
+% 
+329 
+4.0 
+% 
+47 
+14.3 
+% 
+$ 
+14,933 
+100.0 
+% 
+$ 
+8,142 
+100.0 
+% 
+$ 
+6,791 
+83.4 
+% 
+Sales to GTECH for 2011 reached a near record level. However, our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year and are not indicative of GTECH’s overall business or revenue. We expect total sales to GTECH for 2012 to be significantly lower than those reported during 2011. 
+Printrex: Sales in the Printrex market include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. Sales in this market also include wide format printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. A summary of sales of our worldwide Printrex printers is as follows: 
+Year ended 
+(In thousands) 
+December 31, 2011 
+Domestic 
+$ 
+1,391 
+81.3 
+% 
+International 
+319 
+18.7 
+% 
+$ 
+1,710 
+100.0 
+% 
+Printrex printers contributed sales of $1,710,000 during 2011. Such sales were included from the period from August 19, 2011, the closing date of our acquisition of Printrex, through December 31, 2011. As Printrex was acquired during the third quarter of 2011, no Printrex printer sales were included in our results for 2010. We expect sales of Printrex printers for 2012 to be between approximately $5,000,000 and $5,500,000. 
+17 
+Table of Contents 
+TSG : Revenue from TSG includes sales of consumable products (inkjet cartridges, ribbons, receipt paper and other printing supplies), replacement parts, maintenance and repair services, testing services, refurbished printers, and shipping and handling charges. A summary of sales in our worldwide TSG market for the years ended December 31, 2011 and 2010 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2011 
+December 31, 2010 
+$ 
+% 
+Domestic 
+$ 
+13,378 
+92.7 
+% 
+$ 
+13,554 
+91.3 
+% 
+$ 
+(176 
+) 
+(1.3 
+%) 
+International 
+1,050 
+7.3 
+% 
+1,292 
+8.7 
+% 
+(242 
+) 
+(18.7 
+)% 
+$ 
+14,428 
+100.0 
+% 
+$ 
+14,846 
+100.0 
+% 
+$ 
+(418 
+) 
+(2.8 
+)% 
+The decrease in domestic revenue from TSG is primarily due to a 4% decrease in sales of consumables, a decline in service revenue related to a price reduction on a large service contract, and testing services revenue recorded in 2010 that did not recur in 2011. These decreases were largely offset by an increase of 51% in sales of replacement parts compared to 2010 in addition to Printrex sales of approximately $182,000. We expect TSG sales in 2012 to be lower than in 2011. Internationally, TSG revenue decreased due primarily to lower sales of replacement parts as compared to 2010. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2011 
+2010 
+Change 
+Total Sales – 2011 
+Total Sales – 2010 
+Year ended 
+$ 
+24,626 
+$ 
+22,548 
+9.2 
+% 
+37.3 
+% 
+35.7 
+% 
+Gross profit is measured as revenue less cost of sales, which includes primarily the cost of all raw materials and component parts, direct labor and the associated manufacturing overhead expenses, and the cost of finished products purchased directly from our contract manufacturers. Gross profit increased $2,078,000, or 9%, and gross margin improved 160 basis points due primarily to (1) a 4% increase in sales in 2011 compared to 2010, (2) lower product and production costs resulting from increased printer production in Asia and (3) the addition of higher margin Printrex printers in 2011 compared to 2010. We expect our gross margin for 2012 to be higher than in 2011. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2011 
+2010 
+Change 
+Total Sales – 2011 
+Total Sales – 2010 
+Year ended 
+$ 
+3,418 
+$ 
+3,000 
+13.9 
+% 
+5.2 
+% 
+4.7 
+% 
+Engineering, design and product development expenses primarily include salary and payroll related expenses for our engineering staff, depreciation and design expenses (including prototype printer expenses, outside design and testing services, and supplies). Such expenses increased $418,000, or 14%, which was due primarily to the addition of engineering staff and related expenses from the acquisition of Printrex of approximately $241,000, higher outside testing and pre-production expenses related to new product development during 2011 and slightly higher consulting expenses compared to 2010. We expect engineering, design and product development expenses to be higher in 2012 than in 2011 due to the full year effect of the Printrex acquisition. 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2011 
+2010 
+Change 
+Total Sales – 2011 
+Total Sales – 2010 
+Year ended 
+$ 
+6,402 
+$ 
+6,407 
+- 
+% 
+9.7 
+% 
+10.1 
+% 
+Selling and marketing expenses primarily include salaries and payroll related expenses for our sales and marketing staff, sales commissions, travel expenses, expenses associated with the lease of sales offices, advertising, trade show expenses, e-commerce and other promotional marketing expenses. Such expenses were relatively flat compared to 2010 as lower sales commissions and promotional marketing expenses were almost fully offset by higher expenses associated with the Printrex acquisition. We expect selling and marketing expenses to be higher in 2012 than in 2011 due to the full year effect of the Printrex acquisition. 
+18 
+Table of Contents 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2011 
+2010 
+Change 
+Total Sales – 2011 
+Total Sales – 2010 
+Year ended 
+$ 
+7,633 
+$ 
+7,280 
+4.8 
+% 
+11.6 
+% 
+11.5 
+% 
+General and administrative expenses primarily include salaries and payroll related expenses for our executive, accounting, human resource, business development and information technology staff, expenses for our corporate headquarters, professional and legal expenses, telecommunication expenses, and other expenses related to being a publicly-traded company. General and administrative expenses increased $353,000, or 5%, due primarily to higher transaction and integration costs of approximately $129,000 in addition to amortization of intangible assets of approximately $139,000, both related to the acquisition of Printrex. We expect general and administrative expenses to be higher in 2012 than in 2011 due to the full year effect of the Printrex acquisition. 
+Business Consolidation and Restructuring . Business consolidation and restructuring information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2011 
+2010 
+Change 
+Total Sales - 2011 
+Total Sales - 2010 
+Year ended 
+$ 
+184 
+$ 
+- 
+100.0 
+% 
+0.3 
+% 
+- 
+% 
+During 2011, we closed our New Britain, CT service facility which primarily serviced our first generation legacy impact printers for GTECH and incurred certain facility closure and severance costs. We no longer needed to maintain this facility since these printers have been replaced by our thermal lottery printers. We do not expect to incur further expenses associated with the facility closing and believe that this action will result in annualized cost savings of approximately $400,000, or $100,000 per quarter. Please also refer to Note 9 in the Consolidated Financial Statements. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2011 
+2010 
+Change 
+Total Sales - 2011 
+Total Sales – 2010 
+Year ended 
+$ 
+6,989 
+$ 
+5,861 
+19.2 
+% 
+10.6 
+% 
+9.3 
+% 
+The increase in our operating income and operating margin was primarily due to higher gross profit resulting from the 4% increase in net sales and a 160 basis point improvement in gross margin in 2011 compared to 2010 which was slightly offset by higher operating expenses due primarily to the Printrex acquisition. 
+Interest. We recorded net interest income of $18,000 in 2011 compared to net interest expense of $9,000 in 2010. The increase in net interest income is due to the $26,000 of interest expense incurred in 2010 related to certain prior years’ state and local tax liabilities that did not recur in 2011. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2011 and 2010. See “Liquidity and Capital Resources” below for more information. 
+Other, net. We recorded other income of $1,000 in 2011 compared to other expense of $25,000 in 2010. The change from 2010 was primarily due to foreign currency transaction exchange losses recorded by our U.K. subsidiary in 2010 compared to a small gain in 2011. 
+Income Taxes. We recorded an income tax provision for 2011 of $2,332,000 at an effective tax rate of 33.3% compared to $1,923,000 at an effective tax rate of 33.0% for 2010. The effective tax rate for 2011 increased slightly as compared to 2010 primarily due to higher state taxes from the acquisition of Printrex. We expect our annual effective tax rate for 2012 to be approximately 34%. 
+Net Income . We reported net income during 2011 of $4,676,000, or $0.49, per diluted share, compared to $3,904,000, or $0.41, per diluted share, for 2010. 
+19 
+Table of Contents 
+Results of Operations: Year ended December 31, 2010 compared to year ended December 31, 2009 
+Net Sales. Net sales, which include printer sales and sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2010 and 2009 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Banking and POS 
+$ 
+14,528 
+23.0 
+% 
+$ 
+16,695 
+28.6 
+% 
+$ 
+(2,167 
+) 
+(13.0 
+)% 
+Casino and gaming 
+25,678 
+40.6 
+% 
+17,526 
+30.0 
+% 
+8,152 
+46.5 
+% 
+Lottery 
+8,142 
+12.9 
+% 
+9,551 
+16.4 
+% 
+(1,409 
+) 
+(14.8 
+)% 
+TSG 
+14,846 
+23.5 
+% 
+14,574 
+25.0 
+% 
+272 
+1.9 
+% 
+$ 
+63,194 
+100.0 
+% 
+$ 
+58,346 
+100.0 
+% 
+$ 
+4,848 
+8.3 
+% 
+International* 
+$ 
+19,093 
+30.2 
+% 
+$ 
+12,456 
+21.3 
+% 
+$ 
+6,637 
+53.3 
+% 
+* 
+International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+Net sales for 2010 increased $4,848,000, or 8%, from 2009 due to sales increases in two out of four of our markets: casino and gaming (an increase of approximately $8,152,000, or 47%) and TSG (an increase of approximately $272,000, or 2%). Sales from banking and POS decreased approximately $2,167,000, or 13%, and sales from our lottery market decreased approximately $1,409,000, or 15%. Printer sales volume increased 17% while the average selling price of our printers decreased approximately 5% (due primarily to a decrease in sales of banking printers with higher average selling prices) from 2009 to 2010. Overall, international sales increased $6,637,000, or 53%, driven by higher sales to the gaming portion of the casino and gaming market. 
+Banking and POS : Sales of our banking and POS printers worldwide decreased approximately $2,167,000, or 13%, from 2009 and a summary follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+13,447 
+92.6 
+% 
+$ 
+15,480 
+92.7 
+% 
+$ 
+(2,033 
+) 
+(13.1 
+)% 
+International 
+1,081 
+7.4 
+% 
+1,215 
+7.3 
+% 
+(134 
+) 
+(11.0 
+)% 
+$ 
+14,528 
+100.0 
+% 
+$ 
+16,695 
+100.0 
+% 
+$ 
+(2,167 
+) 
+(13.0 
+)% 
+Domestic banking and POS printer revenue was $13,447,000, a 13% decrease from 2009, primarily driven by lower sales of our banking printers. Sales of our banking printers decreased 79% in 2010 compared to 2009 due to the completion of a project by one of our large banking customers utilizing our BANKjet® 1500 bank teller printers in 2009 that did not recur in 2010. This decrease was somewhat offset by the first year of volume sales of our BANKjet® 2500 printer. Domestic sales of our POS printers increased approximately 52% largely due to sales of our two printer products for McDonald’s for its combined beverage initiative and its POS system upgrade and grill initiatives. Sales of these printers increased approximately 121% during 2010 compared to 2009. 
+International banking and POS printer sales for 2010 decreased from 2009 by $134,000, or 11%, to $1,081,000 due primarily to lower legacy impact printer sales to our international distributor in Latin America. 
+Casino and gaming : Sales of our casino and gaming printers increased $8,152,000, or 47%, from 2009 and a summary follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+9,287 
+36.2 
+% 
+$ 
+7,497 
+42.8 
+% 
+$ 
+1,790 
+23.9 
+% 
+International 
+16,391 
+63.8 
+% 
+10,029 
+57.2 
+% 
+6,362 
+63.4 
+% 
+$ 
+25,678 
+100.0 
+% 
+$ 
+17,526 
+100.0 
+% 
+$ 
+8,152 
+46.5 
+% 
+Domestic sales of our casino and gaming printers increased $1,790,000, or 24%, due largely to an increase of 53% in the volume of sales of our thermal casino printers. We believe that our increased casino printer sales during 2010 resulted from market share gains, as we believe the overall replacement cycle of slot machines was lower in 2010 as compared to 2009. 
+International casino and gaming printer sales increased $6,362,000, or 63%, to $16,391,000 in 2010. This increase was due primarily to a 161% increase in our thermal casino printer sales to our OEM and distributor customers in Canada and Europe, partially offset by a 23% 
+20 
+Table of Contents 
+decrease in casino printer sales to our distributor in Australia. The increase in sales to our customers in Canada and Europe was primarily due to the sales of gaming machines into Italy, where in 2010 the Italian government approved gambling operators to install approximately 50,000 VLT games over the course of several years. In addition, sales for 2010 included $1,600,000 in sales of our off-premise gaming printers to a new customer for use in gaming machines in the U.K. 
+Lottery: Revenue from the lottery market includes sales of lottery printers to GTECH for various lottery applications and a summary follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+7,813 
+96.0 
+% 
+$ 
+9,117 
+95.5 
+% 
+$ 
+(1,304 
+) 
+(14.3 
+)% 
+International 
+329 
+4.0 
+% 
+434 
+4.5 
+% 
+(105 
+) 
+(24.2 
+)% 
+$ 
+8,142 
+100.0 
+% 
+$ 
+9,551 
+100.0 
+% 
+$ 
+(1,409 
+) 
+(14.8 
+)% 
+Domestic and international lottery printer sales to GTECH, which include thermal on-line and other lottery printers, decreased approximately $1,409,000, or 15%, in 2010 compared to 2009, with domestic sales decreasing approximately $1,304,000 and international sales decreasing approximately $105,000. Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. Our sales to GTECH are not indicative of GTECH’s overall business or revenue. 
+TSG : Sales from TSG increased approximately $272,000, or 2%, from 2009 and a summary follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2010 
+December 31, 2009 
+$ 
+% 
+Domestic 
+$ 
+13,554 
+91.3 
+% 
+$ 
+13,796 
+94.7 
+% 
+$ 
+(242 
+) 
+(1.8 
+%) 
+International 
+1,292 
+8.7 
+% 
+778 
+5.3 
+% 
+514 
+66.1 
+% 
+$ 
+14,846 
+100.0 
+% 
+$ 
+14,574 
+100.0 
+% 
+$ 
+272 
+1.9 
+% 
+Domestic revenue from TSG decreased approximately $242,000, or 2%, largely due to a decrease of 23% in sales of replacement parts compared to the same period in 2009. The decrease in replacement part sales was primarily due to lower demand for certain legacy printers, as the installed base of these legacy printers in the market continues to decline. In addition, maintenance and repair service revenue declined 18% due primarily to lower service contract revenue. These decreases were somewhat offset by an increase in revenue from our new paper testing services and a 2% increase in sales of inkjet cartridges largely due to newly acquired customers. 
+Internationally, TSG revenue increased $514,000, or 66%, to $1,292,000, due primarily to higher sales of replacement parts and printer accessories, largely for our casino, gaming and lottery printers installed in Europe. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+22,548 
+$ 
+18,829 
+19.8 
+% 
+35.7 
+% 
+32.3 
+% 
+Gross profit increased $3,719,000, or 20%, to $22,548,000 from $18,829,000 and gross margin improved from 32.3% to 35.7% due primarily to (1) an increase in sales of contract manufactured products with lower overall product costs, including lower labor costs, resulting from the move of production for the majority of our products to a low cost contract manufacturer in China, (2) a more favorable sales mix as we sold more higher margin casino printers and fewer lower margin banking printers in 2010 compared to 2009 and (3) increased volume of 17% offset by a decrease of 5% in average selling prices of our printers in 2010 compared to 2009. Additionally, our gross margin for 2009 was adversely impacted by higher material and labor costs as we depleted a substantial portion of our higher cost domestic inventory in preparation for the completion of our production transfer to China. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+3,000 
+$ 
+2,788 
+7.6 
+% 
+4.7 
+% 
+4.8 
+% 
+21 
+Table of Contents 
+Engineering, design and product development expenses increased $212,000, or 8%, to $3,000,000. The increase was due primarily to higher employee compensation related expenses resulting largely from annual salary increases and higher incentive compensation of $165,000, higher outside testing and pre-production expenses related to new product development of $20,000, and higher consulting expenses of $21,000 compared to 2009. 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+6,407 
+$ 
+5,821 
+10.1 
+% 
+10.1 
+% 
+10.0 
+% 
+Selling and marketing expenses for 2010 increased $586,000, or 10%, to $6,407,000. The increase was due primarily to approximately $182,000 of higher employee compensation related expenses associated with increased headcount within the sales departments and higher sales commissions resulting from higher sales volume, $275,000 of increased travel related expenses, $99,000 of increased tradeshow expenses, and $46,000 of higher demonstration printer expenses. These increases were somewhat offset by $13,000 decrease in other promotional marketing expenses compared to the prior year period. 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales – 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+7,280 
+$ 
+6,924 
+5.1 
+% 
+11.5 
+% 
+11.9 
+% 
+General and administrative expenses increased $356,000, or 5%, to $7,280,000. The increase was due primarily to $430,000 in increased employee compensation related expenses from annual salary increases and higher incentive compensation, as well as an increase of $115,000 in certain state and local taxes. These increases were largely offset by a reduction in legal and professional fee expenses of $150,000 and a reduction of depreciation expense of $55,000. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2010 
+2009 
+Change 
+Total Sales - 2010 
+Total Sales – 2009 
+Year ended 
+$ 
+5,861 
+$ 
+3,296 
+77.8 
+% 
+9.3 
+% 
+5.6 
+% 
+During 2010, we reported operating income of $5,861,000, or 9.3%, of net sales, compared to operating income of $3,296,000, or 5.6% of net sales in 2009. The increase in our operating income and operating margin was primarily due to higher gross profit resulting from the 8% increase in net sales and a 340 basis point improvement in gross margin in 2010 compared to 2009. 
+Interest. We recorded net interest expense of $9,000 in 2010 compared to $50,000 in 2009. The decrease in net interest expense is due to increased interest income earned on a higher average cash balance in 2010 compared to 2009, partially offset by $26,000 of interest expense incurred in 2010 related to certain prior years’ state and local tax liabilities. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2010 and 2009. See “Liquidity and Capital Resources” below for more information. 
+Other, net. We recorded other expense of $25,000 in 2010 compared to other expense of $33,000 in 2009. Other expense for 2010 and 2009 primarily included foreign currency transaction exchange losses recorded by our U.K. subsidiary. These losses were relatively consistent in 2010 compared to 2009. 
+Income Taxes. We recorded an income tax provision for 2010 of $1,923,000 at an effective tax rate of 33.0% compared to $1,073,000 at an effective tax rate of 33.4%. The effective tax rate for 2010 decreased slightly as compared to 2009 primarily due to increased utilization of state net operating losses and certain credits. 
+Net Income . We reported net income during 2010 of $3,904,000, or $0.41, per diluted share, compared to $2,140,000, or $0.23, per diluted share, for 2009. 
+22 
+Table of Contents 
+Liquidity and Capital Resources 
+We assess our liquidity in terms of our ability to generate cash to fund our operating, investing and financing activities. Significant factors affecting the management of liquidity are cash flows from operating activities, capital expenditures, stock repurchases, access to bank lines of credit and our ability to attract long-term capital with satisfactory terms. 
+Internal cash generation together with currently available cash and investments, available borrowing facilities and an ability to access credit lines, if needed, are expected to be sufficient to fund operations, capital expenditures, and any increase in working capital that would be required to accommodate a higher level of business activity. We actively seek to expand by acquisition as well as through the growth of our current business. While a significant acquisition may require additional debt and/or equity financing, although no assurances can be given, we believe that we would be able to obtain additional financing based on our historical earnings performance. 
+Cash Flow 
+During 2011, our cash balance decreased $4,422,000, or 39%, from December 31, 2010 and we ended 2011 with $6,863,000 in cash and cash equivalents and no debt outstanding. Our cash flows primarily reflected higher sales volume, the acquisition of Printrex, increased inventory purchasing, purchases of treasury stock and investment in the development of our new EPICENTRAL™ promotional printing system for the casino market . 
+Operating activities : The following significant factors primarily affected our cash provided by operating activities of $2,096,000 in 2011 as compared to $2,132,000 in 2010. During 2011: 
+· 
+We reported net income of $4,676,000. 
+· 
+We recorded depreciation, amortization and non-cash compensation expense of $2,195,000, including $139,000 of amortization related to intangible assets acquired from Printrex. 
+· 
+We recorded non-cash deferred income tax expense of $519,000. 
+· 
+Incremental tax benefits from stock options exercised were $498,000 . 
+· 
+Accounts receivable decreased $1,977,000 due to lower sales volume and the timing of sales during the fourth quarter of 2011 compared to the fourth quarter of 2010. 
+· 
+Inventories increased $568,000 due to lower than anticipated sales volume in the last six months of 2011. We have reduced our inventory purchases and expect our inventories to decline throughout 2012 as we fulfill sales from our existing inventory stock. 
+· 
+Accounts payable decreased $5,427,000 due to significantly lower inventory purchases and the timing of payments during the fourth quarter of 2011 compared to the fourth quarter of 2010. 
+· 
+Accrued liabilities and other liabilities decreased $352,000 due primarily to a reduction of income taxes payable resulting from the overpayment of our 2011 tax liability as certain tax credits were higher than anticipated. Correspondingly, we recorded refundable income taxes of $446,000. 
+During 2010: 
+· 
+We reported net income of $3,904,000. 
+· 
+We recorded depreciation, amortization and non-cash compensation expense of $2,114,000. 
+· 
+We recorded non-cash deferred income tax expense of $540,000. 
+· 
+Accounts receivable increased $1,878,000 due to higher sales volume and the timing of sales during the year. 
+· 
+Inventories increased $6,851,000 as we increased stocking levels of our lower cost, fully-built printers from our contract manufacturer in China in the first half of 2010. During the second half of 2010, inventory purchases were at a significantly higher level than the first half due to backlogged orders that were shipped in 2011. 
+· 
+Accounts payable increased $3,289,000 due to higher inventory purchases in the fourth quarter of 2010 in anticipation of significantly higher demand in the first half of 2011, and to a lesser extent, the timing of payments in the fourth quarter of 2010. 
+· 
+Accrued liabilities and other liabilities increased $625,000 due primarily to higher incentive compensation and fringe benefit related accruals as well as increased income taxes payable resulting from a higher level of taxable income. 
+Investing activities: On August 19, 2011, we completed the purchase of substantially all of the assets of Printrex for $4,000,000 in cash and potential future contingent consideration as previously discussed. 
+Our capital expenditures were $640,000 and $978,000 in 2011 and 2010, respectively. Expenditures in 2011 included $325,000 for the purchase of new product tooling, $235,000 for the purchase of computer, networking equipment, and software, $56,000 for the purchase of engineering equipment, and the remaining amount primarily for the purchase of manufacturing equipment, leasehold improvements and furniture and fixtures. Expenditures in 2010 included approximately $643,000 for the purchase of new product tooling, $269,000 for the purchase of computers, networking equipment, and software, $29,000 for the purchase of engineering equipment, and the remaining amount primarily for the purchase of manufacturing equipment, leasehold improvements and furniture and fixtures. Additionally, our capitalized software development costs for EPICENTRAL™ were $616,000 and $129,000 in 2011 and 2010, respectively. 
+23 
+Table of Contents 
+Capital expenditures for 2012 are expected to be approximately $1,500,000, primarily for new product tooling and tooling enhancements for our existing products. 
+Financing activities: We used $1,254,000 of cash from financing activities during 2011 to purchase $2,680,000 of common stock for treasury and $31,000 in financing costs associated with our amended TD Bank Credit Facility (as discussed below) offset by $1,457,000 of proceeds and incremental tax benefits from stock option exercises. During 2010, we generated $237,000 from financing activities due to $414,000 of proceeds and incremental tax benefits from stock option exercises offset by $177,000 of purchases of common stock for treasury. 
+Working Capital 
+Our working capital increased approximately 7% to $27,222,000 at December 31, 2011 from $25,525,000 at December 31, 2010. Our current ratio increased to 5.7 at December 31, 2011, compared to 3.2 at December 31, 2010. The increase in our working capital and current ratio was primarily due to lower accounts payable and accrued liabilities balances resulting from lower inventory purchases partially offset by lower cash and cash equivalents and accounts receivable balances in the fourth quarter of 2011 compared to 2010. 
+Resource Sufficiency 
+We believe that our cash and cash equivalents on hand and cash flows generated from operating activities will provide sufficient resources to meet our working capital needs, finance our capital expenditures and meet our liquidity requirements through at least the next twelve months. 
+Credit Facility and Borrowings 
+On November 22, 2011, we signed a three-year amendment to renew our existing $20,000,000 credit facility (the “TD Bank Credit Facility”) with TD Bank. The TD Bank Credit Facility provides for a $20,000,000 revolving credit line expiring on November 28, 2014. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent and are secured by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the revolving credit line. The total deferred financing costs relating to expenses incurred to complete the TD Bank Credit Facility was $31,000. The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur additional indebtedness, the payment of dividends on our common stock and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2011. The following table lists the financial covenants and the performance measurements at December 31, 2011: 
+Financial Covenant 
+Requirement/Restriction 
+Calculation at December 31, 2011 
+Operating cash flow / Total debt service 
+Minimum of 1.25 times 
+95.5 times 
+Funded debt / EBITDA 
+Maximum of 3.0 times 
+0 times 
+As of December 31, 2011, undrawn commitments under the TD Bank Credit facility were $20,000,000. 
+Stock Repurchase Program 
+On May 27, 2010, our Board of Directors approved a stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we are authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending May 27, 2013, depending on market conditions, share price and other factors. In March 2012, the Board of Directors approved an increase in our stock repurchase authorization under the Stock Repurchase Program to $15,000,000 from $10,000,000. During the fourth quarter of 2011, we repurchased 92,183 shares of our common stock for approximately $605,000 at an average price per share of $6.56. For the year ended December 31, 2011, we repurchased 275 ,255 shares of common stock for approximately $2,680,000 , at an average price of $9.74 per share, under the Stock Repurchase Program. At December 31, 2011, approximately $7,143,000 remains authorized for future repurchases under the Stock Repurchase Program. 
+Shareholders’ Equity 
+Shareholders’ equity increased $4,179,000 to $35,313,000 at December 31, 2011 from $31,134,000 at December 31, 2010. The increase was primarily due to net income of $4,676,000, proceeds and the associated incremental tax benefits of approximately $1,457,000 from the issuance of 239,074 shares of common stock from stock option exercises, compensation expense related to stock options and restricted stock of $587,000 and approximately $141,000 from the issuance of 14,323 shares of deferred stock units. These increases were offset by $2,680,000 for the purchase of 275,255 shares of treasury stock. 
+24 
+Table of Contents 
+Contractual Obligations 
+Our contractual obligations as of December 31, 2011 were as follows: 
+Payments due by period 
+(In thousands) 
+Total 
+< 1 year 
+1-3 years 
+3-5 years 
+> 5 years 
+Operating lease obligations 
+$ 
+2,349 
+$ 
+607 
+$ 
+757 
+$ 
+760 
+$ 
+225 
+Purchase obligations 
+7,580 
+7,311 
+269 
+- 
+- 
+Accrued contingent consideration 
+680 
+- 
+680 
+- 
+- 
+Total 
+$ 
+10,609 
+$ 
+7,918 
+$ 
+1,706 
+$ 
+760 
+$ 
+225 
+Purchase obligations are for purchases made in the normal course of business to meet operational requirements, primarily of fully assembled printers and component part inventory. Accrued contingent consideration consists of potential future obligations for performance-based cash payments in connection with the Printrex acquisition. 
+Recently Issued Accounting Pronouncements 
+Comprehensive Income : In June 2011, the Financial Accounting Standards Board (“FASB”) issued ASU 2011-05, “Comprehensive Income (Topic 220).” This Accounting Standards Update (“ASU”) revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in ASC 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Effective January 1, 2012, we will adopt the requirements of this ASU. 
+Intangibles – Goodwill and Other: In September 2011, the FASB issued ASU 2011-08, “Intangibles — Goodwill and Other (Topic 350) — Testing Goodwill for Impairment (revised standard).” The revised standard is intended to reduce the costs and complexity of the annual goodwill impairment test by providing entities an option to perform a “qualitative” assessment to determine whether further impairment testing is necessary. This ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We will consider this new guidance as we conduct our annual goodwill impairment testing in 2012 though we do not anticipate that it will have a material impact on our Consolidated Financial Statements. 
+Impact of Inflation 
+We believe that our business has not been affected to a significant degree by inflationary trends during the past three years. However, inflation is still a factor in the worldwide economy and may increase the cost of purchasing printers from our contract manufacturers in China, as well as the cost of certain raw materials, component parts and labor used in the production of our products. It also may increase our operating expenses, manufacturing overhead expenses and the cost to acquire or replace fixed assets. Despite continued growing costs of oil, gas and freight, we have generally been able to maintain or improve our profit margins through productivity and efficiency improvements, cost reduction programs and to a lesser extent, price increases, and we expect to be able to do the same during 2012. As such, we do not believe that inflation will have a significant impact on our business during 2012. 
+Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 
+Interest Rate Risk 
+Our exposure to market risk for changes in interest rates relates primarily to the investment of our available cash and cash equivalents. In accordance with our investment policy, we strive to achieve above market rates of return in exchange for accepting a prudent amount of incremental risk, which includes the risk of interest rate movements. Risk tolerance is constrained by an overriding objective to preserve capital. An increase or decrease of 10% in effective interest rates would not have a material effect on our results of operations or cash flows. 
+Foreign Currency Exchange Risk 
+A substantial portion of our sales are denominated in U.S. dollars and, as a result, we have relatively little exposure to foreign currency exchange risk with respect to sales made. This exposure may change over time as business practices evolve and could have a material adverse impact on our financial results in the future. We do not use forward exchange contracts to hedge exposures denominated in foreign currencies or any other derivative financial instruments for trading or speculative purposes. We estimate that the combined translational and transactional impact of a 10% overall movement in exchange rates from December 31, 2011 (principally the U.K. Pound Sterling) would not have a material impact on our results of operations or cash flows. 
+Item 8. Financial Statements and Supplementary Data. 
+The financial statements of the Company are annexed to this report as pages F-3 through F-19. An index to such materials appears on page F-1. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 
+None. 
+25 
+Table of Contents 
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2011, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2011. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Annual Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2011. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 
+Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2011. We excluded Printrex from our assessment of internal control over financial reporting as of December 31, 2011 because it was acquired by the Company in a purchase combination during the third quarter of 2011. The total assets (inclusive of goodwill and acquired intangible assets of approximately $3,190,000 or 7%) and total revenues of Printrex represent approximately 11% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011. 
+The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. 
+Item 9B. Other Information. 
+Not applicable. 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance. 
+The information in response to this item is incorporated by reference from the Proxy Statement sections entitled “Election of Directors” and “Executive Officers.” 
+Executive Officers of the Registrant 
+The following list is included as an unnumbered item in Part III of this Report in lieu of being included in the Proxy Statement for the Annual Meeting of Stockholders to be held on May 30, 2012. 
+The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. 
+Name 
+Age 
+Position 
+Bart C. Shuldman 
+54 
+Chairman of the Board and Chief Executive Officer 
+Steven A. DeMartino 
+42 
+President, Chief Financial Officer, Treasurer and Secretary 
+Michael S. Kumpf 
+62 
+Executive Vice President-Engineering 
+Tracey S. Chernay 
+52 
+Executive Vice President, Casino and Gaming Sales and Marketing 
+Andrew J. Hoffman 
+54 
+Senior Vice President-Operations 
+Benjamin C. Wyatt 
+38 
+Vice President-Software Products and Business Development 
+26 
+Table of Contents 
+Bart C. Shuldman has been Chief Executive Officer, President and a Director of the Company since its formation in June 1996. In February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman relinquished the President title, effective June 1, 2010, to focus on new products and markets, international expansion and potential acquisitions. 
+Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. 
+Michael S. Kumpf was appointed Executive Vice President of Engineering in March 2002. He served as Senior Vice President, Engineering from June 1996 to March 2002. 
+Tracey S. Chernay was appointed Executive Vice President, Casino and Gaming Sales and Marketing in June 2010, with responsibility for the sales and marketing of all casino and gaming printer products. Previously, Ms. Chernay served as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Sr. Vice President, Marketing & Sales, POS & Banking with the Company from July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. 
+Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice President, Operations from September 1994 to November 2004. 
+Benjamin C. Wyatt was appointed Vice President, Software Products and Business Development in December 2010. Previously, Mr. Wyatt served as Vice President, Business Development for TransAct from May 2008 to November 2010. Prior to joining TransAct, Mr. Wyatt was employed with Pitney Bowes Mail Services where he held the role of Director Business Development since 2006, and Manager Acquisitions and Integration from 2004 to 2006. 
+Item 11. Executive Compensation. 
+The information in response to this item is incorporated by reference from the Proxy Statement sections entitled “Executive Compensation and Certain Transactions” and “Compensation Discussion and Analysis.” 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Security Ownership of Certain Beneficial Owners and Management.” 
+Information regarding our equity compensation plans as of December 31, 2011 is as follows: 
+Plan category 
+(a) 
+Number of securities to be issued upon exercise of outstanding options, warrants and rights 
+(b) 
+Weighted-average exercise price of outstanding options, warrants and rights 
+(c) 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) 
+Equity compensation plans approved by security holders: 
+1996 Stock Plan 
+12,625 
+$ 
+3.77 
+- 
+1996 Non-Employee Director Plan 
+90,000 
+15.54 
+- 
+2005 Equity Incentive Plan 
+729,613 
+7.23 
+406,673 
+Total 
+832,238 
+$ 
+8.07 
+406,673 
+Equity compensation plans not approved by security holders: 
+2001 Employee Stock Plan 
+8,997 
+$ 
+8.91 
+- 
+841,235 
+$ 
+8.08 
+406,673 
+The TransAct Technologies Incorporated 2001 Employee Stock Plan was adopted by our Board of Directors, without approval of our security holders, effective February 26, 2001. The Company also maintains the 2005 Equity Incentive Plan which was approved by our shareholders. The number of shares of common stock which may be subject to awards granted under the plan is 1,200,000. No new awards will be available for future issuance under any of our existing equity plans other than the 2005 Equity Incentive Plan. 
+27 
+Table of Contents 
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Certain Relationships and Related Transactions.” 
+Item 14. Principal Accountant Fees and Services. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Independent Registered Public Accounting Firm’s Services and Fees.” 
+PART IV 
+Item 15. Exhibits. 
+The exhibits filed as a part of this report are listed in the accompanying Index to Exhibits. 
+28 
+Table of Contents 
+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. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+By: 
+/s/ Bart C. Shuldman 
+Name: 
+Bart C. Shuldman 
+Title: 
+Chairman of the Board and Chief Executive Officer 
+Date: March 12, 2012 
+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/ Bart C. Shuldman 
+Chairman of the Board 
+March 12, 2012 
+Bart C. Shuldman 
+and Chief Executive Officer, 
+(Principal Executive Officer) 
+/s/ Steven A. DeMartino 
+President, Chief Financial Officer, 
+March 12, 2012 
+Steven A. DeMartino 
+Treasurer and Secretary 
+(Principal Financial and Accounting Officer) 
+/s/ Charles A. Dill 
+Director 
+March 12, 2012 
+Charles A. Dill 
+/s/ John M. Dillon 
+Director 
+March 12, 2012 
+John M. Dillon 
+/s/ Thomas R. Schwarz 
+Director 
+March 12, 2012 
+Thomas R. Schwarz 
+/s/ Graham Y. Tanaka 
+Director 
+March 12, 2012 
+Graham Y. Tanaka 
+29 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX TO FINANCIAL STATEMENTS 
+Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Consolidated Balance Sheets as of December 31, 2011 and 2010 
+F-3 
+Consolidated Statements of Income for the years ended December 31, 2011, 2010 and 2009 
+F-4 
+Consolidated Statements of Changes in Shareholders' Equity and Comprehensive Income for the years ended December 31, 2011, 2010 and 2009 
+F-5 
+Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 
+All other financial statement schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or notes thereto. 
+F-1 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+To the Board of Directors and Shareholders of TransAct Technologies Incorporated: 
+In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TransAct Technologies Incorporated and its subsidiaries at December 31, 2011 and December 31, 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. Also in our opinion, the Company 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 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 Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which were integrated audits in 2011 and 2009). 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. 
+As described in Management's Annual Report on Internal Control Over Financial Reporting, management has excluded Printrex, Inc. from its assessment of internal control over financial reporting as of December 31, 2011 because it was acquired by the Company in a purchase business combination during 2011. We have also excluded Printrex, Inc. from our audit of internal control over financial reporting. Printrex, Inc. is a wholly-owned subsidiary whose total assets and total revenues represent approximately 4% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011. 
+/s/ PricewaterhouseCoopers LLP 
+Hartford, Connecticut 
+March 12, 2012 
+F-2 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+December 31, 
+2011 
+2010 
+Assets: 
+Current assets: 
+Cash and cash equivalents 
+$ 
+6,863 
+$ 
+11,285 
+Accounts receivable, net 
+9,583 
+10,864 
+Inventories 
+14,151 
+12,795 
+Refundable income taxes 
+446 
+- 
+Deferred tax assets 
+1,636 
+1,705 
+Other current assets 
+375 
+403 
+Total current assets 
+33,054 
+37,052 
+Fixed assets, net 
+3,358 
+4,071 
+Goodwill 
+2,518 
+1,469 
+Deferred tax assets 
+890 
+789 
+Intangible assets, net of accumulated amortization of $730 and $475, respectively 
+2,861 
+221 
+Other assets 
+59 
+19 
+9,686 
+6,569 
+Total assets 
+$ 
+42,740 
+$ 
+43,621 
+Liabilities and Shareholders’ Equity: 
+Current liabilities: 
+Accounts payable 
+$ 
+3,019 
+$ 
+8,342 
+Accrued liabilities 
+2,672 
+2,865 
+Deferred revenue 
+141 
+320 
+Total current liabilities 
+5,832 
+11,527 
+Deferred revenue, net of current portion 
+224 
+295 
+Deferred rent, net of current portion 
+357 
+393 
+Accrued contingent consideration (Note 4) 
+680 
+- 
+Other liabilities 
+334 
+272 
+1,595 
+960 
+Total liabilities 
+7,427 
+12,487 
+Commitments and contingencies (Note 12) 
+Shareholders’ equity: 
+Preferred stock, $0.01 par value, 4,800,000 authorized, none issued and outstanding 
+- 
+- 
+Preferred stock, Series A, $0.01 par value, 200,000 authorized, none issued and outstanding 
+- 
+- 
+Common stock, $0.01 par value, 20,000,000 authorized at December 31, 2011 and 2010; 10,851,955 and 10,612,881 shares issued; 9,390,262 and 9,426,443 shares outstanding, at December 31, 2011 and 2010, respectively 
+108 
+106 
+Additional paid-in capital 
+25,058 
+22,875 
+Retained earnings 
+21,613 
+16,937 
+Accumulated other comprehensive loss, net of tax 
+(71 
+) 
+(69 
+) 
+Treasury stock, 1,461,693 and 1,186,438 shares, at cost 
+(11,395 
+) 
+(8,715 
+) 
+Total shareholders’ equity 
+35,313 
+31,134 
+Total liabilities and shareholders’ equity 
+$ 
+42,740 
+$ 
+43,621 
+See accompanying notes to Consolidated Financial Statements. 
+F-3 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF INCOME 
+(In thousands, except per share data) 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Net sales 
+$ 
+65,969 
+$ 
+63,194 
+$ 
+58,346 
+Cost of sales 
+41,343 
+40,646 
+39,517 
+Gross profit 
+24,626 
+22,548 
+18,829 
+Operating expenses: 
+Engineering, design and product development 
+3,418 
+3,000 
+2,788 
+Selling and marketing 
+6,402 
+6,407 
+5,821 
+General and administrative 
+7,633 
+7,280 
+6,924 
+Business consolidation and restructuring (Note 9) 
+184 
+- 
+- 
+17,637 
+16,687 
+15,533 
+Operating income 
+6,989 
+5,861 
+3,296 
+Interest and other income (expense): 
+Interest expense 
+(69 
+) 
+(96 
+) 
+(70 
+) 
+Interest income 
+87 
+87 
+20 
+Other, net 
+1 
+(25 
+) 
+(33 
+) 
+19 
+(34 
+) 
+(83 
+) 
+Income before income taxes 
+7,008 
+5,827 
+3,213 
+Income tax provision 
+2,332 
+1,923 
+1,073 
+Net income 
+$ 
+4,676 
+$ 
+3,904 
+$ 
+2,140 
+Net income per common share: 
+Basic 
+$ 
+0.50 
+$ 
+0.42 
+$ 
+0.23 
+Diluted 
+$ 
+0.49 
+$ 
+0.41 
+$ 
+0.23 
+Shares used in per-share calculation: 
+Basic 
+9,443 
+9,390 
+9,289 
+Diluted 
+9,603 
+9,590 
+9,377 
+See accompanying notes to Consolidated Financial Statements. 
+F-4 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME 
+(In thousands, except share data) 
+Common Stock 
+Additional Paid-in 
+Retained 
+Treasury 
+Accumulated Other Comprehensive 
+Total Comprehensive 
+Shares 
+Amount 
+Capital 
+Earnings 
+Stock 
+Income (Loss) 
+Total 
+Income 
+Balance, December 31, 2008 
+9,301,488 
+$ 
+105 
+$ 
+20,890 
+$ 
+10,893 
+$ 
+(8,538 
+) 
+$ 
+(68 
+) 
+$ 
+23,282 
+Cancellation of restricted stock 
+(500 
+) 
+- 
+- 
+- 
+- 
+- 
+- 
+Issuance of shares from exercise of stock options 
+63,121 
+- 
+211 
+- 
+- 
+- 
+211 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+79 
+- 
+- 
+- 
+79 
+Share-based compensation expense 
+- 
+- 
+640 
+- 
+- 
+- 
+640 
+Comprehensive income: 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+2 
+2 
+$ 
+2 
+Net income 
+- 
+- 
+- 
+2,140 
+- 
+- 
+2,140 
+2,140 
+Balance, December 31, 2009 
+9,364,109 
+105 
+21,820 
+13,033 
+(8,538 
+) 
+(66 
+) 
+26,354 
+2,142 
+Issuance of shares from exercise of stock options 
+84,672 
+1 
+392 
+- 
+- 
+- 
+393 
+Issuance of deferred stock units 
+- 
+- 
+77 
+- 
+- 
+- 
+77 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+21 
+- 
+- 
+- 
+21 
+Purchase of treasury stock 
+(22,338 
+) 
+- 
+- 
+- 
+(177 
+) 
+- 
+(177 
+) 
+Share-based compensation expense 
+- 
+- 
+565 
+- 
+- 
+- 
+565 
+Comprehensive income: 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(3 
+) 
+(3 
+) 
+$ 
+(3 
+) 
+Net income 
+- 
+- 
+- 
+3,904 
+- 
+- 
+3,904 
+3,904 
+Balance, December 31, 2010 
+9,426,443 
+106 
+22,875 
+16,937 
+(8,715 
+) 
+(69 
+) 
+31,134 
+3,901 
+Issuance of shares from exercise of stock options 
+239,074 
+2 
+957 
+- 
+- 
+- 
+959 
+Issuance of deferred stock units 
+- 
+- 
+141 
+- 
+- 
+- 
+141 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+498 
+- 
+- 
+- 
+498 
+Purchase of treasury stock 
+(275,255 
+) 
+- 
+- 
+- 
+(2,680 
+) 
+- 
+(2,680 
+) 
+Share-based compensation expense 
+- 
+- 
+587 
+- 
+- 
+- 
+587 
+Comprehensive income: 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(2 
+) 
+(2 
+) 
+$ 
+(2 
+) 
+Net income 
+- 
+- 
+- 
+4,676 
+- 
+- 
+4,676 
+4,676 
+Balance, December 31, 2011 
+9,390,262 
+$ 
+108 
+$ 
+25,058 
+$ 
+21,613 
+$ 
+(11,395 
+) 
+$ 
+(71 
+) 
+$ 
+35,313 
+$ 
+4,674 
+See accompanying notes to Consolidated Financial Statements. 
+F-5 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Cash flows from operating activities: 
+Net income 
+$ 
+4,676 
+$ 
+3,904 
+$ 
+2,140 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Share-based compensation expense 
+587 
+565 
+640 
+Incremental tax benefits from stock options exercised 
+(498 
+) 
+(21 
+) 
+(79 
+) 
+Depreciation and amortization 
+1,608 
+1,549 
+1,757 
+Deferred income taxes 
+519 
+540 
+1,002 
+Loss on sale of fixed assets 
+24 
+2 
+- 
+Foreign currency transaction (gains) losses 
+(6 
+) 
+21 
+33 
+Changes in operating assets and liabilities: 
+Accounts receivable 
+1,977 
+(1,878 
+) 
+(263 
+) 
+Inventories 
+(568 
+) 
+(6,851 
+) 
+3,968 
+Refundable income taxes 
+(446 
+) 
+270 
+(235 
+) 
+Other current and long term assets 
+2 
+117 
+(135 
+) 
+Accounts payable 
+(5,427 
+) 
+3,289 
+187 
+Accrued liabilities and other liabilities 
+(352 
+) 
+625 
+(642 
+) 
+Net cash provided by operating activities 
+2,096 
+2,132 
+8,373 
+Cash flows from investing activities: 
+Capital expenditures 
+(640 
+) 
+(978 
+) 
+(643 
+) 
+Additions to capitalized software 
+(616 
+) 
+(129 
+) 
+- 
+Proceeds from sale of fixed assets 
+1 
+10 
+- 
+Acquisitions 
+(4,000 
+) 
+- 
+- 
+Net cash used in investing activities 
+(5,255 
+) 
+(1,097 
+) 
+(643 
+) 
+Cash flows from financing activities: 
+Proceeds from stock option exercises 
+959 
+393 
+211 
+Purchases of common stock for treasury 
+(2,680 
+) 
+(177 
+) 
+- 
+Incremental tax benefits from stock options exercised 
+498 
+21 
+79 
+Payment of deferred financing costs 
+(31 
+) 
+- 
+- 
+Net cash (used in) provided by financing activities 
+(1,254 
+) 
+237 
+290 
+Effect of exchange rate changes on cash and cash equivalents 
+(9 
+) 
+(4 
+) 
+(3 
+) 
+(Decrease) increase in cash and cash equivalents 
+(4,422 
+) 
+1,268 
+8,017 
+Cash and cash equivalents, beginning of period 
+11,285 
+10,017 
+2,000 
+Cash and cash equivalents, end of period 
+$ 
+6,863 
+$ 
+11,285 
+$ 
+10,017 
+Supplemental cash flow information: 
+Interest paid 
+$ 
+51 
+$ 
+51 
+$ 
+51 
+Income taxes paid 
+2,545 
+740 
+482 
+Non-cash financing activities 
+Purchases of common stock for treasury at year end 
+$ 
+(61 
+) 
+$ 
+- 
+$ 
+- 
+See accompanying notes to Consolidated Financial Statements. 
+F-6 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. Description of business 
+TransAct Technologies Incorporated (“TransAct” or the “Company”), which has its headquarters in Hamden, CT and its primary operating facility in Ithaca, NY, operates in one operating segment: market specific printers for transaction-based and other industries. These industries include casino, gaming, lottery, banking, kiosk, point-of-sale, oil and gas and medical and mobile. Our printers are designed based on market-specific requirements and are sold under the Ithaca®, Epic and Printrex® product brands. We distribute our products through OEMs, value-added resellers, selected distributors, and directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. We also generate revenue from the after-market side of the business, providing printer service, supplies and spare parts. 
+2. Summary of significant accounting policies 
+Principles of consolidation: The accompanying Consolidated Financial Statements include the accounts of TransAct and its wholly-owned subsidiaries, which require consolidation, after the elimination of intercompany accounts, transactions and unrealized profit. 
+Reclassifications: Certain amounts in the prior years’ financial statements have been reclassified to conform to the current year’s presentation. 
+Use of estimates: The accompanying Consolidated Financial Statements were prepared using estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and disclosure of contingent assets and liabilities as of the date of the Consolidated Financial Statements and the reported amounts of sales and expenses during the reporting period. Actual results could differ from those estimates. 
+Segment reporting: We apply the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” We view our operations and manage our business as one segment: the design, development, manufacture and sale of transaction-based and specialty printers and printer-related service, supplies and replacement parts . Factors used to identify TransAct’s single operating segment include the organizational structure of the Company and the financial information available for evaluation by the chief operating decision-maker in making decisions about how to allocate resources and assess performance. 
+Cash and cash equivalents: We consider all highly liquid investments with a maturity date of three months or less at date of purchase to be cash equivalents. 
+Allowance for doubtful accounts: We establish an allowance for doubtful accounts to ensure trade receivables are valued appropriately. We maintain an allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, significant one-time events and historical experience. We record a specific allowance for individual accounts when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, we would further adjust estimates of the recoverability of receivables. Allowances for doubtful accounts on accounts receivable balances were $70,000 as of December 31, 2011 and $57,000 as of December 31, 2010. 
+The following table summarizes the activity recorded in the valuation account for accounts receivable: 
+Year ended December 31, 
+(In thousands) 
+2011 
+2010 
+2009 
+Balance, beginning of period 
+$ 
+57 
+$ 
+57 
+$ 
+55 
+Additions charged to costs and expenses 
+1 
+- 
+3 
+Acquisition of business 
+15 
+- 
+- 
+Deductions 
+(3 
+) 
+- 
+(1 
+) 
+Balance, end of period 
+$ 
+70 
+$ 
+57 
+$ 
+57 
+Inventories: Inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. 
+Fixed assets: Fixed assets are stated at cost. Depreciation is recorded using the straight-line method over the estimated useful lives. The estimated useful life of tooling is five years; machinery and equipment is ten years; furniture and office equipment is five to ten years; and computer software and equipment is three to seven years. Leasehold improvements are amortized over the shorter of the term of the lease or the useful life of the asset. Costs related to repairs and maintenance are expensed as incurred. The costs of sold or retired assets are removed from 
+F-7 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+the related asset and accumulated depreciation accounts and any gain or loss is recognized. Depreciation expense was $1,339,000, $1,446,000 and $1,655,000 in 2011, 2010 and 2009, respectively. 
+Leases: Rent expense under non-cancelable operating leases with scheduled rent increases or free rent periods are accounted for on a straight-line basis over the lease term, beginning on the date of control of physical use of the asset or of initial possession. The amount of the excess of straight-line rent expense over scheduled payments is recorded as a deferred liability. Construction allowances and other such lease incentives are recorded as deferred credits, and are amortized on a straight-line basis as a reduction of rent expense beginning in the period they are deemed to be earned, which generally coincides with the occupancy date. 
+Goodwill and Intangible assets: We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with Accounting Standards Codification (“ASC”) 350-20 “Goodwill”, acquired goodwill is not amortized but is subject to impairment testing at least annually and when an event occurs or circumstances change, that indicate it is more likely than not an impairment exists. Factors considered that may trigger an impairment review are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Definite lived intangible assets are amortized and are tested for impairment when appropriate. We have determined that no goodwill or intangible asset impairment has occurred based on our assessment during 2011. 
+Revenue recognition: Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within ASC 605, “Revenue Recognition” (ASC 605). Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms, which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We account for all revenue arrangements involving multiple deliverables in accordance with ASC 605-25, “Multiple-Element Arrangements.” For these arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Concentration of credit risk: Financial instruments that potentially expose TransAct to concentrations of credit risk are limited to cash and cash equivalents held by our banks in excess of insured limits and accounts receivable. 
+F-8 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Accounts receivable from customers representing 10% or more of total accounts receivable were as follows: 
+December 31, 
+2011 
+2010 
+GTECH 
+13 
+% 
+17 
+% 
+Customer A 
+20 
+% 
+22 
+% 
+Sales to customers representing 10% or more of total net sales were as follows: 
+Year ended December 31, 
+2011 
+2010 
+2009 
+GTECH 
+26 
+% 
+12 
+% 
+19 
+% 
+Customer A 
+13 
+% 
+14 
+% 
+10 
+% 
+Customer B 
+* 
+* 
+12 
+% 
+* - Customers represent less than 10% of total net sales 
+Warranty: We generally warrant our products for up to 36 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. 
+The following table summarizes the activity recorded in the accrued product warranty liability: 
+Year ended December 31, 
+(In thousands) 
+2011 
+2010 
+2009 
+Balance, beginning of period 
+$ 
+249 
+$ 
+233 
+$ 
+393 
+Accruals for warranties issued during the period 
+146 
+84 
+112 
+Changes in estimates 
+326 
+172 
+(96 
+) 
+Acquisition of business 
+25 
+- 
+- 
+Settlements during the period 
+(325 
+) 
+(240 
+) 
+(176 
+) 
+Balance, end of period 
+$ 
+421 
+$ 
+249 
+$ 
+233 
+Approximately $106,000 and $71,000 of the accrued product warranty liability were classified as long-term at December 31, 2011 and 2010, respectively. 
+Research and development expenses: Research and development expenses include engineering, design and product development expenses incurred in connection with specialized engineering and design to introduce new products and to customize existing products, and are expensed as a component of operating expenses as incurred. We recorded approximately $3,418,000, $3,000,000 and $2,788,000 of research and development expenses in 2011, 2010 and 2009, respectively. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. During 2010 we began the development of a new software product that enables casino customers to print coupons and promotions at the slot machine. Unamortized development costs for such software were approximately $682,000 and $129,000 as of December 31, 2011 and 2010, respectively. The total amount charged to cost of sales for capitalized software development costs was approximately $62,000 in 2011 with no such charges in 2010. The weighted-average amortization period of capitalized software developments costs is 4 years. 
+Advertising: Advertising costs are expensed as incurred. Advertising expenses, which are included in selling and marketing expense on the accompanying Consolidated Statements of Income, for 2011, 2010 and 2009 totaled $871,000, $824,000 and $763,000, respectively. These expenses include items such as consulting and professional services, tradeshows, and print advertising. 
+F-9 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Restructuring: We continually evaluate our cost structure to ensure that it is appropriately positioned to respond to changing market conditions. We record pre-tax restructuring charges in accordance with ASC 420-10-25-4, “Exit or Disposal Cost Obligations.” See Note 9 for further discussion. 
+Income taxes: The income tax amounts reflected in the accompanying Consolidated Financial Statements are accounted for under the liability method in accordance with ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. We assess the likelihood that net deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. In accordance with ASC 740, we identified, evaluated and measured the amount of benefits to be recognized for our tax return positions. See Note 14 for information regarding our accounting for income taxes. 
+Foreign currency translation: The financial position and results of operations of our foreign subsidiary in the United Kingdom are measured using local currency as the functional currency. Assets and liabilities of such subsidiary have been translated into U.S. dollars at the year-end exchange rate, related sales and expenses have been translated at the average exchange rate for the year, and shareholders’ equity has been translated at historical exchange rates. The resulting translation gains or losses, net of tax, are recorded in shareholders’ equity as a cumulative translation adjustment, which is a component of accumulated other comprehensive income. Foreign currency transaction gains and losses, including those related to intercompany balances, are recognized in Other, net on the Consolidated Statements of Income. 
+Share-based Payments: At December 31, 2011, we had share-based employee compensation plans, which are described more fully in Note 13 - Stock incentive plans. We account for those plans under the recognition and measurement principles of ASC 718, “Compensation – Stock Compensation.” Share-based compensation expense is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. We have no awards with market or performance conditions. 
+We use the Black-Scholes option-pricing model to calculate the fair value of share based awards. The key assumptions for this valuation method include the expected term of the option, stock price volatility, risk-free interest rate, dividend yield, market price of our underlying stock and exercise price. Many of these assumptions are judgmental and highly sensitive in the determination of compensation expense. In addition, we estimate forfeitures when recognizing compensation expense, and we adjust our estimate of forfeitures over the requisite service period based on the extent to which actual forfeitures differ, or are expected to differ, from such estimates. Changes in estimated forfeitures are recognized through a cumulative true-up adjustment in the period of change and also impacts the amount of compensation expense to be recognized in future periods. 
+Net income and loss per share: We report net income or loss per share in accordance with ASC 260, “Earnings per Share (EPS).” Under this guidance, basic EPS, which excludes dilution, is computed by dividing income or loss available to common shareholders by the weighted average number of common shares outstanding for the period. Unvested restricted stock is excluded from the calculation of weighted average common shares for basic EPS. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted EPS includes restricted stock and in-the-money stock options using the treasury stock method. During a loss period, the assumed exercise of in-the-money stock options has an anti-dilutive effect, and therefore, these instruments are excluded from the computation of dilutive EPS. See Note 15 - Earnings per Share. 
+3. Recently issued accounting pronouncements 
+Comprehensive Income : In June 2011, the FASB issued ASU 2011-05, “Comprehensive Income (Topic 220).” This ASU revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in ASC 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Effective January 1, 2012, we will adopt the requirements of this ASU. 
+Intangibles – Goodwill and Other: In September 2011, the FASB issued ASU 2011-08, “Intangibles — Goodwill and Other (Topic 350) — Testing Goodwill for Impairment (revised standard).” The revised standard is intended to reduce the costs and complexity of the annual goodwill impairment test by providing entities an option to perform a “qualitative” assessment to determine whether further impairment testing is necessary. This ASU is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 
+F-10 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+3. Recently issued accounting pronouncements (continued) 
+2011. We will consider this new guidance as we conduct our annual goodwill impairment testing in 2012 though we do not anticipate that it will have a material impact on our Consolidated Financial Statements. 
+4. Business acquisitions 
+On August 19, 2011, we completed the purchase of substantially all of the assets of Printrex for $4,000,000 in cash and potential future contingent consideration further discussed below. Printrex is a leading manufacturer of specialty printers primarily sold into the oil and gas exploration and medical markets which serve commercial and industrial customers primarily in the United States, Canada, Europe and Asia. This acquisition was completed primarily to expand our product offerings into the oil and gas exploration and medical markets. The Company is in the process of completing its analysis of fair value attributes of the assets acquired related to the Printrex acquisition and anticipates that the final assessment of values will not defer materially from the preliminary assessment. 
+The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed related to the Printrex acquisition: 
+Purchase Price Allocation (In thousands) : 
+Receivables 
+$ 
+673 
+Inventories 
+780 
+Fixed assets 
+11 
+Other current assets 
+6 
+Intangible assets 
+2,280 
+Goodwill 
+1,049 
+Other assets 
+22 
+Liability related to potential future contingent consideration 
+(680 
+) 
+Other liabilities 
+(141 
+) 
+Total purchase price 
+$ 
+4,000 
+Intangible Assets: 
+Customer relationships 
+$ 
+1,300 
+Trademark 
+480 
+Developed technology 
+420 
+Other 
+80 
+Total Intangible assets 
+$ 
+2,280 
+Intangible Asset Weighted Average Amortization Period: 
+Customer relationships 
+6 years 
+Trademark 
+10 years 
+Developed technology 
+9 years 
+Other 
+1.2 years 
+Total weighted average 
+7.2 years 
+The fair values assigned to intangible assets were determined through the use of the income approach, specifically the relief from royalty method and the multi-period excess earnings method. The valuation of tangible assets was derived using a combination of the income approach, the market approach and the cost approach. 
+The fair value of trade accounts receivables acquired is $623,000 and other receivables is $50,000. The gross contractual amount due on these trade accounts receivable is approximately $638,000, of which $15,000 is expected to be uncollectible. 
+We entered into a contingent consideration arrangement with Printrex as part of the acquisition for 30% of the gross profit for a three-year period related to new products under development, less certain other adjustments, beginning on the earlier of 1) January 1, 2012 or 2) the date of first commercial introduction of the new products under development. The undiscounted fair value related to the contingent liability could range from $100,000 to $1,800,000. The fair value of the contingent consideration arrangement of $680,000 was estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which fair value measurement guidance refers to as Level 3 inputs. 
+Key assumptions include a discount rate range of 5% to 6% and a probability-adjusted level of gross profit between $1,300,000 and $7,000,000. 
+F-11 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+4. Business Acquisitions (continued) 
+The Printrex acquisition resulted in $1,049,000 of goodwill, which is deductible for tax purposes, and largely consists of expected synergies resulting from the acquisition. Key areas of potential cost savings include increased purchasing power for raw materials; manufacturing and supply chain work process improvements; and the elimination of redundant manufacturing overhead and operating expenses. We also anticipate that the transaction will produce growth synergies as a result of applying TransAct’s sales and engineering expertise to Printrex’s products. 
+In January 2012, we determined that we no longer need to maintain the existing Printrex manufacturing facility in San Jose, California, along with certain redundant headcount. This decision will enable us to utilize the space in our existing facilities while also gaining the efficiencies and operational excellence from our team in Ithaca, NY. As a result, we plan to transition all San Jose manufacturing operations to our Ithaca, NY facility, and all San Jose service operations to our Las Vegas, NV facility, by the end of August 2012. As part of this transition, we plan to maintain the San Jose engineering group and relocate them to a new, smaller facility in the San Jose area. 
+The change in carrying value of goodwill for the year ended December 31, 2011 was as follows (in thousands): 
+Balance at December 31, 2010 
+$ 
+1,469 
+August 2011 Printrex acquisition 
+1,049 
+Balance at December 31, 2011 
+$ 
+2,518 
+We incurred acquisition-related costs of $159,000 during the year ended December 31, 2011. These costs included legal, accounting, valuation and other professional services and were included in general and administrative expenses in the Consolidated Statements of Income. In addition, we incurred approximately $78,000 of integration-related expenses in 2011 that were also included in general and administrative expenses in the Consolidated Statements of Income. 
+The Printrex acquisition contributed $1,892,000 to net sales and reduced net income by $23,000 for the year ended December 31, 2011. This reduction includes the after-tax impact of $139,000 of amortization expense from the intangible assets acquired from Printrex as well as $78,000 of integration expenses. The following unaudited pro forma consolidated results of operations are provided for illustrative purposes only and assume that the acquisition of Printrex occurred on January 1, 2010. This unaudited pro forma information should not be relied upon as being indicative of the historical results that would have been obtained if the acquisition had occurred on that date, nor of the results that may be obtained in the future. 
+Year ended December 31, 
+(In thousands) 
+2011 
+2010 
+Sales 
+$ 
+69,694 
+$ 
+68,617 
+Net income 
+$ 
+5,025 
+$ 
+3,865 
+5. Inventories 
+The components of inventories are: 
+December 31, 
+(In thousands) 
+2011 
+2010 
+Raw materials and purchased component parts 
+$ 
+6,863 
+$ 
+5,077 
+Work-in-process 
+71 
+2 
+Finished goods 
+7,217 
+7,716 
+$ 
+14,151 
+$ 
+12,795 
+F-12 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+6. Fixed assets 
+The components of fixed assets, net are: 
+December 31, 
+(In thousands) 
+2011 
+2010 
+Tooling, machinery and equipment 
+$ 
+12,463 
+$ 
+12,207 
+Furniture and office equipment 
+1,543 
+1,659 
+Computer software and equipment 
+5,315 
+4,991 
+Leasehold improvements 
+1,763 
+1,888 
+21,084 
+20,745 
+Less: Accumulated depreciation and amortization 
+(18,053 
+) 
+(17,296 
+) 
+3,031 
+3,449 
+Construction in-process 
+327 
+622 
+$ 
+3,358 
+$ 
+4,071 
+7. Intangible assets 
+Identifiable intangible assets are recorded in Intangible assets in the accompanying Consolidated Balance Sheets and are comprised of the following: 
+December 31, 
+2011 
+2010 
+(In thousands) 
+Gross Amount 
+Accumulated Amortization 
+Gross Amount 
+Accumulated Amortization 
+Purchased technology 
+$ 
+1,528 
+$ 
+(443 
+) 
+$ 
+493 
+$ 
+(334 
+) 
+Customer relationships 
+1,300 
+(79 
+) 
+- 
+- 
+Trademark 
+480 
+(18 
+) 
+- 
+- 
+Covenant not to compete 
+146 
+(136 
+) 
+146 
+(115 
+) 
+Patents 
+57 
+(29 
+) 
+57 
+(26 
+) 
+Other 
+80 
+(25 
+) 
+- 
+- 
+Total 
+$ 
+3,591 
+$ 
+(730 
+) 
+$ 
+696 
+$ 
+(475 
+) 
+Amortization expense was $255,000 in 2011, $85,000 in 2010 and $84,000 in 2009, respectively. Amortization expense for each of the next five years ending December 31 is expected to be as follows: $565,000 in 2012; $501,000 in 2013; $500,000 in 2014; $441,000 in 2015; $315,000 in 2016; and $539,000 thereafter. 
+8. Accrued liabilities 
+The components of accrued liabilities are: 
+December 31, 
+(In thousands) 
+2011 
+2010 
+Payroll and fringe benefits 
+$ 
+1,702 
+$ 
+1,736 
+Income taxes 
+40 
+359 
+Warranty 
+315 
+178 
+Professional and consulting 
+95 
+111 
+Other 
+520 
+481 
+$ 
+2,672 
+$ 
+2,865 
+9. Accrued business consolidation and restructuring expenses 
+During 2011, we closed our New Britain, CT service facility which primarily serviced our first generation legacy impact printers for GTECH and incurred certain facility closure and severance costs. We no longer needed to maintain this facility since these printers have been replaced by our thermal lottery printers. These restructuring activities reduced the number of employees and closed a facility, which caused us to incur costs for employee termination benefits related to these employee reductions as well as lease termination costs and the disposal of fixed assets. During the year ended December 31, 2011, we recorded a restructuring charge of $184,000, in accordance with FASB ASC 420-10-25-4 “Exit 
+F-13 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+9. Accrued business consolidation and restructuring expenses (continued) 
+or Disposal Cost Obligations” which has been included within Business consolidation and restructuring expenses in the accompanying Consolidated Statements of Income. Cash payments to be made under this restructuring plan should be complete by March 2012. 
+In 2010, due to the completion of the move of a substantial portion of our printer production to a contract manufacturer in China, we initiated and completed certain restructuring programs to better utilize our workforce. These restructuring activities reduced the number of employees and caused us to incur costs for employee termination benefits related to the employee reductions. During 2010, we recorded pre-tax restructuring charges of approximately $156,000 which were included within general and administrative expenses in the accompanying Consolidated Statements of Income. The restructuring activity during 2010 included severance costs related to the termination of 16 employees. 
+The following table summarizes the activity recorded in accrued restructuring expenses during 2011 and 2010, and is included in accrued liabilities in the accompanying Consolidated Balance Sheets. 
+December 31, 
+(In thousands) 
+2011 
+2010 
+Accrual balance, beginning of period 
+$ 
+- 
+$ 
+13 
+Severance charges 
+134 
+156 
+Non-cancelable lease payments 
+26 
+- 
+Cash payments 
+(115 
+) 
+(169 
+) 
+Accrual balance, end of period 
+$ 
+45 
+$ 
+- 
+10. Retirement savings plan 
+We maintain a 401(k) plan under which all full-time employees are eligible to participate at the beginning of each month immediately following their date of hire. We match employees’ contributions at a rate of 50% of employees’ contributions up to the first 6% of the employees’ compensation contributed to the 401(k) plan. Our matching contributions were $201,000, $223,000 and $237,000 in 2011, 2010 and 2009, respectively. 
+11. Borrowings 
+On November 22, 2011, we signed an amendment to renew our existing three-year $20,000,000 credit facility (the “TD Bank Credit Facility”) with TD Bank. The TD Bank Credit Facility provides for a $20,000,000 revolving credit line expiring on November 28, 2014. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent and are secured by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the revolving credit line. The total deferred financing costs relating to expenses incurred to complete the TD Bank Credit Facility was $31,000 which will be amortized over the three year term. The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur additional indebtedness, the payment of dividends on our common stock and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2011. 
+As of December 31, 2011, undrawn commitments under the TD Bank Credit Facility were $20,000,000. 
+12. Commitments and contingencies 
+At December 31, 2011, we were the lessee on operating leases for equipment and real property. Rent expense was approximately $1,030,000, $1,047,000 and $1,024,000 in 2011, 2010 and 2009, respectively. Minimum aggregate rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2011 are as follows: $607,000 in 2012; $385 ,000 in 2013; $372,000 in 2014; $378,000 in 2015; $382,000 in 2016; and $225,000 thereafter. 
+13. Stock incentive plans 
+Stock incentive plans . We currently have four primary stock incentive plans: the 1996 Stock Plan, which provided for the grant of awards to officers and other key employees of the Company; the 1996 Directors’ Stock Plan, which provided for non-discretionary awards to non-employee directors; the 2001 Employee Stock Plan, which provided for the grant of awards to key employees of the Company and other non-employees who provided services to the Company; and the 2005 Equity Incentive Plan, which provides for awards to executives, key employees, directors and consultants. The plans generally provide for awards in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units, (v) stock appreciation rights or (vi) limited stock appreciation rights. However, the 2001 Employee Stock Plan does not provide for incentive stock option awards. Options granted under these plans have exercise prices equal to 
+F-14 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Stock incentive plans (continued) 
+100% of the fair market value of the common stock at the date of grant. Options granted have a ten-year term and generally vest over a three- to five-year period, unless automatically accelerated for certain defined events. As of May 2005, no new awards will be made under the 1996 Stock Plan, the 1996 Directors’ Stock Plan or the 2001 Employee Stock Plan. Under our 2005 Equity Incentive Plan, we may authorize up to 1,200,000 of shares of TransAct common stock. At December 31, 2011, 406,673 shares of common stock remained available for issuance under the 2005 Equity Incentive Plan. 
+Under the assumptions indicated below, the weighted-average fair value of stock option grants for the years ended December 31, 2011, 2010 and 2009 was $10.42, $7.45 and $2.56, respectively. The table below indicates the key assumptions used in the option valuation calculations for options granted in the years ended December 31, 2011, 2010 and 2009 and a discussion of our methodology for developing each of the assumptions used in the valuation model: 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Expected option term 
+6.8 years 
+6.1 years 
+6.0 years 
+Expected volatility 
+62.5 
+% 
+66.8 
+% 
+67.4 
+% 
+Risk-free interest rate 
+2.0 
+% 
+2.3 
+% 
+2.0 
+% 
+Dividend yield 
+0 
+% 
+0 
+% 
+0 
+% 
+Expected Option Term - This is the weighted average period of time over which the options granted are expected to remain outstanding giving consideration to our historical exercise patterns. Options granted have a maximum term of ten years and an increase in the expected term will increase compensation expense. 
+Expected Volatility – The stock volatility for each grant is measured using the weighted average of historical daily price changes of our common stock over the most recent period approximately equal to the expected option term of the grant. An increase in the expected volatility factor will increase compensation expense. 
+Risk-Free Interest Rate - This is the U.S. Treasury rate in effect at the time of grant having a term approximately equal to the expected term of the option. An increase in the risk-free interest rate will increase compensation expense. 
+Dividend Yield - We have not made any dividend payments on our common stock, and we have no plans to pay dividends in the foreseeable future as it is restricted under the terms of the TD Bank Credit Facility. An increase in the dividend yield will decrease compensation expense. 
+For the years ending December 31, 2011, 2010 and 2009, we recorded $587,000, $565,000, and $640,000 of share-based compensation costs, respectively, included primarily in general and administrative expense in our Consolidated Statements of Income. We also recorded income tax benefits of approximately $195,000, $186,000, and $214,000 in 2011, 2010, and 2009 respectively, related to such share-based compensation. At December 31, 2011, these benefits are recorded as a deferred tax asset in the Consolidated Balance Sheet. 
+The 1996 Stock Plan, 1996 Directors’ Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan option activity is summarized below: 
+Number of Shares 
+Weighted Average Exercise Price 
+Weighted Average Remaining Contractual Term 
+Aggregate Intrinsic Value 
+Outstanding at December 31, 2010 
+942,956 
+$ 
+6.69 
+Granted 
+127,500 
+10.42 
+Exercised 
+(239,074 
+) 
+4.01 
+Forfeited 
+(12,300 
+) 
+7.09 
+Expired 
+(2,374 
+) 
+5.87 
+Outstanding at December 31, 2011 
+816,708 
+$ 
+8.06 
+6.1 years 
+$ 
+975,000 
+Options exercisable at December 31, 2011 
+435,283 
+$ 
+8.80 
+4.6 years 
+$ 
+492,000 
+Options vested or expected to vest 
+781,268 
+$ 
+8.07 
+6.1 years 
+$ 
+937,000 
+F-15 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Stock incentive plans (continued) 
+Shares that are issued upon exercise of employee stock options are newly issued shares and not issued from treasury stock. As of December 31, 2011, unrecognized compensation cost related to stock options is approximately $1,251,000, which is expected to be recognized over a weighted average period of 2.8 years. 
+The total intrinsic value of stock options exercised was $1,576,000, $299,000 and $161,000 and the total fair value of stock options vested was $504,000, $424,000, and $341,000 during the years ended December 31, 2011, 2010 and 2009, respectively. Cash received from option exercises were $959,000, $393,000 and $211,000 for 2011, 2010 and 2009, respectively. We recorded a realized tax benefit in 2011 from equity-based awards of $498,000 related to options exercised which has been included as a component of cash flows from financing activities in the Consolidated Statement of Cash Flows. 
+Restricted stock: Under the 1996 Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan, we have granted shares of restricted common stock, for no consideration, to our officers, directors and certain key employees. R estricted stock activity for the 1996 Stock Plan , 2001 Employee Stock Plan and 2005 Equity Incentive Plan is summarized below: 
+Shares 
+Weighted Average Grant Date Fair Values 
+Nonvested shares at December 31, 2010 
+3,000 
+$ 
+13.78 
+Granted 
+- 
+- 
+Vested 
+(3,000 
+) 
+13.78 
+Canceled 
+- 
+- 
+Nonvested shares at December 31, 2011 
+- 
+$ 
+- 
+As of December 31, 2011, there was no unrecognized compensation cost related to restricted stock. 
+We paid a portion of the 2010 and 2009 incentive bonus for the chief executive officer and chief financial officer in the form of 14,323 and 10,204 deferred stock units, respectively, with a corresponding credit recorded to Additional Paid in Capital in the amount of $141,000 in 2011 and $77,000 in 2010. Such deferred stock units were granted in March 2011 and 2010, respectively, and were fully vested at the time of grant. These units will be converted three years from the grant date to shares of the Company’s common stock on a one-for-one basis. The weighted average exercise price of the deferred stock units was $8.91. 
+14. Income taxes 
+The components of the income tax provision are as follows: 
+Year Ended December 31, 
+(In thousands) 
+2011 
+2010 
+2009 
+Current: 
+Federal 
+$ 
+1,695 
+$ 
+1,297 
+$ 
+53 
+State 
+74 
+51 
+13 
+Foreign 
+44 
+35 
+5 
+1,813 
+1,383 
+71 
+Deferred: 
+Federal 
+448 
+457 
+891 
+State 
+71 
+82 
+110 
+Foreign 
+- 
+1 
+1 
+519 
+540 
+1,002 
+Income tax provision 
+$ 
+2,332 
+$ 
+1,923 
+$ 
+1,073 
+At December 31, 2011, we have no federal or state net operating loss carryforwards. We also have approximately $71,000 in state tax credit carryforwards that began to expire in 2011. Foreign income (loss) before taxes was $68,000, $35,000 and ($49,000) in 2011, 2010 and 2009, respectively. 
+F-16 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+14. Income taxes (continued) 
+Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the Consolidated Financial Statements. Our gross deferred tax assets and liabilities were comprised of the following: 
+December 31, 
+(In thousands) 
+2011 
+2010 
+Deferred tax assets: 
+Net operating losses 
+$ 
+149 
+$ 
+114 
+Capitalized research and development 
+204 
+273 
+Inventory reserves 
+1,169 
+1,210 
+Deferred revenue 
+98 
+176 
+Warranty reserve 
+148 
+87 
+Stock compensation expense 
+810 
+586 
+Foreign tax and other credits 
+47 
+65 
+Other liabilities and reserves 
+595 
+562 
+Gross deferred tax assets 
+3,220 
+3,073 
+Valuation allowance 
+(176 
+) 
+(125 
+) 
+Net deferred tax assets 
+3,044 
+2,948 
+Gross deferred tax liabilities: 
+Depreciation 
+422 
+392 
+Other 
+96 
+62 
+Net deferred tax liabilities 
+518 
+454 
+Total net deferred tax assets 
+$ 
+2,526 
+$ 
+2,494 
+The following table summarizes the activity recorded in the valuation allowance on the deferred tax assets: 
+Year ended December 31, 
+(In thousands) 
+2011 
+2010 
+2009 
+Balance, beginning of period 
+$ 
+125 
+$ 
+76 
+$ 
+26 
+Additions charged to income tax provision 
+51 
+55 
+50 
+Reductions credited to income tax provision 
+- 
+(6 
+) 
+- 
+Balance, end of period 
+$ 
+176 
+$ 
+125 
+$ 
+76 
+Differences between the U.S. statutory federal income tax rate and our effective income tax rate are analyzed below: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Federal statutory tax rate 
+34.0 
+% 
+34.0 
+% 
+34.0 
+% 
+State income taxes, net of federal income taxes 
+1.4 
+1.5 
+2.5 
+Tax benefit from tax credits, net of valuation allowance 
+(2.7 
+) 
+(2.9 
+) 
+(4.5 
+) 
+Valuation allowance and tax accruals 
+0.7 
+0.8 
+0.8 
+Permanent items 
+(0.4 
+) 
+(0.2 
+) 
+0.7 
+Other 
+0.3 
+(0.2 
+) 
+- 
+Effective tax rate 
+33.3 
+% 
+33.0 
+% 
+33.5 
+% 
+At December 31, 2011 and 2010, we had approximately $228,000 and $201,000 of total gross unrecognized tax benefits that, if recognized, would favorably affect the effective income tax rate in any future periods. We are not aware of any events that could occur within the next twelve months that could cause a significant change in the total amount of unrecognized tax benefits. A tabular reconciliation of the gross amounts of unrecognized tax benefits at the beginning and end of the year is as follows: 
+F-17 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+14. Income taxes (continued) 
+(In thousands) 
+2011 
+2010 
+Unrecognized tax benefits as of January 1 
+$ 
+201 
+$ 
+189 
+Tax positions taken during the current period 
+53 
+61 
+Lapse of statute of limitations 
+(26 
+) 
+(49 
+) 
+Unrecognized tax benefits as of December 31 
+$ 
+228 
+$ 
+201 
+We are subject to U.S. federal income tax as well as income tax of certain state and foreign jurisdictions. We have substantially concluded all U.S. federal income tax, state and local, and foreign tax matters through 2003. During 2008, a limited scope examination of our 2005 and 2006 federal tax returns was completed. However, our federal tax returns for the years 2004 through 2010 remain open to examination. Various state and foreign tax jurisdiction tax years remain open to examination as well, though we believe that any additional assessment would be immaterial to the Consolidated Financial Statements. No federal, state or foreign tax jurisdiction income tax returns are currently under examination. 
+We do not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2012. 
+We recognize interest and penalties related to uncertain tax positions in the income tax provision. As of December 31, 2011 and 2010, we have approximately $23,000 and $4,000, respectively, of accrued interest and penalties related to uncertain tax positions. 
+15. Earnings per share 
+For 2011, 2010 and 2009, earnings per share were computed as follows (in thousands, except per share amounts): 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Net income 
+$ 
+4,676 
+$ 
+3,904 
+$ 
+2,140 
+Shares: 
+Basic: Weighted average common shares outstanding 
+9,443 
+9,390 
+9,289 
+Add: Dilutive effect of outstanding options as determined by the treasury stock method 
+160 
+200 
+88 
+Diluted: Weighted average common and common equivalent shares outstanding 
+9,603 
+9,590 
+9,377 
+Net income per common share: 
+Basic 
+$ 
+0.50 
+$ 
+0.42 
+$ 
+0.23 
+Diluted 
+0.49 
+0.41 
+0.23 
+We compute earnings per share using the two-class method, which is an earnings allocation formula that determines earnings per share for common stock and participating securities. Restricted stock granted by the Company is considered a participating security since it contains a non-forfeitable right to dividends. 
+Certain stock-based awards were not included in the full year computation of earnings per diluted share because the effect would be anti-dilutive. Anti-dilutive stock options, restricted shares and deferred stock units excluded from the computation of earnings per dilutive share were 309,250, 367,750, and 525,500, at December 31, 2011, 2010 and 2009 respectively. 
+16. Stock repurchase program 
+On May 27, 2010, our Board of Directors approved a stock repurchase program (the “Stock Repurchase Program”). Under the Stock Repurchase Program, we are authorized to repurchase up to $10,000,000 of our outstanding shares of common stock from time to time in the open market over a three-year period ending May 27, 2013, depending on market conditions, share price and other factors. In March 2012, the Board of Directors approved an increase in our stock repurchase authorization under the Stock Repurchase Program to $15,000,000 from $10,000,000. For the year ended December 31, 2011, we repurchased a total of 275,255 shares of common stock for approximately $2,680,000, at an average price of $9.74 per share, under the Stock Repurchase Program. From January 1, 2005 through December 31, 2011, we repurchased a total of 1,461,693 shares of common stock for approximately $11,395,000 under all of our stock repurchase programs, at an 
+F-18 
+Table of Contents 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+16. Stock repurchase program (continued) 
+average price of $7.80 per share. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the trade date. At December 31, 2011, approximately $7,143,000 remains authorized for future repurchases under the Stock Repurchase Program. 
+17. Geographic area information 
+Information regarding our operations by geographic area is contained in the following table. These amounts in the geographic area table are based on the location of the customer and vendor. 
+Year Ended December 31, 
+(In thousands) 
+2011 
+2010 
+2009 
+Net sales: 
+United States 
+$ 
+49,301 
+$ 
+44,101 
+$ 
+45,890 
+International 
+16,668 
+19,093 
+12,456 
+Total 
+$ 
+65,969 
+$ 
+63,194 
+$ 
+58,346 
+Fixed assets, net: 
+United States 
+$ 
+2,129 
+$ 
+2,694 
+$ 
+3,395 
+International 
+1,229 
+1,377 
+1,156 
+Total 
+$ 
+3,358 
+$ 
+4,071 
+$ 
+4,551 
+Sales to international customers were approximately 25%, 30%, and 21% in 2011, 2010, and 2009 respectively. Sales to the United Kingdom represented 51%, 43%, and 45%, sales to the Pacific Rim (which includes Australia and Asia) represented 25%, 18%, and 31%, and sales to Canada represented 6%, 20%, and 11% of total international sales in 2011, 2010, and 2009 respectively. International long-lived assets consist of net fixed assets located at our foreign subsidiary in the United Kingdom as well as our contract manufacturers in China, Malaysia and Mexico. 
+18. Quarterly results of operations (unaudited) 
+Our quarterly results of operations for 2011 and 2010 are as follows: 
+Quarter Ended 
+(In thousands, except per share amounts) 
+March 31 
+June 30 
+September 30 
+December 31 
+2011: 
+Net sales 
+$ 
+20,694 
+$ 
+17,519 
+$ 
+14,111 
+$ 
+13,645 
+Gross profit 
+6,932 
+6,663 
+5,350 
+5,681 
+Net income 
+1,825 
+1,442 
+839 
+570 
+Net income per share: 
+Basic 
+0.19 
+0.15 
+0.09 
+0.06 
+Diluted 
+0.19 
+0.15 
+0.09 
+0.06 
+2010: 
+Net sales 
+$ 
+14,208 
+$ 
+16,443 
+$ 
+16,369 
+$ 
+16,174 
+Gross profit 
+5,189 
+6,155 
+5,557 
+5,647 
+Net income 
+629 
+1,145 
+1,052 
+1,078 
+Net income per share: 
+Basic 
+0.07 
+0.12 
+0.11 
+0.11 
+Diluted 
+0.07 
+0.12 
+0.11 
+0.11 
+F-19 
+Table of Contents 
+Index to Exhibits 
+3.1(a) 
+Certificate of Incorporation of TransAct Technologies Incorporated (“TransAct” or the “Company”), filed with the Secretary of State of Delaware on June 17, 1996. 
+(2) 
+3.1(b) 
+Certificate of Amendment of Certificate of Incorporation of the Company, filed with the Secretary of State of Delaware on June 4, 1997. 
+(4) 
+3.1(c) 
+Certificate of Designation, Series A Preferred Stock, filed with the Secretary of State of Delaware on December 2, 1997. 
+(5) 
+3.1(d) 
+Certificate of Designation, Series B Preferred Stock, filed with the Secretary of State of Delaware on April 6, 2000. 
+(8) 
+3.2 
+Amended and Restated By-laws of the Company. 
+(6) 
+4.1 
+Specimen Common Stock Certificate. 
+(2) 
+10.1(x) 
+1996 Stock Plan, effective July 30, 1996. 
+(3) 
+10.2(x) 
+Non-Employee Directors’ Stock Plan, effective August 22, 1996. 
+(3) 
+10.3(x) 
+2001 Employee Stock Plan. 
+(9) 
+10.4(x) 
+2005 Equity Incentive Plan. 
+(14) 
+10.5(x) 
+Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. Shuldman. 
+(2) 
+10.6(x) 
+Severance Agreement by and between TransAct and Michael S. Kumpf, dated September 4, 1996. 
+(3) 
+10.7(x) 
+Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, 2004. 
+(13) 
+10.8(x) 
+Severance Agreement by and between TransAct and Tracey S. Chernay, dated July 29, 2005. 
+(18) 
+10.9(x) 
+Amendment to Employment Agreement, effective January 1, 2008, by and between TransAct and Bart C. Shuldman. 
+(19) 
+10.10(x) 
+Amendment to Severance Agreement by and between TransAct and Michael S. Kumpf, effective January 1, 2008. 
+(19) 
+10.11(x) 
+Amendment to Severance Agreement by and between TransAct and Steven A. DeMartino, effective January 1, 2008. 
+(19) 
+10.12(x) 
+Amendment to Severance Agreement by and between TransAct and Tracey S. Chernay, effective January 1, 2008. 
+(19) 
+10.13 
+Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, 1992. 
+(2) 
+10.14 
+Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated December 2, 1996. 
+(4) 
+10.15 
+Agreement regarding the Continuation and Renewal of Lease by and between Bomax Properties, LLC and TransAct, dated July 18, 2001. 
+(11) 
+10.16 
+Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated December 2, 2004. 
+(13) 
+10.17 
+First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 
+(20) 
+10.18 
+Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated November 27, 2006. 
+(16) 
+10.19 
+OEM Purchase Agreement by and between GTECH Corporation, TransAct and Magnetec Corporation commencing July 14, 1999. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(7) 
+10.20 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct commencing July 2, 2002. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(10) 
+10.21 
+Amendment to OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated February 17, 2006. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(15) 
+10.22 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated November 20, 2009. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy) 
+(20) 
+10.23 
+Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. dated November 28, 2006 
+(16) 
+10.24 
+First Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. effective September 30, 2007. 
+(17) 
+Table of Contents 
+10.25 
+Second Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Bank, N.A. effective November 22, 2011. 
+(1) 
+10.26 
+License Agreement between Seiko Epson Corporation and TransAct dated May 17, 2004 (Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(12) 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+(1) 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+101.INS 
+XBRL Instance Document. 
+(1) 
+101.SCH 
+XBRL Taxonomy Extension Schema Document. 
+(1) 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document. 
+(1) 
+101.DEF 
+XBRL Taxonomy Extension Definition Linkbase Document. 
+(1) 
+101.LAB 
+XBRL Taxonomy Extension Label Linkbase Document. 
+(1) 
+101.PRE 
+XBRL Taxonomy Extension Presentation Linkbase Document. 
+(1) 
+(1) 
+These exhibits are filed herewith. 
+(2) 
+These exhibits, which were previously filed with the Company’s Registration Statement on Form S-1 (No. 333-06895), are incorporated by reference. 
+(3) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1996, are incorporated by reference. 
+(4) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1997, are incorporated by reference. 
+(5) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed February 18, 1999, is incorporated by reference. 
+(6) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1998, is incorporated by reference. 
+(7) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 25, 1999, is incorporated by reference. 
+(8) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended March 25, 2000, are incorporated by reference. 
+(9) 
+This exhibit, which was previously filed with the Company’s Registration Statement on Form S-8 (No. 333-59570), is incorporated by reference. 
+(10) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002, is incorporated by reference. 
+(11) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003, is incorporated by reference. 
+(12) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004, is incorporated by reference. 
+(13) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, are incorporated by reference. 
+(14) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed June 1, 2005, is incorporated by reference. 
+Table of Contents 
+(15) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, is incorporated by reference. 
+(16) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, are incorporated by reference. 
+(17) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1997, is incorporated by reference. 
+(18) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, is incorporated by reference. 
+(19) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, is incorporated by reference. 
+(20) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, is incorporated by reference. 
+(x) 
+Management contract or compensatory plan or arrangement. 
+Table of Contents 
+EXHIBIT LIST 
+The following exhibits are filed herewith. 
+Exhibit 
+10.25 
+Second Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Bank, N.A. effective November 22, 2011. 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+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.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/filing_metadata.csv b/raw/filings/0001017303/2011/0001017303-12-000013/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..9301911b78172dab9567c95e7e5f8dbfa71ef771
--- /dev/null
+++ b/raw/filings/0001017303/2011/0001017303-12-000013/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
+0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2012-03-12,2011-12-31,2012-03-12T19:52:53.000Z,0001017303-12-000013,form10k.htm,FORM 10-K,5430942,1,0,https://www.sec.gov/Archives/edgar/data/1017303/000101730312000013/form10k.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730312000013/,2011,2011,1
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/item1.txt b/raw/filings/0001017303/2011/0001017303-12-000013/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f3c1c55daf77f1bcfa4b78a45552d61bd92978ea
--- /dev/null
+++ b/raw/filings/0001017303/2011/0001017303-12-000013/item1.txt
@@ -0,0 +1,90 @@
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops, assembles, markets and services world-class transaction printers under the Epic, Ithaca® and Printrex® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers generate top-quality transaction records such as receipts, tickets, coupons, register journals and other documents as well as printed logging and plotting of data. We focus on the following core markets: banking and point-of-sale (“POS”), casino and gaming, lottery, oil and gas and medical and mobile. We sell our products to original equipment manufacturers ("OEMs"), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. Beyond printers, TransAct is a leader in providing printing supplies to the full transaction printer market. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the hospitality, banking, retail, gaming, government and oil and gas exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating facility and eastern region service center located in Ithaca, NY, our printer sales headquarters and western region service center in Las Vegas, NV, a manufacturing facility located in San Jose, CA, which will be closed and incorporated into our Ithaca facility by August 2012, a European sales and service center in the United Kingdom, a sales office located in Macau and two other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT, 06518, with a telephone number of (203) 859-6800. 
+On August 19, 2011, we completed the acquisition of Printrex, Inc. (“Printrex”) for $4,000,000 in cash and potential future contingent consideration. Printrex is a leading manufacturer of specialty printers primarily sold into the oil and gas exploration and medical and mobile markets. Printrex serves commercial and industrial customers primarily in the United States, Canada, Europe and Asia. This acquisition was completed to complement our existing product offerings. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction and specialty printers and printer-related service, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers 
+TransAct designs, develops, assembles and markets a broad array of transaction-based and specialty printers utilizing inkjet, thermal and impact printing technology for applications, primarily in the banking, POS, casino and gaming, lottery, oil and gas and medical and mobile markets. Our printers are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Banking and POS: Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print and/or validate receipts at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of our internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals that print tickets or receipts instead of issuing coins at casinos, racetracks and other gaming establishments worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that enables casinos to print coupons and promotions. In addition, we sell printers using thermal and impact printing 
+1 
+Table of Contents 
+technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Video lottery terminals (“VLT”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through regional distributors (four in the United States and Asia, one in Europe and Africa, two in Latin America and one in Australia). We also maintain a dedicated internal sales force to solicit sales from slot manufacturers and casinos, as well as to manage sales through our distributors. 
+We have also developed a new software solution, the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that will allow casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. With EPICENTRAL TM , casinos will be able to utilize the system to create multiple promotions and incentives to either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. 
+Printrex: Printrex printers include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. In addition, we sell wide format thermal printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. We primarily sell our Printrex products directly to drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. We also maintain a dedicated internal sales force and one manufacturer’s representative located in Texas. 
+TSG 
+Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper and other transaction supplies), replacement parts and maintenance services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. Approximately 80% of our printer production is through two third-party contract manufacturers in China, with the remaining 20% of products assembled in our Ithaca, NY and San Jose, CA facilities largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY and San Jose, CA. Critical component parts and subassemblies include inkjet, thermal and impact printheads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, purchases of component parts have declined while purchases of fully-assembled printers produced by our contract manufacturers have increased. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer, and to a much lesser extent, a second foreign contract manufacturer. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturer, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2012 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges that are compatible with the HP inkjet cartridge are available, the loss of the supply of HP inkjet cartridges could have a material adverse effect on both the sale of our inkjet 
+2 
+Table of Contents 
+printers and TSG consumable products. Our relationship with HP remains stable and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be any less favorable than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+Patents and Proprietary Information 
+We have significantly expanded our patent portfolio over the past ten years, and expect to continue to do so in the future. We also believe our patent portfolio could provide additional opportunities to license our intellectual property in the future. We hold 27 United States and 20 foreign patents and have 8 United States and 25 foreign patent applications pending pertaining to our products. The duration of these patents range from 6 to 16 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+Seasonality 
+Retailers typically reduce purchases of new POS equipment in the fourth quarter due to the increased volume of consumer transactions in that holiday period, and our sales of printers in the POS market historically have increased in the third quarter and decreased in the fourth quarter. Similarly, installations of lottery terminals are typically reduced in the fourth quarter, resulting in decreased sales of lottery printers. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH is our most significant customer. We currently have an ongoing OEM purchase agreement, as amended in February 2006 (the “GTECH Thermal Printer Agreement”) with GTECH that provides for the sale of thermal on-line lottery printers and spare parts, at fixed prices, through June 28, 2012. We expect to renew this agreement prior to its expiration in 2012. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH New Thermal Printer Agreement”). Under the terms of the new agreement, we will provide GTECH with their next generation thermal lottery printers for various lottery applications. The terms of the new agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH through January 2015. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2011 
+2010 
+2009 
+GTECH 
+26 
+% 
+12 
+% 
+19 
+% 
+Customer A 
+13 
+% 
+14 
+% 
+10 
+% 
+Customer B 
+* 
+* 
+12 
+% 
+* Customers represented less than 10% of total net sales 
+Backlog 
+Our backlog of firm orders was approximately $7,261,000 as of February 29, 2012, compared to $12,764,000 as of February 28, 2011. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2012. 
+Competition 
+The market for transaction-based and specialty printers is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+3 
+Table of Contents 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group (“TPG”), Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreements with GTECH. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+In the Printrex market, we compete with the Imaging Systems Group, Inc. (“iSys”), GSI Group and others. We compete in this market based largely on our ability to provide specialized, custom-engineered products. 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including POS and internet resellers, depending on the geographic area. 
+Our strategy for competing in our markets is to continue to develop new products (hardware and software) and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $3,418,000, $3,000,000 and $2,788,000 in 2011, 2010 and 2009, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new products and to customize or improve existing products. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. During 2010 we began the development of EPICENTRAL TM , that enables casino customers to print coupons and promotions at the slot machine. Unamortized development costs for such software were approximately $682,000 and $129,000 as of December 31, 2011 and 2010, respectively. The total amount charged to cost of sales for capitalized software development costs was approximately $62,000 in 2011 with no such charges in 2010. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of December 31, 2011, TransAct and our subsidiaries employed 134 persons, of whom 130 were full-time and 4 were temporary employees. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 17 – Geographic Area Information in the Notes to the Consolidated Financial Statements. Risks attendant to our foreign operations are described in Item 1A below. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is 
+4 
+Table of Contents 
+electronically filed with or furnished to the SEC. You may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/item13.txt b/raw/filings/0001017303/2011/0001017303-12-000013/item13.txt
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@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item is incorporated by reference from the Proxy Statement section entitled “Certain Relationships and Related Transactions.”
\ No newline at end of file
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/item9a.txt b/raw/filings/0001017303/2011/0001017303-12-000013/item9a.txt
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--- /dev/null
+++ b/raw/filings/0001017303/2011/0001017303-12-000013/item9a.txt
@@ -0,0 +1,9 @@
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2011, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2011. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Annual Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2011. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 
+Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2011. We excluded Printrex from our assessment of internal control over financial reporting as of December 31, 2011 because it was acquired by the Company in a purchase combination during the third quarter of 2011. The total assets (inclusive of goodwill and acquired intangible assets of approximately $3,190,000 or 7%) and total revenues of Printrex represent approximately 11% and 3%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011. 
+The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/rp_note.txt b/raw/filings/0001017303/2011/0001017303-12-000013/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2011/0001017303-12-000013/rpt_disclosure.txt b/raw/filings/0001017303/2011/0001017303-12-000013/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e82a200afd907bc9757e93cc22dfd87a70b3fb78
--- /dev/null
+++ b/raw/filings/0001017303/2011/0001017303-12-000013/rpt_disclosure.txt
@@ -0,0 +1,4 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+The Company maintains policies that relate to the identification, review and approval of related party transactions. As part of a review of possible related person transactions, the Company annually distributes and collects questionnaires that solicit information about any direct or indirect transactions with the Company from each of our directors and officers. 
+Our Standards of Business Conduct require all directors, officers and employees to avoid any situation that involves an actual or apparent conflict of interest in personal and professional relationships or with their duty to, or with any interest of, the Company. Under the Standards of Business Conduct, situations that involve, or may reasonably be inferred to involve, a conflict between a director, officer or employee’s personal interests and the interests of the Company should be disclosed to the Chair of the Audit Committee. The Audit Committee is then responsible for reviewing the related party transaction. No related party transaction shall be approved or ratified if such transaction is contrary to the best interests of the Company. In determining whether to approve or ratify a related party transaction, the Audit Committee takes into account such factors as it deems appropriate, which may include whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the related person’s interest in the transaction . 
+From January 1, 2011 to the date of this proxy statement, there have not been any transactions subject to the Company’s related party transaction policy or of the type described in Item 404 of Regulation S-K, and currently no such transactions are proposed.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/filing.txt b/raw/filings/0001017303/2013/0001017303-14-000015/filing.txt
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@@ -0,0 +1,3516 @@
+10-K
+1
+form10k2013.htm
+FORM 10K FOR THE YEAR ENDED DECEMBER 31, 2013
+form10k2013.htm 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+Washington, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+x 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2013 
+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: 0-21121 
+______________________________________________________________________ 
+______________________________________________________________________ 
+(Exact name of registrant as specified in its charter) 
+Delaware 
+06-1456680 
+(State or other jurisdiction of incorporation or organization) 
+(I.R.S. Employer Identification No.) 
+One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT 
+06518 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant's telephone number, including area code 203-859-6800 
+______________________________________________________________________ 
+Securities registered pursuant to Section 12(b) of the Act: 
+Title of Each Class - Common Stock, par value $.01 per share 
+Name of Exchange on which Registered - NASDAQ Global 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 o 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 o 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 o 
+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 (§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 ý No o 
+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. 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
+Large accelerated filer o 
+Accelerated filer ý 
+Non-accelerated filer o (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 Exchange Act). Yes o No ý 
+The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the Registrant was approximately $67,800,000 based on the last sale price on June 28, 2013. 
+As of February 28, 2014, the number of shares outstanding of the Registrant’s common stock, $0.01 par value, was 8,371,307. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+Portions of the Registrant’s Proxy Statement to be filed with the Securities and Exchange Commission within 120 days after the year covered by this Form 10-K with respect to the 2014 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX 
+PART I. 
+Item 1. 
+Business 
+1 
+Item 1A. 
+Risk Factors 
+4 
+Item 1B. 
+Unresolved Staff Comments 
+8 
+Item 2. 
+Properties 
+8 
+Item 3. 
+Legal Proceedings 
+9 
+Item 4. 
+Mine Safety Disclosures 
+9 
+PART II. 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 
+9 
+Item 6. 
+Selected Financial Data 
+11 
+Item 7. 
+Management's Discussion and Analysis of Financial Condition and Results of Operations 
+11 
+Item 7A. 
+Quantitative and Qualitative Disclosures About Market Risk 
+23 
+Item 8. 
+Financial Statements and Supplementary Data 
+24 
+Item 9. 
+Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 
+24 
+Item 9A. 
+Controls and Procedures 
+24 
+Item 9B. 
+Other Information 
+24 
+PART III. 
+Item 10. 
+Directors, Executive Officers and Corporate Governance 
+24 
+Item 11. 
+Executive Compensation 
+25 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 
+25 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence 
+25 
+Item 14. 
+Principal Accounting Fees and Services 
+25 
+PART IV. 
+Item 15. 
+Exhibits 
+25 
+SIGNATURES 
+Signatures 
+26 
+CONSOLIDATED FINANCIAL STATEMENTS 
+Index to Consolidated Financial Statements 
+F-1 
+EXHIBITS 
+Index to Exhibits 
+PART I 
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops and sells market-specific solutions, including printers, terminals, software and other products for transaction-based and other industries. These world-class products are sold under the Epic, EPICENTRAL TM , Ithaca® and Printrex® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers and terminals generate top-quality labels and transaction records such as receipts, tickets, coupons, register journals and other documents as well as printed logging and plotting of data. We focus on the following core markets: food safety, banking and point-of-sale (“POS”), casino and gaming, lottery, and Printrex (which serves the oil and gas, medical and emergency vehicle markets). We sell our products to original equipment manufacturers (“OEMs”), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. TransAct also provides world-class printer service, spare parts, accessories and printing supplies to its growing worldwide installed base of printers. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the hospitality, banking, retail, casino and gaming, government and oil and gas exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating and global research and development and eastern region service center located in Ithaca, NY. In addition, we have a casino and gaming sales headquarters and western region service center in Las Vegas, NV, a satellite research and development office in San Jose, CA, a European sales and service center in the United Kingdom, a sales office located in Macau and three other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT , 06518, with a telephone number of (203) 859-6800. 
+On August 19, 2011, we completed the acquisition of Printrex, Inc. (“Printrex”) for $4,000,000 in cash and potential future contingent consideration. Printrex is a leading manufacturer of specialty printers primarily sold into the oil and gas exploration and medical and mobile markets. Printrex serves commercial and industrial customers primarily in the United States, Canada, Europe and Asia. This acquisition was completed to complement our existing product offerings. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction printers and terminals and providing related software, services, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers and terminals 
+TransAct designs, develops, assembles and markets a broad array of transaction-based and specialty printers and terminals utilizing inkjet, thermal and impact printing technology for applications, primarily in the food safety, banking and POS, casino and gaming, lottery, oil and gas, medical and emergency vehicle markets. Our printers and terminals are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers and terminals, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Food safety, banking and POS: During 2012 in an effort to address the Food Safety Modernization Act, we developed a food safety terminal, a hardware device that consists of a touchscreen and one or two thermal print mechanisms, that print easy-to-read expiration and "enjoy by" date labels to help restaurants effectively manage food spoilage. In the food safety market, we use an internal sales representative to manage sales of our terminals through distribution, as well as a dedicated internal sales force to solicit sales directly from end-users. 
+Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print receipts and/ or validate checks at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of our internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals (“VLT’s”) and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos, racetracks (“racinos”) and other gaming venues worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that enables casinos to print coupons and promotions. In addition, we sell printers using thermal printing technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through distributors (one in the United States, Australia and Asia, and one in Europe and Africa). We also maintain a dedicated internal sales force to solicit sales from slot manufacturers and casinos, as well as to manage sales through our distributors. 
+1 
+We have also gained traction from our software solution, the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that enables casino operators to create promotional coupons and marketing messages and print them in real-time at the slot machine. With EPICENTRAL TM , casinos will be able to utilize the system to create multiple promotions and incentives to either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. 
+Printrex: Printrex printers include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. During 2012, we launched two new color printers for this market, the Printrex 920 and Printrex 980. The Printrex 920 is the first full-color printer designed from the ground up to perform in the adverse environment of a well logging truck or off-shore platform. Using thermal printer technology, it can print in black and white, or in full color using proprietary color paper without the need for inkjet cartridges or ribbons. The Printrex 980 is the fastest full color printer available for plotting continuous logs in the data centers of the large oil field service companies. This printer uses proprietary inkjet cartridges. In addition, we sell wide format thermal printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. We primarily sell our Printrex products directly to oil field service and drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. We also maintain a dedicated internal sales force with a sales office located in Houston, Texas. 
+TSG: Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper, color thermal paper and other printing supplies), replacement parts, maintenance and repair services and testing services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. Approximately 90% of our printer production is primarily through one third-party contract manufacturer in Asia and to a lesser extent three others in Asia. The remaining 10% of our products are assembled in our Ithaca, NY facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY. Critical component parts and subassemblies include inkjet, thermal and impact print heads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, LCD screens, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, purchases of component parts have declined while purchases of fully-assembled printers produced by our contract manufacturers have increased. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer, and to a much lesser extent, three other foreign contract manufacturers. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturers, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2014 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our banking inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges that are compatible with the HP inkjet cartridge are available, the loss of the supply of HP inkjet cartridges could have a material adverse effect on both the sale of our inkjet printers and TSG consumable products. Our relationship with HP remains stable and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be materially different than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+ZINK Imaging Inc. (“ZINK”) is the sole supplier of proprietary color thermal paper used in our Printrex 920 oil and gas printer. We have a supply agreement with ZINK to exclusively supply us with ZINK color thermal paper for the oil and gas industry at fixed prices through December 31, 2014. The loss of the supply of ZINK color thermal paper would have a material adverse effect on the sale of Printrex 920 printers and ZINK color thermal paper. 
+2 
+Canon, Inc. (“Canon”) is the sole supplier of inkjet cartridges and other consumable items (“Canon Consumables”) that are used in our Printrex 980 oil and gas printer. The loss of supply of Canon Consumables would have a material adverse effect on the sale of Printrex 980 printers and the Canon Consumables. We have a supply agreement with Canon to supply us with Canon Consumables until May 2017. Prices under this agreement were fixed through May 2013, but may be changed for the remainder of the agreement due to significant exchange rate fluctuations between the Japanese yen and the U.S. dollar. 
+Patents and Proprietary Information 
+TransAct relies on a combination of trade secrets, patents, employee and third party nondisclosure agreements, copyright laws and contractual rights to establish and protect its proprietary rights in its products. We hold 29 United States and 28 foreign patents and have 10 United States and 11 foreign patent applications pending pertaining to our products. The duration of these patents range from 4 to 16 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+Seasonality 
+Restaurants typically reduce purchases of new food safety equipment in the fourth quarter due to the increased volume of transactions in that holiday period. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH has been our most significant customer. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH Thermal Printer Agreement”). Under the terms of the agreement, we provide GTECH with their latest generation thermal lottery printers for various lottery applications. The terms of the agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH through January 2015. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2013 
+2012 
+2011 
+GTECH 
+12% 
+18% 
+26% 
+Customer A 
+12% 
+15% 
+13% 
+Backlog 
+Our backlog of firm orders was approximately $4,778,000 as of February 28, 2014, compared to $4,776,000 as of February 28, 2013. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2014. 
+Competition 
+The market for transaction-based and specialty printing solutions is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+In the food safety market, we compete with Avery Dennison Corporation, Ecolab Inc. and Integrated Control Corp. We compete in this market based largely on our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group (“TPG”), Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing and promotional coupon printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreement with GTECH. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the Printrex market, we compete with the Imaging Systems Group, Inc. (“iSys”), Neuralog Inc., GSI Group and others. We compete in this market based largely on our ability to provide specialized, custom-engineered products. 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including POS and internet resellers, depending on the geographic area. 
+3 
+Our strategy for competing in our markets is to continue to develop new products (hardware and software) and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $4,065,000, $4,239,000 and $3,418,000 in 2013, 2012 and 2011, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new hardware and software products and to customize or improve existing products. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheets until the product is available for sale to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. During 2010 we began the development of EPICENTRAL TM, , which enables casino customers to print coupons and promotions at the slot machine. Unamortized development costs for such software were approximately $370,000 and $528,000 as of December 31, 2013 and 2012, respectively. The total amount charged to cost of sales for capitalized software development costs were approximately $199,000, $189,000 and $62,000 in 2013, 2012 and 2011, respectively. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of December 31, 2013, TransAct and our subsidiaries employed 139 persons, of whom 138 were full-time employees and 1 was a temporary employee. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 16 – Geographic Area Information in the Notes to the Consolidated Financial Statements. Risks related to our foreign operations are described in Item 1A below. 
+Trademarks, Service Marks and Copyrights 
+We own or have rights to trademarks, service marks, trade names and copyrights that we use in connection with the operation of our business, including our corporate names, logos and website names. Other trademarks, service marks and trade names appearing in this annual report on Form 10-K are the property of their respective owners. The trademarks we own include TransAct®, EPICENTRAL TM , Ithaca® and Printrex®. Solely for convenience, some of the trademarks, service marks, trade names and copyrights referred to in this annual report on Form 10-K are listed without the ©, ® and ™ symbols, but we will assert, to the fullest extent under applicable law, our rights to our trademarks, service marks, trade names and copyrights. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). You may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800. 
+Item 1A. Risk Factors 
+Investors should carefully consider the risks, uncertainties and other factors described below, as well as other disclosures in Management’s Discussion and Analysis of Financial Condition and Results of Operations, because they could have a material adverse effect on our business, financial condition, operating results, and growth prospects. The risks described below are not the only ones facing our Company. Additional risks not known to us now or that we currently deem immaterial may also impair our business operations. 
+We assume no obligation (and specifically disclaim any such obligation) to update these Risk Factors or any other forward-looking statements contained in this Annual Report to reflect actual results, changes in assumptions or other factors affecting such forward-looking statements, except as required by law. 
+4 
+Our operating results and financial condition may fluctuate. 
+Our operating results and financial condition may fluctuate from quarter to quarter and year to year and are likely to continue to vary due to a number of factors, many of which are not within our control. If our operating results do not meet the expectations of securities analysts or investors, who may derive their expectations by extrapolating data from recent historical operating results, the market price of our common stock will likely decline. Fluctuations in our operating results and financial condition may be due to a number of factors, including, but not limited to, those identified throughout this “Risk Factors” section: 
+· 
+market acceptance of our products, both domestically and internationally; 
+· 
+development of new competitive products by others; 
+· 
+our responses to price competition; 
+· 
+our level of research and development activities; 
+· 
+changes in the amount that we spend to develop, acquire or license new products, consumables, technologies or businesses; 
+· 
+changes in the amount we spend to promote our products and services; 
+· 
+changes in the cost of satisfying our warranty obligations and servicing our installed base of printers; 
+· 
+delays between our expenditures to develop and market new or enhanced products and consumables and the generation of sales from those products; 
+· 
+the geographic distribution of our sales; 
+· 
+availability of third-party components at reasonable prices; 
+· 
+general economic and industry conditions, including changes in interest rates affecting returns on cash balances and investments, that affect customer demand; 
+· 
+severe weather events (such as hurricanes) that can disrupt or interrupt the operation of our customers or suppliers facilities; and 
+· 
+changes in accounting rules. 
+Due to all of the foregoing factors, and the other risks discussed in this report, quarter-to-quarter comparisons of our operating results may not be an indicator of future performance. 
+Our revenue and profitability depend on our ability to continue to develop, on a timely basis, new products and technologies which are free from hardware or software anomalies and cannot be fraudulently manipulated. 
+The success of newly introduced products such as the Ithaca® 9700 food safety terminal and the Printrex® 920 and Printrex® 980 oil and gas color printers is dependent on how quickly customers in the related markets accept them given the very little market penetration these products have experienced since they are new and innovative and have limited competition. Additionally, the success of innovative technology, such as printing coupons and promotions at the slot machine using EPICENTRAL™, is dependent on our casino customers' acceptance of such technology. While we have designed EPICENTRAL™ to support our customers' existing investment in our Epic 950® thermal casino printers, such acceptance may nevertheless only build gradually over time or not at all. Delays in acceptance by our customers of new technologies may adversely affect our operations. 
+Our success depends upon our ability to adapt our capabilities and processes to meet the demands of producing new and innovative products. Because our newer products are generally more technologically sophisticated than those we have produced in the past, we must continually refine our capabilities to meet the needs of our product innovation. If we cannot efficiently adapt our infrastructure to meet the needs of our product innovations in a timely manner, our business could be negatively impacted. 
+We rely on resellers to sell our products and services. 
+We use a variety of distribution channels, including OEMs and distributors, to market our products. We may be adversely impacted by any conflicts that could arise between and among our various sales channels. 
+Our dependence upon resellers exposes us to numerous risks, including: 
+· 
+loss of channel and the ability to bring new products to market; 
+· 
+concentration of credit risk, including disruption in distribution should the resellers’ financial condition deteriorate; 
+· 
+reduced visibility to end user demand and pricing issues which makes forecasting more difficult; 
+· 
+resellers leveraging their buying power to change the terms of pricing, payment and product delivery schedules; and 
+· 
+direct competition should a reseller decide to manufacture printers internally or source printers from a competitor. 
+We cannot guarantee that resellers will not reduce, delay or eliminate purchases from us, which could have a material adverse effect upon the business, consolidated results of operations and financial condition. 
+General economic conditions could have a material adverse effect on our business, operating results and financial condition. 
+Global economic growth has slowed and has resulted in recessions in numerous countries, including many of those in North America, Europe and Asia, where the Company does substantially all of its business. If these economic conditions continue to persist, or if they worsen, a number of negative effects on our business could result, including customers or potential customers reducing or delaying orders, the insolvency of key suppliers which could result in production delays, the inability of customers to obtain credit, and the insolvency of one or more customers. Any of these effects could impact our ability to effectively manage inventory levels and collect receivables, create unabsorbed costs due to lower net sales, and ultimately decrease our net sales and profitability including write-downs of assets. 
+5 
+We have outsourced a large portion of the assembly of our printers to four contract manufacturers and will be dependent on them for the manufacturing of such printers. A failure by these contract manufacturers, or any disruption in such manufacturing, may adversely affect our business results. 
+In an effort to achieve additional cost savings and operation benefits, we have continued to outsource the manufacturing and assembly of our printers to contract manufacturers in Asia. Approximately 90% of our printer manufacturing is conducted by one third party manufacturer in Asia. 
+However, to the extent we rely on a third-party service provider for manufacturing services, we may incur increased business continuity risks. We will no longer be able to exercise control over the assembly of certain of our products or any related operations or processes, including the internal controls associated with operations and processes conducted and the quality of our products assembled by contract manufacturers. If we are unable to effectively develop and implement our outsourcing strategy, we may not realize cost structure efficiencies and our operating and financial results could be materially adversely affected. 
+In addition, if any of our contract manufacturers experience business difficulties or fails to meet our manufacturing needs, then we may be unable to meet production requirements, may lose revenue and may not be able to maintain relationships with our customers. Without the contract manufacturers continuing to manufacture our products and the continuing operation of the contract manufacturers’ facilities, we will have limited means for the final assembly of a majority of our products until we are able to secure the manufacturing capability at another facility or develop an alternative manufacturing facility, which could be costly and time consuming and have a material adverse effect on our operating and financial results. 
+The increased elements of risk that arise from conducting certain operating processes in foreign jurisdictions may lead to an increase in reputational risk. 
+Although we carry business interruption insurance to cover lost revenue and profits in an amount we consider adequate, this insurance does not cover all possible situations. In addition, the business interruption insurance would not compensate us for the loss of opportunity and potential adverse impact, both short-term and long-term, on relations with our existing customers resulting from our inability to produce products for them. 
+The contract manufacturers have access to our intellectual property, which increases the risk of infringement or misappropriation of this intellectual property. 
+We source some of our component parts and consumable products from sole source suppliers; any disruptions may impact our ability to manufacture and sell our products. 
+A disruption in the supply of such component parts and consumable products could have a material adverse effect on our operations and financial results. 
+We sell a significant portion of our products internationally and purchase important components from foreign suppliers. These circumstances create a number of risks. 
+We sell a significant amount of our products to customers outside the United States. Shipments to international customers are expected to continue to account for a material portion of net sales. Risks associated with sales and purchases outside the United States include: 
+· 
+fluctuating foreign currency rates could restrict sales, or increase costs of purchasing, in foreign countries; 
+· 
+foreign governments may impose burdensome tariffs, quotas, taxes, trade barriers or capital flow restrictions; 
+· 
+political and economic instability may reduce demand for our products or put our foreign assets at risk; 
+· 
+restrictions on the export or import of technology may reduce or eliminate the ability to sell in or purchase from certain markets; and 
+· 
+potentially limited intellectual property protection in certain countries, such as China, may limit recourse against infringing products or cause us to refrain from selling in certain geographic territories. 
+We face risks associated with manufacturing forecasts. 
+If we fail to predict our manufacturing requirements accurately, we could incur additional costs or experience manufacturing delays, which could cause us to lose orders or customers and result in lower net sales. We currently use a rolling 12-month forecast based primarily on our anticipated product orders and our product order history to help determine our requirements for components and materials. It is very important that we accurately predict both the demand for our products and the lead-time required to obtain the necessary components and raw materials. 
+Lead times for materials and components that we order vary significantly and depend on factors such as the specific supplier, the size of the order, contract terms, and demand for each component at a given time. If we underestimate our requirements, we may have inadequate manufacturing capacity or inventory, which could interrupt manufacturing of our products and result in delays in shipments and net sales. If we overestimate our requirements, we could have excess inventory of parts. In addition, delays in the manufacturing of our products could cause us to lose orders or customers. 
+In the lottery market, we have been dependent on sales to one large customer; the loss of this customer or reduction in orders from this customer could materially affect our sales. 
+We expect that sales to one large customer will continue to represent a material percentage of our net sales for the foreseeable future. A reduction, delay or cancellation in orders from this customer, including reductions or delays due to market, economic, or competitive conditions in the industries in which we serve, could have a material adverse effect upon our results of operations. 
+Our success will depend on our ability to sustain and manage growth. 
+As part of our business strategy, we intend to pursue a growth strategy. Assuming this growth occurs, it will require the expansion of distribution relationships in international markets, the successful development and marketing of new products for our existing and new markets, expanded customer service and support, and the continued implementation and improvement of our operational, financial and management information systems. 
+6 
+To the extent that we seek growth through acquisitions, our ability to manage our growth will also depend on our ability to integrate businesses that have previously operated independently. We may not be able to achieve this integration without encountering difficulties or experiencing the loss of key employees, customers or suppliers. It may be difficult to design and implement effective financial controls for combined operations and differences in existing controls for each business may result in weaknesses that require remediation when the financial controls and reporting functions are combined. As we pursue acquisitions, we may incur legal, accounting and other transaction related expenses for unsuccessful acquisition attempts that could adversely affect our results of operations in the period in which they are incurred. 
+There can be no assurance that we will be able to successfully implement our growth strategy, or that we can successfully manage expanded operations. As we expand, we may from time to time experience constraints that will adversely affect our ability to satisfy customer demand in a timely fashion. Failure to manage growth effectively could adversely affect our results of operations and financial condition. 
+We compete in highly competitive markets, which are likely to become more competitive. Competitors may be able to respond more quickly to new or emerging technology and changes in customer requirements. 
+We face significant competition in developing and selling our printers, terminals, software, transaction supplies and services. Principal competitors have substantial marketing, financial, development and personnel resources. To remain competitive, we believe we must continue to provide: 
+· 
+technologically advanced products that satisfy the user demands; 
+· 
+superior customer service; 
+· 
+high levels of quality and reliability; and 
+· 
+dependable and efficient distribution networks. 
+We cannot ensure we will be able to compete successfully against current or future competitors. Increased competition may result in price reductions, lower gross profit margins and loss of market share, and could require increased spending on research and development, sales and marketing and customer support. Some competitors may make strategic acquisitions or establish cooperative relationships with suppliers or companies that produce complementary products. Any of these factors could reduce our earnings. 
+We depend on key personnel, the loss of which could materially impact our business. 
+Our future success will depend in significant part upon the continued service of certain key management and other personnel and our continuing ability to attract and retain highly qualified managerial, technical and sales and marketing personnel. There can be no assurance that we will be able to recruit and retain such personnel. The loss of either Bart C. Shuldman, the Company's Chairman of the Board and Chief Executive Officer, or Steven A. DeMartino, the Company’s President, Chief Financial Officer, Treasurer and Secretary, or the loss of certain groups of key employees, could have a material adverse effect on our results of operations. 
+If we are unable to enforce our patents or if it is determined that we infringe patents held by others it could damage our business. 
+Prosecuting and defending patent lawsuits is very expensive. We are committed to aggressively asserting and defending our technology and related intellectual property, which we have spent a significant amount of money to develop. These factors could cause us to become involved in new patent litigation in the future. The expense of prosecuting or defending these future lawsuits could also have a material adverse effect on our business, financial condition and results of operations. 
+If we were to lose a patent lawsuit in which another party is asserting that our products infringe its patents, we would likely be prohibited from marketing those products and could also be liable for significant damages. Either or both of these results may have a material adverse effect on our business, financial condition and results of operations. If we lose a patent lawsuit in which we are claiming that another party’s products are infringing our patents and thus, are unable to enforce our patents, it may have a material adverse effect on our business, financial condition and results of operations. In addition to disputes relating to the validity or alleged infringement of other parties' rights, we may become involved in disputes relating to our assertion of our own intellectual property rights. Whether we are defending the assertion of intellectual property rights against us or asserting our intellectual property rights against others, intellectual property litigation can be complex, costly, protracted, and highly disruptive to business operations by diverting the attention and energies of management and key technical personnel. Plaintiffs in intellectual property cases often seek injunctive relief, and the measures of damages in intellectual property litigation are complex and often subjective or uncertain. Thus, any adverse determinations in this type of litigation could subject us to significant liabilities and costs. During the course of these lawsuits there may be public announcements of the results of hearings, motions, and other interim proceedings or developments in the litigation. If securities analysts or investors perceive these results to be negative, it could harm the market price of our stock. 
+The inability to protect intellectual property could harm our reputation, and our competitive position may be materially damaged. 
+Our intellectual property is valuable and provides us with certain competitive advantages. Copyrights, patents, trade secrets and contracts are used to protect these proprietary rights. Despite these precautions, it may be possible for third parties to copy aspects of our products or, without authorization, to obtain and use information which we regard as trade secrets. 
+Infringement on the proprietary rights of others could put us at a competitive disadvantage, and any related litigation could be time consuming and costly. 
+Third parties may claim that we violated their intellectual property rights. To the extent of a violation of a third party’s patent or other intellectual property right, we may be prevented from operating our business as planned and may be required to pay damages, to obtain a license, if available, or to use a non-infringing method, if possible, to accomplish our objectives. Any of these claims, with or without merit, could result in costly litigation and divert the attention of key personnel. If such claims are successful, they could result in costly judgments or settlements. Refer to Item 3. “Legal Proceedings” for discussion surrounding litigation we are currently involved in regarding alleged misappropriation of unspecified trade secrets and confidential information. 
+7 
+Our stock price may fluctuate significantly. 
+The market price of our common stock could fluctuate significantly in response to variations in quarterly operating results and other factors, such as: 
+· 
+changes in our business, operations or prospects; 
+· 
+developments in our relationships with our customers; 
+· 
+announcements of new products or services by us or by our competitors; 
+· 
+announcement or completion of acquisitions by us or by our competitors; 
+· 
+changes in existing or adoption of additional government regulations; 
+· 
+unfavorable or reduced analyst coverage; and 
+· 
+prevailing domestic and international market and economic conditions. 
+In addition, the stock market has experienced significant price fluctuations in recent years. Broad market fluctuations, general economic conditions and specific conditions in the industries in which we operate may adversely affect the market price of our common stock. 
+Limited trading volume and a reduction in analyst coverage of our capital stock may contribute to its price volatility. 
+Our common stock is traded on the NASDAQ Global Market. During the year ended December 31, 2013, the average daily trading volume for our common stock as reported by the NASDAQ Global Market was approximately 20,000 shares. We are uncertain whether a more active trading market in our common stock will develop. In addition, many investment banks no longer find it profitable to provide securities research on micro-cap and small-cap companies. As a result, relatively small trades may have a significant impact on the market price of our common stock, which could increase the volatility and depress the price of our common stock. 
+Future sales of our common stock may cause our stock price to decline. 
+In the future, we may sell additional shares of our common stock in public or private offerings, and we may also issue additional shares of our common stock to finance future acquisitions. Shares of our common stock are also available for future sale pursuant to stock options that we have granted to our employees, and in the future we may grant additional stock options and other forms of equity compensation to our employees. Sales of our common stock or the perception that such sales could occur may adversely affect prevailing market prices for shares of our common stock and could impair our ability to raise capital through future offerings. 
+If market conditions deteriorate or future results of operations are less than expected, a valuation allowance may be required for all or a portion of our deferred tax assets. 
+We currently have deferred tax assets, which may be used to reduce taxable income in the future. We assess the realization of these deferred tax assets on a quarterly basis, and if we determine that it is more likely than not that some portion of these assets will not be realized, an income tax valuation allowance is recorded. If market conditions deteriorate or future results of operations are less than expected, or there is a change to applicable tax rules, future assessments may result in a determination that it is more likely than not that some or all of our net deferred tax assets are not realizable. As a result, we may need to establish a valuation allowance for all or a portion of our net deferred tax assets, which may have a material adverse effect on our business, results of operations and financial condition. 
+We cannot provide any assurance that current laws, or any laws enacted in the future, will not have a material adverse effect on our business. 
+Our operations are subject to laws, rules, regulations, including environmental regulations, government policies and other requirements in each of the jurisdictions in which we conduct business. Changes in laws, rules, regulations, policies or requirements could result in the need to modify our products and could affect the demand for our products, which may have an adverse impact on our future operating results. If we do not comply with applicable laws, rules and regulations we could be subject to costs and liabilities and our business may be adversely impacted. 
+Intangible computer software costs may not be recoverable. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheets until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. To the extent technological feasibility of products is not achieved, related capitalized computer software costs may not be recoverable. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. 
+Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. It is possible that terrorist attacks could be directed at important locations for the gaming industry. Heightened security measures and other efforts to combat terrorism may also have an adverse effect on the gaming industry by reducing tourism. Any of these developments could also negatively affect the general economy and consumer confidence. Any downturn in the economy or in the gaming industry in particular could reduce demand for our products and adversely affect our business and results of operations. In addition, heightened security measures may cause certain governments to restrict the import/export of goods, which may have an adverse effect on our ability to buy/sell goods. 
+Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial also may adversely impact our business. Should any risks or uncertainties develop into actual events, these developments could have material adverse effects on our business, financial condition, and results of operations. 
+Item 1B. Unresolved Staff Comments. 
+Not applicable. 
+8 
+Item 2. Properties. 
+Our principal facilities as of December 31, 2013 are listed below and we believe that all facilities generally are in good condition, adequately maintained and suitable for their present and currently contemplated uses. 
+Location 
+Operations Conducted 
+Size 
+(Approx. Sq. Ft.) 
+Owned or 
+Leased 
+Lease Expiration 
+Date 
+Hamden, Connecticut 
+Executive offices and Printrex and TSG sales office 
+11,100 
+Leased 
+April 23, 2017 
+Ithaca, New York 
+Global engineering, design, assembly and service facility 
+73,900 
+Leased 
+May 31, 2016 
+Las Vegas, Nevada 
+Service center and casino and gaming sales office 
+13,700 
+Leased 
+December 31, 2016 
+Doncaster, United Kingdom 
+Sales office and service center 
+2,800 
+Leased 
+August 1, 2016 
+Houston, Texas 
+Sales office and service center 
+1,350 
+Leased 
+April 30, 2015 
+San Jose, California 
+Engineering office 
+1,340 
+Leased 
+February 28, 2014 
+Georgia and New York 
+Two regional sales offices 
+300 
+Leased 
+Various 
+Macau, China 
+Sales office 
+180 
+Leased 
+June 30, 2014 
+104,670 
+Item 3. Legal Proceedings. 
+On June 8, 2012, Avery Dennison Corporation (“AD”) filed a civil complaint against the Company and a former employee of the Company and of AD, in the Court of Common Pleas (the “Court”) in Lake County, Ohio. The complaint alleges that this former employee and the Company misappropriated unspecified trade secrets and confidential information related to the design of our food safety terminals from AD. The complaint requests a preliminary and permanent injunction against the Company from manufacturing and selling our Ithaca® 9700 and 9800 food safety terminals. On July 16, 2012, the Company filed its answer, affirmative defenses and counterclaims, seeking all available damages including legal fees. A hearing on the plaintiff's motion for preliminary injunction took place in August 2012, and in November 2012, the Court denied this request. AD filed an appeal of the Court’s ruling to the Eleventh Appellate District, which heard oral arguments on the appeal on July 16, 2013. On July 23, 2013, AD requested that the Eleventh Appellate District enjoin the Company’s further sale and marketing of the food safety terminals, pending the appeals court's decision. On July 29, 2013, TransAct opposed this request. On October 15, 2013, the Eleventh District Court of Appeals affirmed the lower court’s decision in the Company’s favor and denied AD’s further request for an injunction pending the Court of Appeal’s decision. On October 24, 2013, AD filed a motion seeking that the Court of Appeals reconsider its decision. 
+Item 4. Mine Safety Disclosures. 
+Not applicable. 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+Our common stock is traded on the NASDAQ Global Market under the symbol TACT. As of February 28, 2014, there were 424 holders of record of the common stock. The high and low bid sales prices of the common stock reported during each quarter of the years ended December 31, 2013 and 2012 were as follows: 
+Year Ended 
+Year Ended 
+December 31, 2013 
+December 31, 2012 
+High 
+Low 
+High 
+Low 
+First Quarter 
+$ 
+8.20 
+$ 
+7.15 
+$ 
+8.37 
+$ 
+6.46 
+Second Quarter 
+8.50 
+7.22 
+9.15 
+7.29 
+Third Quarter 
+13.19 
+7.75 
+7.97 
+6.64 
+Fourth Quarter 
+15.23 
+11.54 
+7.91 
+7.01 
+On September 10, 2012, we announced that our Board of Directors approved the initiation of a quarterly cash dividend program which is subject to the Board’s approval each quarter. On May 2, 2013, our Board of Directors declared an increase to the quarterly cash dividend from $0.06 per share to $0.07 per share. Dividends declared and paid on our common stock totaled $2,317,000 or $0.27 per share and $526,000 or $0.06 per share, in 2013 and 2012, respectively . On February 4, 2014, our Board of Directors approved the first quarter 2014 dividend in the amount of $0.07 per share payable on or about March 14, 2014 to common shareholders of record at the close of business on February 20, 2014. 
+Issuer Purchases of Equity Securities 
+Prior to its expiration on May 27, 2013, we maintained a stock repurchase program (the “Stock Repurchase Program”) whereby we were authorized to repurchase up to $15,000,000, as increased from $10,000,000 in March 2012, of our outstanding shares of common stock from time to time in the open market, depending on market conditions, share price and other factors. The Stock Repurchase Program expired on May 27, 2013 and was not renewed. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the settlement date. From January 1, 2013 through the expiration date of the Stock Repurchase Program, we repurchased 114,161 shares of our common stock for approximately $887,000 at an average price per share of $7.77. In addition to shares repurchased under the Stock Repurchase Program, during the year ended December 31, 2013, we repurchased 490,000 shares of our common stock for approximately $4,307,000 at an average price per share of $8.79 in an open-market transaction. From January 1, 2005 through December 31, 2013, we repurchased a total of 2,787,038 shares of common stock for approximately $22,527,000, at an average price of $8.08 per share. As of December 31, 2013, no additional shares are authorized for future repurchases due to the expiration of the Stock Repurchase Program. 
+9 
+CORPORATE PERFORMANCE GRAPH 
+The following graph compares the cumulative total return on the Company’s Common Stock from December 31, 2008 through December 31, 2013, with the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index. The graph assumes that $100 was invested on December 31, 2008 in each of TransAct’s common stock, the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index, and that all dividends were reinvested. 
+COMPARISON OF CUMULATIVE TOTAL RETURN AMONG 
+TRANSACT TECHNOLOGIES INCORPORATED COMMON STOCK, 
+THE CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.), 
+AND THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX 
+12/31/08 
+12/31/09 
+12/31/10 
+12/31/11 
+12/31/12 
+12/31/13 
+TransAct Technologies Incorporated Common Stock 
+$ 
+100.00 
+$ 
+151.20 
+$ 
+205.23 
+$ 
+158.17 
+$ 
+157.30 
+$ 
+272.98 
+CRSP Total Return Index for the Nasdaq Stock Market (U.S.) 
+$ 
+100.00 
+$ 
+143.74 
+$ 
+170.17 
+$ 
+171.08 
+$ 
+202.40 
+$ 
+281.91 
+Nasdaq Computer Manufacturer Stocks Index 
+$ 
+100.00 
+$ 
+219.64 
+$ 
+313.47 
+$ 
+367.84 
+$ 
+467.63 
+$ 
+538.59 
+10 
+Item 6. Selected Financial Data (in thousands, except per share amounts) 
+The following is summarized from our audited financial statements of the past five years: 
+Year ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+Consolidated Statement of Operations Data: 
+Net sales 
+$ 
+60,141 
+$ 
+68,386 
+$ 
+65,969 
+$ 
+63,194 
+$ 
+58,346 
+Gross profit 
+25,092 
+25,982 
+24,626 
+22,548 
+18,829 
+Operating expenses 
+18,475 
+20,380 
+17,637 
+16,687 
+15,533 
+Operating income 
+6,617 
+5,602 
+6,989 
+5,861 
+3,296 
+Net income 
+4,935 
+3,621 
+4,676 
+3,904 
+2,140 
+Net income per share: 
+Basic 
+0.57 
+0.40 
+0.50 
+0.42 
+0.23 
+Diluted 
+0.57 
+0.40 
+0.49 
+0.41 
+0.23 
+Dividends declared and paid per share 
+0.27 
+0.06 
+- 
+- 
+- 
+December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+Consolidated Balance Sheet Data: 
+Total assets 
+$ 
+40,408 
+$ 
+45,228 
+$ 
+42,740 
+$ 
+43,621 
+$ 
+34,899 
+Working capital 
+24,871 
+25,492 
+27,222 
+25,525 
+20,474 
+Shareholders’ equity 
+32,521 
+33,369 
+35,313 
+31,134 
+26,354 
+Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 
+This discussion should be read in conjunction with the Consolidated Financial Statements and notes thereto. 
+Forward Looking Statements 
+Certain statements included in this report, including without limitation statements in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, which are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements generally can be identified by the use of forward-looking terminology, such as “may”, “will”, “expect”, “intend”, ”estimate”, “anticipate”, “believe”, “project” or “continue” or the negative thereof or other similar words. All forward-looking statements involve risks and uncertainties, including, but not limited to those listed in Item 1A of this Annual Report. Actual results may differ materially from those discussed in, or implied by, the forward-looking statements. The forward-looking statements speak only as of the date of this report and we assume no duty to update them. 
+Overview 
+During 2013, we continued to transition our business to focus on sales of value-added products and technologies in diversified growth markets while moving away from the low margin, commoditized POS market. To that end, we saw a significant increase in sales from our new food safety and nutritional labeling terminal, the Ithaca® 9700 food safety terminal, which has been well received by our customers. We have numerous field tests and trials that are currently ongoing at several restaurant chains and while these trials areprogressing, we expect further sales growth from the Ithaca® 9700 food safety terminal in 2014. Additionally, during 2013 we installed EPICENTRAL™ at an additional six casinos and experienced significant revenue growth from these installations as a result. Casinos that have installed the system can now measure its success through various industry metrics, such as increased carded play and the results our casino customers have experienced has been very positive. Because these casinos have allowed us to share such metrics with other potential customers, we expect our EPICENTRAL™ sales to continue to ramp during 2014. 
+During 2012, we developed and launched two new printers for the oil and gas exploration market which we believe represents a worldwide growth opportunity for us. Our Printrex® 980 printer, the fastest color office printer designed specifically for high-volume printing of oil and gas logging reports in the office has already won orders and has the opportunity to drive significant recurring consumable revenue based on proprietary inkjet cartridges, inkjet print heads and other items that these printers consume as our customers use the printer. Our Printrex® 920, a thermal truck-mounted printer designed for the rugged and demanding exploration and production market, prints color logging reports at the well site, has also begun to win orders, and utilizes proprietary color thermal paper which represents another lucrative recurring consumable revenue stream for us. Although we began to see revenue contributions from both the Printrex 920 and 980 during 2013, the sales cycle is taking longer than we anticipated as the printers must be integrated into the many oil and gas explorations systems around the world. However, we continue to receive positive responses from the industry to our new color thermal printing technology which would replace the black and white printing of logging reports done today for drilling, casing and wire-line analysis and believe sales will slowly ramp in 2014. 
+We also continued to focus on increasing our overall gross margin and leveraging such increase to our operating income primarily by focusing our sales effort on our new, higher margin products in addition to our continual effort of reducing costs of our foreign-sourced printers. Despite lower sales volume of 12% in 2013, we increased our gross margin to 41.7% which was a record high for us. Also, while our total printer and terminal shipments decreased 23% to approximately 153,000 in 2013, the average selling price of printers sold during the year increased by 7%. 
+11 
+During 2013, our total net sales decreased 12% to approximately $60,141,000. See the table below for a breakdown of our sales by market: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Food safety, banking and POS 
+$ 
+11,296 
+18.8% 
+$ 
+9,484 
+13.9% 
+$ 
+1,812 
+19.1% 
+Casino and gaming 
+27,300 
+45.4% 
+29,129 
+42.6% 
+(1,829) 
+(6.3%) 
+Lottery 
+4.450 
+7.4% 
+11,634 
+17.0% 
+(7,184) 
+(61.8%) 
+Printrex 
+4,335 
+7.2% 
+4,673 
+6.8% 
+(338) 
+(7.2%) 
+TSG 
+12,760 
+21.2% 
+13,466 
+19.7% 
+(706) 
+(5.2%) 
+Total net sales 
+$ 
+60,141 
+100.0% 
+$ 
+68,386 
+100.0% 
+$ 
+(8,245) 
+(12.1%) 
+Sales of our food safety, banking and POS products increased 19% in 2013 compared to 2012. During 2013, our newly developed Ithaca® 9700 food safety terminal provided significant revenue contributions. We currently have over 100 customers trialing the Ithaca 9700 and we expect this product to be a significant contributor to our revenue growth over the next few years. In the banking market, we focus mainly on supplying printers for use in bank teller stations at banks and financial institutions primarily in the U.S. Opportunities in the banking market are project oriented and, as a result, our banking printer sales can fluctuate significantly year-to-year. During 2013, our banking printer sales decreased 61% primarily due to sales from a large order for our Ithaca® 280 thermal receipt printer to a new banking customer that occurred in 2012 and did not repeat in 2013. In the POS market, we focus primarily on supplying printers that print receipts or linerless labels for customers in the restaurant, hospitality and specialty retail markets. Sales of our POS printers decreased 13% in 2013 primarily driven by lower domestic and international sales of our legacy POS printers as we continue to decrease our focus on this commoditized market. However, sales of POS printers to McDonald’s continued to grow in 2013 with the first year of volume sales of our new Ithaca 9000 and we expect to continue to pursue more business from McDonald’s for both this printer, and the Ithaca 9700 food safety terminal during 2014. 
+Sales of our casino and gaming products decreased 6% in 2013 compared to 2012. In our casino and gaming market, our focus lies primarily in supplying printers for use in slot machines at casinos and racetracks, as well as in other electronic gaming devices that print tickets or receipts, worldwide. Additionally, we supplement these printer sales with revenue from EPICENTRAL™ - our promotional printing system that enables casino operators to create promotional coupons and marketing messages and print them real time at the slot machine -for which we had nine executed contracts as of the end of 2013. Domestic casino and gaming sales increased 8%, mostly from a significant increase in revenue resulting from six completed installations of EPICENTRAL™ during 2013. International sales decreased by 20%, primarily due to decreases in both casino ticket printer sales and off-premise thermal gaming printers, mainly from our European distributor. 
+In the lottery market, we continue to hold a leading position based on our long-term exclusive purchase agreement with GTECH, our largest customer and the world’s largest provider of lottery terminals. GTECH has been our customer since 1995, and we continue to maintain a good relationship with them. In 2009 we expanded our long-standing relationship with GTECH by executing a new exclusive purchase agreement to develop and supply them with their next generation online thermal lottery printer. Pursuant to the new agreement, GTECH will exclusively purchase all of its requirements for thermal on-line lottery printers from us and we will exclusively sell such printers to GTECH through November 2014. Currently, we fulfill substantially all of GTECH’s printer requirements for lottery terminal installations and upgrades worldwide. During 2013, total printer sales to GTECH decreased approximately 62%, compared to 2012. Sales for 2012 were unusually high as GTECH made a final purchase for an older generation lottery printer that we discontinued production for at the end of 2012. Our sales to GTECH each year are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs and are not indicative of GTECH’s overall business or revenue. 
+Sales of our Printrex branded printers include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. Sales in this market also includes wide format printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. During 2013, we had solid revenue contributions from our new Printrex® 920 and Printrex® 980 oil and gas color printers developed in 2012. We believe that over time, sales of our color printers will increase as these printers provide customers with more value as data printed in color is easier to read and analyze than the same data printed in black and white. Despite the increase in color printer sales, Printrex printer sales for 2013 decreased by approximately $338,000 primarily due to lower black and white oil and gas printer sales compared to 2012. 
+Our TSG group, which sells service, replacement parts and consumable products, including receipt paper, ribbons and inkjet cartridges, continues to offer a recurring revenue stream for the Company. TSG sales decreased 5% in 2013 from 2012 primarily due to lower sales of non-Printrex consumables compared to 2012 from the effect of lower HP inkjet cartridge sales as we deemphasize our focus on this commoditized product. This decrease was partially offset by higher replacement part sales and Printrex color printer consumable sales which should continue to increase as the installed base of these printers grows. 
+Operationally, our gross margin increased to a record annual high 41.7% compared to 38.0% in 2012. This increase in our gross margin reflects the success we’ve had in transitioning our business to a more favorable sales mix of our new value-added products , including the Ithaca® 9700 food safety terminals and EPICENTRAL™ software. In addition, we continue to benefit from cost control efforts, specifically in striving to drive lower production costs. Our operating margin for 2013 was 11.0% compared to 8.2% in 2012. 
+We reported net income of $4,935,000 and net income per diluted share of $0.57 for 2013, compared to net income of $3,621,000 and net income per diluted share of $0.40 in 2012. In terms of cash flow for 2013, we generated $2,493,000 of cash from operating activities and received cash proceeds from stock option exercises, inclusive of incremental tax benefits, of $1,177,000. We also utilized $5,194,000 for treasury share repurchases, $2,317,000 for cash dividend payments to shareholders and $751,000 for capital expenditures and additions to capitalized software resulting in cash and cash equivalents of $2,936,000 and no debt on our Consolidated Balance Sheet at December 31, 2013. 
+12 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect both Balance Sheet items and Statement of Income categories. Such estimates and judgments are based upon historical experience and certain assumptions that are believed to be reasonable in the particular circumstances. We evaluate our assumptions on an ongoing basis by comparing actual results with our estimates. Actual results may differ from the original estimates. 
+The following accounting policies are those that we believe to be most critical in the preparation of our financial statements. These items utilize assumptions and estimates about the effect of future events that are inherently uncertain and are therefore based on our judgment. Please refer to Note 2 – Summary of significant accounting policies in the accompanying Consolidated Financial Statements for a complete listing of our accounting policies. 
+Revenue Recognition – Our typical contracts include the sale of printers and terminals, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within Accounting Standards Codification (“ASC”) 605, “Revenue Recognition” (ASC 605). Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers and terminals to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+Our software solution, EPICENTRAL TM , enables casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. Revenue arrangements for EPICENTRAL TM include multiple deliverables and as a result such arrangements are accounted for in accordance with both ASC 605-25, “Multiple-Element Arrangements” and ASC 985-605, “Software.” EPICENTRAL TM is primarily comprised of both a software component, which is licensed, and a hardware component, which can either be leased or sold to end users, and both components are integrated to deliver the system’s full functionality. Under leasing arrangements, revenue is generally recognized ratably over the lease term, excluding revenue allocated to installation, which is recognized upon completion. In an arrangement where the hardware is purchased, revenue, inclusive of software license fees, is generally recognized upon installation and formal acceptance by the customer. For EPICENTRAL TM and other multiple deliverable arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and recognize revenue as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this guidance, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established, but we cannot guarantee that we will continue to experience return rates consistent with historical patterns. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. However, we cannot guarantee that this minimal level will continue. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Accounts Receivable – We have standardized credit granting and review policies and procedures for all customer accounts, including: credit reviews of all new customer accounts; ongoing credit evaluations of current customers; credit limits and payment terms based on available credit information; and adjustments to credit limits based upon payment history and the customer’s current creditworthiness. We also provide an estimate of doubtful accounts based on historical experience and specific customer collection issues. Our allowance for doubtful accounts as of December 31, 2013 was approximately $63,000, or less than 1.0% of outstanding accounts receivable, which we feel is appropriate considering the overall quality of our accounts receivable. While credit losses have historically been within expectations and the reserves established, we cannot guarantee that our credit loss experience will continue to be consistent with historical experience. 
+Inventories – Our inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Assumptions are reviewed at least quarterly and adjustments are made, as necessary, to reflect changing market conditions. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. Should circumstances change and we determine that additional inventory is subject to obsolescence, additional write-downs of inventory could result in a charge to income. 
+Goodwill and Intangible Assets – We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with Accounting Standards Codification (“ASC”) 350-20 “Goodwill”, acquired goodwill is not amortized but is subject to impairment testing at least annually and when an event occurs or circumstances change, that indicate it is more likely than not an impairment exists. Factors considered that may trigger an impairment review are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Definite lived intangible assets are amortized and are tested for impairment when appropriate. We reported $2,621,000 of goodwill and $1,856,000 of unamortized definite-lived intangible assets at December 31, 2013. We have determined that no goodwill impairment has occurred based on our assessment as of December 31, 2013 when the impairment review is performed. 
+13 
+Income Taxes – In preparing our Consolidated Financial Statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. This involves estimating the actual current tax exposure together with assessing temporary differences between the tax basis of certain assets and liabilities and their reported amounts in the financial statements, as well as net operating losses, tax credits and other carryforwards. These differences result in deferred tax assets and liabilities, which are included within our Consolidated Balance Sheets. We then assess the likelihood that the deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. 
+Significant judgment is required in determining the provision for income taxes and, in particular, any valuation allowance or tax reserves with respect to our deferred tax assets and uncertain tax positions. On a quarterly basis, we evaluate the recoverability of our deferred tax assets based upon historical results and forecasted taxable income over future years, and match this forecast against the basis differences, deductions available in future years and the limitations allowed for net operating loss and tax credit carryforwards to ensure that there is adequate support for the realization of the deferred tax assets. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance or tax reserve, in the event we were to determine that we would not be able to realize all or part of our deferred tax assets in the future, an adjustment to the valuation allowance or tax reserves would be charged as a reduction to income in the period such determination was made. Likewise, should we determine that we would be able to realize future deferred tax assets in excess of its net recorded amount, an adjustment to the valuation allowance or tax reserves would increase net income in the period such determination was made. 
+We account for income taxes in accordance with ASC 740, “Income Taxes.” Among other things this provision prescribes a minimum recognition threshold that an income tax position must meet before it is recorded in the reporting entity’s financial statements. It also requires that the effects of such income tax positions be recognized only if, as of the balance sheet reporting date, it is “more likely than not” (i.e., more than a 50% likelihood) that the income tax position will be sustained based solely on its technical merits. When making this assessment, management must assume that the responsible taxing authority will examine the income tax position and have full knowledge of all relevant facts and other pertinent information. The accounting guidance also clarifies the method of accruing for interest and penalties when there is a difference between the amount claimed, or expected to be claimed, on a company’s income tax returns and the benefits recognized in the financial statements. 
+Warranty – We generally warrant our products for up to 36 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. If actual future product repair rates or the actual costs of material and labor differ from the estimates, adjustments to the accrued warranty liability and related warranty expense would be made. 
+Contingencies – We record an estimated liability related to contingencies based on our estimates of the probable outcomes pursuant to ASC 450, “Contingencies.” On a quarterly basis, we assess the potential liability related to pending litigation, audits and other contingencies and confirm or revise estimates and reserves as appropriate. If the actual liabilities are settled in an amount greater than those recorded on the balance sheet, a charge to income would be recorded. As of December 31, 2013 and 2012, a contingent liability of $60,000 and $960,000, respectively, was recorded in connection with a contingent consideration arrangement entered into as part of the Printrex acquisition. The decrease of $900,000 was the result of our revised estimate of the expected payout in connection with this arrangement primarily due to changes in probabilities and decreases in revenue and gross margin estimates, and was credited to general and administrative expense during 2013. See Note 3 to the Consolidated Financial Statements for further discussion. 
+Share-Based Compensation – We calculate share-based compensation expense in accordance with ASC 718, “Compensation – Stock Compensation” using the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions for this valuation method include the expected term of an option grant, stock price volatility, risk-free interest rate, dividend yield, and forfeiture rate. The determination of these assumptions is based on past history and future expectations, and is subject to a high level of judgment. To the extent any of the assumptions were to change from year to year, the fair value of new option grants may vary significantly. 
+Results of Operations: Year ended December 31, 2013 compared to year ended December 31, 2012 
+Net Sales. Net sales, which include printer, terminal and software sales as well as sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2013 and 2012 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Food safety, banking and POS 
+$ 
+11,296 
+18.8% 
+$ 
+9,484 
+13.9% 
+$ 
+1,812 
+19.1% 
+Casino and gaming 
+27,300 
+45.4% 
+29,129 
+42.6% 
+(1,829) 
+(6.3%) 
+Lottery 
+4,450 
+7.4% 
+11,634 
+17.0% 
+(7,184) 
+(61.8%) 
+Printrex 
+4,335 
+7.2% 
+4,673 
+6.8% 
+(338) 
+(7.2%) 
+TSG 
+12,760 
+21.2% 
+13,466 
+19.7% 
+(706) 
+(5.2%) 
+$ 
+60,141 
+100.0% 
+$ 
+68,386 
+100.0% 
+$ 
+(8,245) 
+(12.1%) 
+International* 
+$ 
+13,764 
+22.9% 
+$ 
+18,454 
+27.0% 
+$ 
+(4,690) 
+(25.4%) 
+* International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+14 
+Net sales for 2013 decreased $8,245,000, or 12%, from 2012. Printer and terminal sales volume decreased 23% to approximately 153,000 units primarily due to declines in the lottery and casino and gaming markets of 60% and 11%, respectively. The average selling price of our printers increased approximately 7% from 2012 to 2013 due primarily to higher sales of our food safety terminals which have a significantly higher average selling price than most of our other printers. Also contributing to our higher average selling price was a significant reduction in lottery printer sales volume due to a large order by GTECH in 2012 which was not repeated in 2013. Overall, international sales decreased $4,690,000, or 25%, primarily driven by lower sales in both the international casino and gaming and lottery markets. 
+Food safety, banking and POS : Revenue from the food safety, banking and POS market includes sales of food safety terminals, hardware devices that consist of a touchscreen and one or two thermal print mechanisms, that print easy-to-read expiration and "enjoy by" date labels to help restaurants effectively manage food spoilage. Revenue from this market also includes sales of inkjet, thermal and impact printers used primarily by retailers in the restaurant (including fine dining, casual dining and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In addition, revenue includes sales of printers used by banks, credit unions and other financial institutions to print receipts and/ or validate checks at bank teller stations. A summary of sales of our worldwide food safety, banking and POS products for the years ended December 31, 2013 and 2012 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Domestic 
+$ 
+10,956 
+97.0% 
+$ 
+8,876 
+93.6% 
+$ 
+2,080 
+23.4% 
+International 
+340 
+3.0% 
+608 
+6.4% 
+(268) 
+(44.1%) 
+$ 
+11,296 
+100.0% 
+$ 
+9,484 
+100.0% 
+$ 
+1,812 
+19.1% 
+The increase in domestic food safety, banking and POS product revenue from 2012 was primarily driven by higher sales from our newly launched Ithaca® 9700 food safety terminal and Ithaca® 9000 printer. This was partially offset by lower sales of our banking printers mainly due to the shipment of a large order for our Ithaca® 280 thermal receipt printer to a banking customer in 2012 that did not repeat in 2013 as well as lower sales of our legacy POS printers as we continue to decrease our focus on this commoditized market. Although we are currently pursuing several banking opportunities, due to the project-oriented nature of these sales, we cannot predict the level of future sales. 
+International banking and POS printer sales for 2013 decreased 44% from 2012 due primarily to lower sales for the McDonald’s POS system upgrade and grill initiative in its Canadian stores in 2013 compared to 2012, partially offset by higher sales of our Ithaca® 9700 food safety terminal. 
+Casino and gaming : Revenue from the casino and gaming market includes sales of printers used in slot machines, video lottery terminals (“VLTs”), and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos and racetracks (“racinos”) and other gaming venues worldwide. Revenue from this market also includes sales of printers used in the international off-premise gaming market in gaming machines such as Amusement with Prizes (“AWP”), Skills with Prizes (“SWP”) and Fixed Odds Betting Terminals (“FOBT”) at non-casino gaming establishments. Revenue from this market also includes royalties related to our patented casino and gaming technology. In addition, casino and gaming market revenue includes sales of our software solution, EPICENTRAL TM , that enables casino operators to create promotional coupons and marketing messages and to print them real-time at the slot machine. A summary of sales of our worldwide casino and gaming products for the years ended December 31, 2013 and 2012 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Domestic 
+$ 
+15,367 
+56.3% 
+$ 
+14,283 
+49.0% 
+$ 
+1,084 
+7.6% 
+nternational 
+11,933 
+43.7% 
+14,846 
+51.0% 
+(2,913) 
+(19.6%) 
+$ 
+27,300 
+100.0% 
+$ 
+29,129 
+100.0% 
+$ 
+(1,829) 
+(6.3%) 
+The increase in domestic sales is primarily due to an increase in EPICENTRAL TM software sales partially offset by a 3% decline in sales of our thermal casino printers mainly due to fewer new casino openings during 2013 compared to 2012. 
+International casino and gaming product sales decreased due primarily to a 38% decrease in sales of our off-premise thermal gaming printers mainly from a 35% decrease in sales to our European distributor and a 35% decrease in sales to our customers in Australia and Asia. Sales of our off-premise gaming printers are largely project-oriented, and we therefore cannot predict the level of future sales. Additionally, sales of our thermal casino printers decreased by 12% primarily from 20% lower sales to our European distributor. This decline in sales of our thermal casino printers resulted primarily from fewer installations of VLT gaming machines in Italy as the government approved rollout of these games was substantially completed during 2012, and we therefore shipped fewer printers in 2013. The decrease in thermal casino printers was partially offset by higher international EPICENTRAL TM software sales in 2013. 
+Lottery: Revenue from the lottery market includes sales of thermal on-line and other lottery printers to GTECH and its subsidiaries for various lottery applications. A summary of sales of our worldwide lottery printers for the years ended December 31, 2013 and 2012 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Domestic 
+$ 
+4,417 
+99.3% 
+$ 
+10,574 
+90.9% 
+$ 
+(6,157) 
+(58.2%) 
+International 
+33 
+0.7% 
+1,060 
+9.1% 
+(1,027) 
+(96.9%) 
+$ 
+4,450 
+100.0% 
+$ 
+11,634 
+100.0% 
+$ 
+(7,184) 
+(61.8%) 
+15 
+Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year and are not indicative of GTECH’s overall business or revenue. However, sales for 2012 were unusually high as GTECH made a final purchase for an older generation lottery printer that we discontinued production for at the end of 2012. Based on our backlog of orders and customer’s forecast, we expect total sales to GTECH for 2014 to be approximately $4 to $5 million. 
+Printrex: Printrex branded printers are sold into markets that include wide format, rack mounted and vehicle mounted black/white and color thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. It also includes high-speed color inkjet desktop printers used to print logs at data centers of the oil and gas field service companies. Revenue in this market also includes sales of wide format printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. A summary of sales of our worldwide Printrex printers for the years ended December 31, 2013 and 2012 is as follows (in thousands, except percentages): 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Domestic 
+$ 
+3,712 
+85.6% 
+$ 
+3,915 
+83.8% 
+$ 
+(203) 
+(5.2%) 
+International 
+623 
+14.4% 
+758 
+16.2% 
+(135) 
+(17.8%) 
+$ 
+4,335 
+100.0% 
+$ 
+4,673 
+100.0% 
+$ 
+(338) 
+(7.2%) 
+The decrease in Printrex printers is primarily due to lower sales of black and white printers in the oil and gas market, partially offset by higher sales of our two new color printers, the Printrex® 920 and Printrex® 980, into the worldwide oil and gas market. 
+TSG : Revenue from TSG includes sales of consumable products (inkjet cartridges, ribbons, receipt paper, color thermal paper and other printing supplies), replacement parts, maintenance and repair services, testing services, refurbished printers, and shipping and handling charges. A summary of sales in our worldwide TSG market for the years ended December 31, 2013 and 2012 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2013 
+December 31, 2012 
+$ 
+% 
+Domestic 
+$ 
+11,925 
+93.5% 
+$ 
+12,284 
+91.2% 
+$ 
+(359) 
+(2.9%) 
+International 
+835 
+6.5% 
+1,182 
+8.8% 
+(347) 
+(29.4%) 
+$ 
+12,760 
+100.0% 
+$ 
+13,466 
+100.0% 
+$ 
+(706) 
+(5.2%) 
+The decrease in domestic revenue from TSG is primarily due to a 25% decrease in sales of consumables, largely HP inkjet cartridges, as we continue to deemphasize this commoditized consumable product. As a result, we expect sales of HP inkjet cartridges to continue to decline in 2014. In addition, paper testing service revenue declined by 38% as we performed fewer tests in 2013 than in 2012. These decreases were partially offset by a 45% increase in sales of replacement parts as well as first year sales contributions from consumables for our new Printrex color printers. Internationally, TSG revenue decreased due primarily to lower sales of replacement parts and accessories as compared to 2012. We expect TSG sales in 2014 to be lower than in 2013, as we expect lower HP inkjet cartridges partially offset by higher expected sales of consumables from our newly launched Printrex color oil and gas printers. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+25,092 
+$ 
+25,982 
+(3.4%) 
+41.7% 
+38.0% 
+Gross profit is measured as revenue less cost of sales, which includes primarily the cost of all raw materials and component parts, direct labor, manufacturing overhead expenses, cost of finished products purchased directly from our contract manufacturers and expenses associated with installations and maintenance of EPICENTRAL®. Gross profit decreased $890,000, or 3%, while gross margin improved 370 basis points as we continued to transition of business towards a more favorable sales mix of new value-added products. During 2013 our gross margin primarily benefited from sales contributions from our Ithaca® 9700 food safety terminals in addition to significantly higher EPICENTRAL™ software sales combined with lower lottery printer sales. We expect our gross margin for 2014 to continue to increase as we expect to continue to benefit from increased sales of our new, value-added products. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+4,065 
+$ 
+4,239 
+(4.1%) 
+6.8% 
+6.2% 
+Engineering, design and product development expenses primarily include salary and payroll related expenses for our engineering staff, depreciation and design expenses (including prototype printer expenses, outside design and testing services, and supplies). Such expenses decreased $174,000, or 4%, due primarily to lower outside testing and pre-production expenses related to new product development from the four new products we launched in 2012. We expect engineering, design and product development expenses in 2014 to be slightly higher than in 2013 as we plan to launch three new products during 2014. 
+16 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+7,346 
+$ 
+6,637 
+10.7% 
+12.2% 
+9.7% 
+Selling and marketing expenses primarily include salaries and payroll related expenses for our sales and marketing staff, sales commissions, travel expenses, expenses associated with the lease of sales offices, advertising, trade show expenses, e-commerce and other promotional marketing expenses. Such expenses increased $709,000, or 11%, primarily due to the addition of new sales staff and increased marketing spend to support our newly launched products. We expect selling and marketing expenses to be higher in 2014 than in 2013 primarily due to planned expansion of our sales staff and higher trade show and promotional marketing expenses as we further focus our selling and marketing efforts on our newly launched, value-added products in 2014. 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+6,588 
+$ 
+7,833 
+(15.9%) 
+11.0% 
+11.5% 
+General and administrative expenses primarily include salaries and payroll related expenses for our executive, accounting, human resource, business development and information technology staff, expenses for our corporate headquarters, professional and legal expenses, telecommunication expenses, and other expenses related to being a publicly-traded company. General and administrative expenses decreased $1,245,000, or 16%, due primarily to a reduction in the accrued contingent consideration liability to be paid in connection with the acquisition of Printrex of $900,000 (as discussed in more detail in Note 3 to the Consolidated Financial Statements) in addition to lower incentive compensation-related expenses for executive and administrative employees. These decreases were partially offset by higher recruitment fees of $160,000 due to the additional sales and engineering staff as previously discussed, as compared to 2012. We expect general and administrative expenses in 2014 to be relatively consistent with 2013, after excluding the $900,000 reduction in the Printrex accrued contingent consideration liability. 
+Legal Fees Associated with Lawsuit . Legal fee information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+476 
+$ 
+1,533 
+(68.9%) 
+0.8% 
+2.2% 
+As disclosed in Note 11 to the Consolidated Financial Statements, in June 2012, Avery Dennison Corporation (“AD”) filed a civil complaint against the Company. In connection with this lawsuit, we incurred legal fees and other related expenses of $476,000 and $1,533,000 in 2013 and 2012, respectively. As a result of AD’s actions, we may incur additional legal fees related to this lawsuit in 2014 and beyond, although we cannot predict the timing and extent of such legal fees. 
+Business Consolidation and Restructuring. Business consolidation and restructuring information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+- 
+$ 
+138 
+(100.0%) 
+-% 
+0.2% 
+As disclosed in Note 8 to the Consolidated Financial Statements, in January 2012, we determined that we no longer needed to maintain the existing Printrex manufacturing facility in San Jose, California, along with certain redundant headcount. During 2012, we recorded a restructuring charge of $138,000 for employee termination benefits related to these employee reductions as well as moving costs. The closing of the San Jose manufacturing operations was completed as of December 31, 2012. We did not incur any restructuring charges during 2013. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2013 
+2012 
+Change 
+Total Sales - 2013 
+Total Sales - 2012 
+Year ended 
+$ 
+6,617 
+$ 
+5,602 
+18.1% 
+11.0% 
+8.2% 
+The increase in our operating income and operating margin was primarily due to the 370 basis point improvement in gross margin in 2013 as compared to 2012 as well as to lower legal fees incurred from the AD lawsuit as previously discussed. In addition, our operating margin for 2013 benefited by 150 basis points from the $900,000 reduction in the Printrex accrued contingent consideration liability. 
+Interest. We recorded net interest expense of $23,000 in 2013 compared to net interest income of $6,000 in 2012. The decrease in net interest income is primarily due to lower interest income earned on a lower average cash balance, as we used a significant amount of our cash (approximately $7,511,000) to repurchase our common stock and pay cash dividends in 2013. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2013 and 2012. See “Liquidity and Capital Resources” below for more information. 
+17 
+Other, net. We recorded other expense of $63,000 in 2013 compared to $23,000 in 2012. The change was primarily due to a loss from the disposal of certain tooling equipment during 2013 of $60,000 offset by lower foreign currency transaction exchange losses recorded by our U.K. subsidiary in 2013 compared to 2012. 
+Income Taxes. We recorded an income tax provision for 2013 of $1,596,000 at an effective tax rate of 24.4% compared to $1,964,000 at an effective tax rate of 35.2% for 2012. Our effective tax rate for 2013 is unusually low because it includes: 1) a $224,000 reduction in tax liabilities for unrecognized tax benefits resulting from the completion of an audit of our 2010 federal income tax return and 2) the benefit from the 2012 R&D credit of approximately $220,000 as this credit was not renewed until January 2, 2013 as a component of the American Taxpayer Relief Act of 2012. We expect our annual effective tax rate for 2014 to be between 32% and 33%. 
+Net Income . We reported net income during 2013 of $4,935,000, or $0.57, per diluted share, compared to $3,621,000, or $0.40, per diluted share, for 2012. 
+Results of Operations: Year ended December 31, 2012 compared to year ended December 31, 2011 
+Net Sales. Net sales, which include printer, terminal and software sales and as well as sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2012 and 2011 were as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2012 
+December 31, 2011 
+$ 
+% 
+Food safety, banking and POS 
+$ 
+9,484 
+13.9% 
+$ 
+9,943 
+15.1% 
+$ 
+(459) 
+(4.6%) 
+Casino and gaming 
+29,129 
+42.6% 
+24,955 
+37.8% 
+4,174 
+16.7% 
+Lottery 
+11,634 
+17.0% 
+14,933 
+22.6% 
+(3,299) 
+(22.1%) 
+Printrex 
+4,673 
+6.8% 
+1,710 
+2.6% 
+2,963 
+173.3% 
+TSG 
+13,466 
+19.7% 
+14,428 
+21.9% 
+(962) 
+(6.7%) 
+$ 
+68,386 
+100.0% 
+$ 
+65,969 
+100.0% 
+$ 
+2,417 
+3.7% 
+International* 
+$ 
+18,454 
+27.0% 
+$ 
+16,668 
+25.3% 
+$ 
+1,786 
+10.7% 
+* International sales do not include sales of printers made to domestic distributors or other customers who in turn ship those printers to international destinations. 
+Net sales for 2012 increased $2,417,000, or 4%, from 2011. Printer and terminal sales volume decreased 1% to approximately 199,000 units as a 26% decline in lottery printer unit volume was almost entirely offset by an 18% increase in unit volume from the casino and gaming market. The average selling price of our printers and terminals increased approximately 7% from 2011 to 2012 due primarily to higher sales of casino and gaming printers as well as our first full year of sales of Printrex printers, both of which have significantly higher average selling prices than all our other printers. Overall, international sales increased $1,786,000, or 11%, primarily driven by higher sales in both the international casino and gaming and lottery markets. 
+Food safety, banking and POS : A summary of sales of our worldwide food safety, banking and POS products for the years ended December 31, 2012 and 2011 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2012 
+December 31, 2011 
+$ 
+% 
+Domestic 
+$ 
+8,876 
+93.6% 
+$ 
+8,968 
+90.2% 
+$ 
+(92) 
+(1.0%) 
+International 
+608 
+6.4% 
+975 
+9.8% 
+(367) 
+(37.6%) 
+$ 
+9,484 
+100.0% 
+$ 
+9,943 
+100.0% 
+$ 
+(459) 
+(4.6%) 
+The decrease in domestic food safety, banking and POS printer revenue from 2011 was primarily driven by a decrease in U.S. sales of our two POS printer products to McDonald’s, the Ithaca® 8000 and Ithaca® 8040, for its combined beverage initiative and its POS system upgrade which includes grill initiative printer upgrades, as the U.S. rollout of printers for these initiatives was substantially completed. However, beginning in the second half of 2012, we began to ship Ithaca 8000® printers to McDonald’s for a new application. This decrease in sales was largely offset by higher sales of our banking printers mainly due to sales from a large order for our Ithaca® 280 thermal receipt printer to a new banking customer which we completed shipments to in the third quarter of 2012. Sales for 2012 also benefited from the first revenue contributions from our newly launched Ithaca® 9700 food service terminal. 
+International banking and POS printer sales for 2012 decreased 38% from 2011 due primarily to lower sales for the aforementioned McDonald’s POS system upgrade and grill initiative as well as the combined beverage initiative to its Canadian stores in 2012 compared to 2011. 
+Casino and gaming : A summary of sales of our worldwide casino and gaming printers and Epicentral software for the years ended December 31, 2012 and 2011 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2012 
+December 31, 2011 
+$ 
+% 
+Domestic 
+$ 
+14,283 
+49.0% 
+$ 
+11,007 
+44.1% 
+$ 
+3,276 
+29.8% 
+International 
+14,846 
+51.0% 
+13,948 
+55.9% 
+898 
+6.4% 
+$ 
+29,129 
+100.0% 
+$ 
+24,955 
+100.0% 
+$ 
+4,174 
+16.7% 
+18 
+The increase in domestic sales of our casino and gaming products is primarily due to an increase of 31% in sales of our thermal casino printers. We believe that our increased casino printer sales during 2012 resulted from a combination of new casino openings and continued market share gains. Revenue in 2012 also benefited from the first contribution of EPICENTRAL TM software sales. 
+International casino and gaming printer sales increased due primarily to a 14% increase in thermal casino printer sales during 2012 primarily driven by a 100% increase in sales to a Canadian OEM as well as 9% higher sales to our European distributor. Sales of our off-premise thermal gaming printers decreased 10% in 2012 compared to 2011 due largely to a 47% decrease in sales to distribution and an OEM customer in Australia and Asia as well as a 77% decrease in sales to a Canadian OEM. These decreases were somewhat offset by 29% higher sales of off-premise printers to our European distributor. 
+Lottery: A summary of sales of our worldwide lottery printers for the years ended December 31, 2012 and 2011 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2012 
+December 31, 2011 
+$ 
+% 
+Domestic 
+$ 
+10,574 
+90.9% 
+$ 
+14,557 
+97.5% 
+$ 
+(3,983) 
+(27.4%) 
+International 
+1,060 
+9.1% 
+376 
+2.5% 
+684 
+181.9% 
+$ 
+11,634 
+100.0% 
+$ 
+14,933 
+100.0% 
+$ 
+(3,299) 
+(22.1%) 
+Our sales to GTECH are directly dependent on the timing and number of new and upgraded lottery terminal installations GTECH performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year and are not indicative of GTECH’s overall business or revenue. 
+Printrex: A summary of sales of our worldwide Printrex printers for the years ended December 31, 2012 and 2011 is as follows (in thousands, except percentages): 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2012 
+December 31, 2011 
+$ 
+% 
+Domestic 
+$ 
+3,915 
+83.8% 
+$ 
+1,391 
+81.3% 
+$ 
+2,524 
+181.4% 
+International 
+758 
+16.2% 
+319 
+18.7% 
+439 
+137.6% 
+$ 
+4,673 
+100.0% 
+$ 
+1,710 
+100.0% 
+$ 
+2,963 
+173.3% 
+The increase in sales is primarily due to a full twelve months of sales being reported in 2012 as compared to approximately four and one-half months of sales in 2011 as we acquired Printrex on August 19, 2011. 
+TSG : A summary of sales in our worldwide TSG market for the years ended December 31, 2012 and 2011 is as follows: 
+Year ended 
+Year ended 
+Change 
+(In thousands) 
+December 31, 2012 
+December 31, 2011 
+$ 
+% 
+Domestic 
+$ 
+12,284 
+91.2% 
+$ 
+13,378 
+92.7% 
+$ 
+(1,094) 
+(8.2%) 
+International 
+1,182 
+8.8% 
+1,050 
+7.3% 
+132 
+12.6% 
+$ 
+13,466 
+100.0% 
+$ 
+14,428 
+100.0% 
+$ 
+(962) 
+(6.7%) 
+The decrease in domestic revenue from TSG is primarily due to a 19% decrease in sales of consumables from the effect of a loss of sales to two OEM customers partially offset by an increase in service revenue of approximately $582,000 during 2012 from several new contracts for paper testing services that did not occur in 2011. Additionally, Printrex TSG sales increased by approximately $272,000 to reflect a full twelve months of sales being reported in 2012 as compared to approximately four and one-half months of sales in 2011. Internationally, TSG revenue increased due primarily to higher sales of replacement parts as compared to 2011. 
+Gross Profit. Gross profit information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+25,982 
+$ 
+24,626 
+5.5% 
+38.0% 
+37.3% 
+Gross profit increased $1,356,000, or 6%, and gross margin improved 70 basis points due primarily to a favorable sales mix as we sold more higher margin casino and gaming and Printrex printers, and fewer lower margin lottery printers in 2012 compared to 2011. 
+Engineering, Design and Product Development. Engineering, design and product development information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+4,239 
+$ 
+3,418 
+24.0% 
+6.2% 
+5.2% 
+Such expenses increased $821,000, or 24%, due primarily to the full twelve months effect of the addition of engineering staff and related expenses from the acquisition of Printrex of approximately $657,000, and higher outside testing and prototype expenses related to new product development from the four new products we launched in the fourth quarter of 2012. 
+19 
+Selling and Marketing. Selling and marketing information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+6,637 
+$ 
+6,402 
+3.7% 
+9.7% 
+9.7% 
+Such expenses increased $235,000, or 4%, primarily due to higher expenses from the full twelve months effect from the acquisition of Printrex of approximately $365,000, including the addition of new sales staff, partially offset by lower promotional marketing expenses in 2012 as compared to 2011. 
+General and Administrative. General and administrative information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+7,833 
+$ 
+7,633 
+2.6% 
+11.5% 
+11.6% 
+General and administrative expenses increased $200,000, or 3%, due primarily to an increase in accrued contingent consideration of $280,000 (as discussed in more detail in Note 3 to the Consolidated Financial Statements) and higher amortization of intangible assets of $227,000, both in connection with the acquisition of Printrex. These increases were partially offset by lower recruitment fees of $175,000 as compared to 2011. 
+Legal Fees Associated with Lawsuit . Legal fee information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+1,533 
+$ 
+- 
+100.0% 
+2.2% 
+-% 
+As disclosed in Note 11 to the Consolidated Financial Statements, in June 2012, Avery Dennison Corporation (“AD”) filed a civil complaint against the Company. In connection with this lawsuit, we incurred legal fees and other related expenses of $1,533,000 in 2012. 
+Business Consolidation and Restructuring. Business consolidation and restructuring information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+138 
+$ 
+184 
+(25.0%) 
+0.2% 
+0.3% 
+As disclosed in Note 8 to the Consolidated Financial Statements, in January 2012, we determined that we no longer needed to maintain the existing Printrex manufacturing facility in San Jose, California, along with certain redundant headcount. During 2012, we recorded a restructuring charge of $138,000 for employee termination benefits related to these employee reductions as well as moving costs. The closing of the San Jose manufacturing operations was completed as of December 31, 2012. 
+In May 2011, we undertook a plan to close our New Britain, CT service facility. The New Britain facility primarily serviced our first generation legacy impact printers for GTECH. We no longer needed to maintain this facility since these printers were replaced by our thermal lottery printers. During 2011, we recorded a restructuring charge of $184,000 in connection with this facility closure. As of June 30, 2011, all New Britain activities ceased. Please also refer to Note 8 in the Consolidated Financial Statements. 
+Operating Income. Operating income information is summarized below (in thousands, except percentages): 
+December 31, 
+Percent 
+Percent of 
+Percent of 
+2012 
+2011 
+Change 
+Total Sales - 2012 
+Total Sales - 2011 
+Year ended 
+$ 
+5,602 
+$ 
+6,989 
+(19.8%) 
+8.2% 
+10.6% 
+The decrease in our operating income and operating margin was primarily due to the legal fees incurred from the AD lawsuit and higher operating expenses attributable to the Printrex acquisition of approximately $1,145,000 which were partially offset by higher gross profit as previously discussed. 
+Interest. We recorded net interest income of $6,000 in 2012 compared to net interest income of $18,000 in 2011. The decrease in net interest income is primarily due to lower interest income earned on a lower average cash balance, as we used a significant amount of our cash (approximately $6,464,000) to repurchase our common stock and pay cash dividends in 2012. Interest expense related to the unused revolving credit line fee and amortization of deferred financing costs on our revolving credit facility with TD Bank remained consistent in 2012 and 2011. See “Liquidity and Capital Resources” below for more information. 
+Other, net. We recorded other expense of $23,000 in 2012 compared to other income of $1,000 in 2011. The change from 2011 was primarily due to foreign currency transaction exchange losses recorded by our U.K. subsidiary in 2012 compared to a small gain in 2011. 
+20 
+Income Taxes. We recorded an income tax provision for 2012 of $1,964,000 at an effective tax rate of 35.2% compared to $2,332,000 at an effective tax rate of 33.3% for 2011. The effective tax rate for 2012 is higher because it does not include a benefit from the federal R&D credit, which is normally included in our tax rate, as this credit expired at the end of 2011 and was not renewed until January 2, 2013 as a component of the Act. Since the Act was not signed until 2013, the cumulative 2012 impact of the R&D credit was \reflected as a discrete item in the first quarter of 2013. Had the R&D credit been included in our effective tax rate for 2012, it would have lowered our income tax provision and effective tax rate, by approximately $220,000 and 400 basis points, respectively. 
+Net Income . We reported net income during 2012 of $3,621,000, or $0.40, per diluted share, compared to $4,676,000, or $0.49, per diluted share, for 2011. 
+Liquidity and Capital Resources 
+We assess our liquidity in terms of our ability to generate cash to fund our operating, investing and financing activities. Significant factors affecting the management of liquidity are cash flows from operating activities, capital expenditures, treasury share repurchases, dividend payments, access to bank lines of credit and our ability to attract long-term capital with satisfactory terms. 
+Internal cash generation together with currently available cash and cash equivalents, available borrowing facilities and an ability to access credit lines, if needed, are expected to be sufficient to fund operations, capital expenditures, treasury share repurchases, dividend payments and any increase in working capital that would be required to accommodate a higher level of business activity. We actively seek to expand by acquisition as well as through the growth of our current business. While a significant acquisition may require additional debt and/or equity financing, although no assurances can be given, we believe that we would be able to obtain additional financing based on our historical earnings performance. 
+Cash Flow 
+During 2013, our cash balance decreased $4,601,000, or 61%, from December 31, 2012 as we used a substantial portion of our cash flow to return to shareholders in the form of $5,194,000 of repurchases of our common stock and $2,317,000 of cash dividends paid to our common shareholders. Even after funding these items and our capital expenditures, we still ended 2013 with $2,936,000 in cash and cash equivalents and no debt outstanding. 
+Operating activities : The following significant factors primarily affected our cash provided by operating activities of $2,493,000 in 2013 as compared to $8,030,000 in 2012. During 2013: 
+· 
+We reported net income of $4,935,000. 
+· 
+We recorded depreciation, amortization and share-based compensation expense of $2,262,000, including $311,000 of amortization related to intangible assets acquired from Printrex. 
+· 
+Accounts receivable decreased $2,685,000 due primarily to significantly lower sales volume during the fourth quarter of 2013 compared to the fourth quarter of 2012. 
+· 
+Inventories increased $3,189,000 as we increased stocking levels of our new food safety and Printrex products during 2013 in anticipation of higher expected sales volume. We expect our inventories to gradually decrease during 2014 as we sell through this inventory buildup. 
+· 
+Accounts payable decreased $1,674,000 due to primarily to lower inventory purchases made during the fourth quarter of 2013 compared to the fourth quarter of 2012, as well as the timing of payments. 
+· 
+Accrued liabilities and other liabilities decreased $2,156,000 due primarily to a decrease in our estimate of accrued contingent consideration associated with the acquisition of Printrex of $900,000 during 2013 based on our revised estimate of the expected payout. Additionally, income taxes payable decreased by approximately $603,000 resulting from the overpayment of our 2013 tax liability. Correspondingly, we recorded prepaid income taxes of $390,000. 
+During 2012: 
+· 
+We reported net income of $3,621,000. 
+· 
+We recorded depreciation, amortization and share-based compensation expense of $2,278,000, including $366,000 of amortization related to intangible assets acquired from Printrex. 
+· 
+Accounts receivable increased $6,332,000 due primarily to significantly higher sales volume during the fourth quarter of 2012 compared to the fourth quarter of 2011. 
+· 
+Inventories decreased $3,684,000 due primarily to a focused effort at inventory management through a reduction in inventory purchases and sales fulfillment through existing inventory stock throughout 2012. 
+· 
+Accounts payable increased $3,403,000 due to primarily to higher inventory purchases made during the fourth quarter 2012 to support significantly higher sales volume compared to the fourth quarter of 2011. 
+· 
+Accrued liabilities and other liabilities increased $1,182,000 due primarily to an increase in income taxes payable of approximately $589,000 resulting from a higher level of income before income taxes in the fourth quarter 2012 compared to 2011. Additionally, we increased our estimate of accrued contingent consideration associated with the acquisition of Printrex by $280,000 during 2012 based on our revised estimate of the expected payout. 
+Investing activities: Our capital expenditures were $709,000 and $1,082,000 in 2013 and 2012, respectively. Expenditures in 2013 included approximately $89,000 for costs incurred in connection with an upgrade to the Company’s ERP software and the remaining amount primarily for the purchase of new product tooling and computer equipment. Expenditures in 2012 included $490,000 for the purchase of new product tooling with the remaining amount primarily for the purchase of computer hardware and software and manufacturing equipment. Additionally, our capitalized software development costs for EPICENTRAL™ were $42,000 and $35,000 in 2013 and 2012, respectively. 
+21 
+Capital expenditures for 2014 are expected to be approximately $1,000,000, primarily for new product tooling, and tooling enhancements for our existing products, as well as for new computer equipment purchases. 
+Financing activities: We used $6,334,000 of cash from financing activities during 2013 to purchase $5,194,000 of common stock for treasury and to pay cash dividends of $2,317,000 to common shareholders partially offset by proceeds and tax benefits from stock option exercises of $1,177,000. During 2012, we used $6,242,000 of cash from financing activities to purchase $5,938,000 of common stock for treasury and $526,000 to make our first ever cash dividend payment, partially offset by $229,000 of proceeds and incremental tax benefits from stock option exercises. 
+Working Capital 
+Our working capital decreased approximately 2% to $24,871,000 at December 31, 2013 from $25,492,000 at December 31, 2012. Our current ratio of current assets to current liabilities increased to 4.4 at December 31, 2013, compared to 3.5 at December 31, 2012. The decrease in our working capital was primarily due to lower cash and cash equivalent balances of $4,601,000 resulting from the significant treasury share repurchases and cash dividend payments previously discussed, as well as higher inventories and lower accounts payable balances, partially offset by lower accounts receivable. The increase in our current ratio was primarily due to lower accounts payable and accrued liabilities balances primarily resulting from reduced inventory purchases and the timing of payments in the fourth quarter of 2013 as compared to 2012 in addition to higher inventory balances. These were partially offset by lower accounts receivable and cash and cash equivalents balances in 2013 compared to 2012. 
+Resource Sufficiency 
+We believe that our cash and cash equivalents on hand and cash flows generated from operating activities will provide sufficient resources to meet our working capital needs, finance our capital expenditures, treasury stock repurchases, dividend payments and meet our liquidity requirements through at least the next twelve months. 
+Credit Facility and Borrowings 
+We maintain a credit facility (the “TD Bank Credit Facility”) with TD Bank which provides for a $20,000,000 revolving credit line that expires on November 28, 2014. Borrowings under the TD Bank Credit Facility bear a floating rate of interest at the prime rate minus one percent and are secured by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the TD Bank Credit Facility. We expect to renew our credit facility with TD Bank or replace it with a similar credit facility from another financial institution during 2014. 
+On September 7, 2012, we signed an amendment to the TD Bank Credit Facility that allows us to declare and pay cash dividends to holders of our outstanding common shares subject to approval by our Board of Directors and provided that no default or event of default has occurred and is continuing under the credit facility on the date of the dividend payment. The amendment also allows us to use up to $5,000,000 in revolving credit loans to fund future cash dividend payments or treasury share buybacks as well as requires cash dividend payments to be treated as distributions for purposes of quarterly debt covenant calculations. 
+The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur additional indebtedness and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2013. The following table lists the financial covenants and the performance measurements at December 31, 2013: 
+Financial Covenant 
+Requirement/Restriction 
+Calculation at December 31, 2013 
+Operating cash flow / Total debt service 
+Minimum of 1.25 times 
+60.4 times 
+Funded debt / EBITDA 
+Maximum of 3.0 times 
+0 times 
+As of December 31, 2013, undrawn commitments under the TD Bank Credit facility were $20,000,000. 
+Shareholder Dividend Payments 
+On September 10, 2012, we announced that our Board of Directors approved the initiation of a quarterly cash dividend program which is subject to the Board’s approval each quarter. On May 2, 2013, our Board of Directors declared an increase to the quarterly cash dividend from $0.06 per share to $0.07 per share. Dividends declared and paid on our common stock totaled $2,317,000, or $0.27 per share, and $526,000, or $0.06 per share, in 2013 and 2012, respectively. On February 4, 2014, our Board of Directors approved the first quarter 2014 dividend in the amount of $0.07 per share payable on or about March 14, 2014 to common shareholders of record at the close of business on February 20, 2014. We expect to pay approximately $2,400,000 in cash dividends to our common shareholders during 2014. 
+Stock Repurchase Program 
+Prior to its expiration on May 27, 2013, we maintained the Stock Repurchase Program whereby we were authorized to repurchase up to $15,000,000, as increased from $10,000,000 in March 2012, of our outstanding shares of common stock from time to time in the open market, depending on market conditions, share price and other factors. The Stock Repurchase Program expired on May 27, 2013 and was not renewed. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the settlement date. From January 1, 2013 through the expiration date of the Stock Repurchase Program, we repurchased 114,161 shares of our common stock for approximately $887,000 at an average price per share of $7.77. In addition to shares repurchased under the Stock Repurchase Program, during the year ended December 31, 2013, we repurchased 490,000 shares of our common stock for approximately $4,307,000 at an average price per share of $8.79 in an open-market transaction. From January 1, 2005 through December 31, 2013, we repurchased a total of 2,787,038 shares of common stock for approximately $22,527,000, at an average price of $8.08 per share. As of December 31, 2013, no additional shares are authorized for future repurchases due to the expiration of the Stock Repurchase Program. The following table summarizes the repurchase of our common stock for the year ended December 31, 2013: 
+22 
+Period 
+Total Number of Shares Purchased 
+Average Price Paid per Share 
+Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs 
+Approximate Dollar Value of Shares that May Yet Be Purchased under the May 2010 Program 
+January 1, 2013 – January 31, 2013 
+45,177 
+$ 
+7.59 
+45,177 
+$ 
+5,863,000 
+February 1, 2013 – February 28, 2013 
+23,339 
+8.06 
+23,339 
+$ 
+5,675,000 
+March 1, 2013 – March 31, 2013 
+20,384 
+7.89 
+20,384 
+$ 
+5,514,000 
+April 1, 2013 – April 30, 2013 
+22,494 
+7.75 
+22,494 
+$ 
+5,340,000 
+May 1, 2013 – May 31, 2013 
+2,767 
+7.48 
+2,767 
+-* 
+June 1, 2013 – June 30, 2013 
+- 
+- 
+- 
+-* 
+July 1, 2013 – July 31, 2013 
+- 
+- 
+- 
+-* 
+August 1, 2013 – August 31, 2013 
+490,000 
+8.79 
+- 
+-* 
+September 1, 2013 – September 30, 2013 
+- 
+- 
+- 
+-* 
+October 1, 2013 – October 31, 2013 
+- 
+- 
+- 
+-* 
+November 1, 2013 – November 30, 2013 
+- 
+- 
+- 
+-* 
+December 1, 2013 – December 31, 2013 
+- 
+- 
+- 
+-* 
+Total 
+604,161 
+$ 
+8.60 
+114,161 
+* - Stock Repurchase Program expired on May 27, 2013 and was not renewed. 
+Shareholders’ Equity 
+Shareholders’ equity decreased $848,000 to $32,521,000 at December 31, 2013 from $33,369,000 at December 31, 2012. The decrease was primarily due to our purchase of 604,161 shares of treasury stock for $5,194,000 and dividend payments of $2,317,000. These decreases were partially offset by net income of $4,935,000, proceeds and the associated incremental tax benefits of approximately $1,177,000 from the issuance of 196,358 shares of common stock from stock option exercises, share-based compensation expense related to stock options of $521,000 and approximately $111,000 from the issuance of 6,919 shares of deferred stock units, net of relinquishments. 
+Contractual Obligations 
+Our contractual obligations as of December 31, 2013 were as follows: 
+Payments due by period 
+(In thousands) 
+Total 
+< 1 year 
+1-3 years 
+3-5 years 
+> 5 years 
+Operating lease obligations 
+$ 
+2,294 
+$ 
+832 
+$ 
+1,384 
+$ 
+78 
+$ 
+- 
+Purchase obligations 
+9,025 
+8,820 
+205 
+- 
+- 
+Accrued contingent consideration 
+60 
+60 
+- 
+- 
+- 
+Total 
+$ 
+11,379 
+$ 
+9,712 
+$ 
+1,589 
+$ 
+78 
+$ 
+- 
+Purchase obligations are for purchases made in the normal course of business to meet operational requirements, primarily of fully assembled printers and component part inventory. Accrued contingent consideration consists of potential future obligations for performance-based cash payments in connection with the Printrex acquisition. 
+Impact of Inflation 
+We believe that our business has not been affected to a significant degree by inflationary trends during the past three years. However, inflation is still a factor in the worldwide economy and may increase the cost of purchasing products from our contract manufacturers in Asia, as well as the cost of certain raw materials, component parts and labor used in the production of our products. It also may increase our operating expenses, manufacturing overhead expenses and the cost to acquire or replace fixed assets. Despite continued growing costs of oil, gas and freight, we have generally been able to maintain or improve our profit margins through productivity and efficiency improvements, cost reduction programs and to a lesser extent, price increases, and we expect to be able to do the same during 2014. As such, we do not believe that inflation will have a significant impact on our business during 2014. 
+Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 
+Interest Rate Risk 
+Our exposure to market risk for changes in interest rates relates primarily to the investment of our available cash and cash equivalents. In accordance with our investment policy, we strive to achieve above market rates of return in exchange for accepting a prudent amount of incremental risk, which includes the risk of interest rate movements. Risk tolerance is constrained by an overriding objective to preserve capital. An increase or decrease of 10% in effective interest rates would not have a material effect on our results of operations or cash flows. 
+Foreign Currency Exchange Risk 
+A substantial portion of our sales are denominated in U.S. dollars and, as a result, we have relatively little exposure to foreign currency exchange risk with respect to sales made. This exposure may change over time as business practices evolve and could have a material adverse impact on our financial results in the future. We do not use forward exchange contracts to hedge exposures denominated in foreign currencies or any other derivative financial instruments for trading or speculative purposes. We estimate that the combined translational and transactional impact of a 10% overall movement in exchange rates from December 31, 2013 (principally the U.K. Pound Sterling) would not have a material impact on our results of operations or cash flows. 
+23 
+Item 8. Financial Statements and Supplementary Data. 
+The financial statements of the Company are annexed to this report as pages F-3 through F-19. An index to such materials appears on page F-1. 
+Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 
+None. 
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2013, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2013. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Annual Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2013. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“1992 COSO”). Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2013 
+The effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. 
+Item 9B. Other Information. 
+Not applicable. 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance. 
+Set forth below is certain information regarding our executive officers. The remaining information in response to this item will be contained in our Proxy Statement for our 2014 Annual Meeting of Stockholders (the “Proxy Statement”), which will be filed within 120 days after the year covered by this Form 10-K and is incorporated herein by reference. 
+Executive Officers of the Registrant 
+The following list is included as an unnumbered item in Part III of this Report in lieu of being included in the Proxy Statement for the Annual Meeting of Stockholders to be held on May 15, 2014. 
+The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. 
+Name 
+Age 
+Position 
+Bart C. Shuldman 
+56 
+Chairman of the Board and Chief Executive Officer 
+Steven A. DeMartino 
+44 
+President, Chief Financial Officer, Treasurer and Secretary 
+Donald E. Brooks 
+61 
+Senior Vice President-Engineering 
+Tracey S. Chernay 
+54 
+Executive Vice President, Casino and Gaming Sales and Marketing 
+Andrew J. Hoffman 
+56 
+Senior Vice President-Operations 
+Benjamin C. Wyatt 
+40 
+Vice President-Software Products and Business Development 
+Bart C. Shuldman has been Chief Executive Officer, President and a Director of the Company since its formation in June 1996. In February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman relinquished the President title, effective June 1, 2010, to focus on new products and markets, international expansion and potential acquisitions. 
+Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. 
+24 
+Donald E. Brooks was appointed Senior Vice President of Engineering in April 2012. Previously, Mr. Brooks served as Vice President, Engineering from September 2004 to April 2012, Senior Project Engineer from February 1998 to September 2004, Project Engineer from June 1997 to February 1998, Director of Electrical Engineering from March 1986 to June 1997 and Manager of Electronic Development from December 1983 to March 1986. 
+Tracey S. Chernay was appointed Executive Vice President, Casino and Gaming Sales and Marketing in June 2010, with responsibility for the sales and marketing of all casino and gaming products. Previously, Ms. Chernay served as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Seniorr Vice President, Marketing & Sales, POS & Banking with the Company from July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. 
+Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice President, Operations from September 1994 to November 2004. 
+Benjamin C. Wyatt was appointed Vice President, Software Products and Business Development in December 2010. Previously, Mr. Wyatt served as Vice President, Business Development for TransAct from May 2008 to November 2010. Prior to joining TransAct, Mr. Wyatt was employed with Pitney Bowes Mail Services where he held the role of Director Business Development since 2006, and Manager Acquisitions and Integration from 2004 to 2006 
+Item 11. Executive Compensation. 
+The information in response to this item will be contained in the Proxy Statement and is incorporated herein by reference. 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+The information in response to this item will be contained in the Proxy Statement and is incorporated herein by reference. 
+Information regarding our equity compensation plans as of December 31, 2013 is as follows: 
+Plan category 
+(a) 
+Number of securities to be issued upon exercise of outstanding options, warrants and rights 
+(b) 
+Weighted-average exercise price of outstanding options, warrants and rights 
+(c) 
+Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a) 
+Equity compensation plans approved by security holders: 
+1996 Non-Employee Director Plan 
+22,500 
+31.82 
+- 
+2005 Equity Incentive Plan 
+746,966 
+7.73 
+195,755 
+Total 
+769,466 
+$ 
+8.43 
+195,755 
+Equity compensation plans not approved by security holders: 
+2001 Employee Stock Plan 
+1,000 
+$ 
+26.23 
+- 
+770,466 
+$ 
+8.46 
+195,755 
+The TransAct Technologies Incorporated 2001 Employee Stock Plan was adopted by our Board of Directors, without approval of our security holders, effective February 26, 2001. The Company also maintains the 2005 Equity Incentive Plan which was approved by our shareholders. The number of shares of common stock which may be subject to awards granted under the 2005 Equity Incentive Plan is 1,200,000. No new awards will be available for future issuance under any of our existing equity plans other than the 2005 Equity Incentive Plan. 
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item will be contained in the Proxy Statement and is incorporated herein by reference. 
+Item 14. Principal Accountant Fees and Services. 
+The information in response to this item will be contained in the Proxy Statement section and is incorporated herein by reference. 
+PART IV 
+Item 15. Exhibits and Financial Statement Schedules. 
+The exhibits filed as a part of this report are listed in the accompanying Index to Exhibits. 
+25 
+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. 
+TRANSACT TECHNOLOGIES INCORPORATED 
+By: 
+/s/ Bart C. Shuldman 
+Name: 
+Bart C. Shuldman 
+Title: 
+Chairman of the Board and Chief Executive Officer 
+Date: March 14, 2014 
+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/ Bart C. Shuldman 
+Chairman of the Board 
+March 14, 2014 
+Bart C. Shuldman 
+and Chief Executive Officer, 
+(Principal Executive Officer) 
+/s/ Steven A. DeMartino 
+President, Chief Financial Officer, 
+March 14, 2014 
+Steven A. DeMartino 
+Treasurer and Secretary 
+(Principal Financial and Accounting Officer) 
+/s/ John M. Dillon 
+Director 
+March 14, 2014 
+John M. Dillon 
+/s/ Thomas R. Schwarz 
+Director 
+March 14, 2014 
+Thomas R. Schwarz 
+/s/ Graham Y. Tanaka 
+Director 
+March 14, 2014 
+Graham Y. Tanaka 
+26 
+TRANSACT TECHNOLOGIES INCORPORATED 
+INDEX TO FINANCIAL STATEMENTS 
+Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Consolidated Balance Sheets as of December 31, 2013 and 2012 
+F-3 
+Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 20 11 
+F-4 
+Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 20 11 
+F-5 
+Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2013, 2012 and 20 11 
+F-6 
+Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 20 11 
+F-7 
+Notes to Consolidated Financial Statements 
+F-8 
+All other financial statement schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or notes thereto. 
+F-1 
+Report of Independent Registered Public Accounting Firm 
+To the Board of Directors and Shareholders of TransAct Technologies Incorporated: 
+In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of TransAct Technologies Incorporated and its subsidiaries at December 31, 2013 and December 31, 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. Also 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 Internal Control - Integrated Framework (1992) 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 Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements 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 
+Hartford, Connecticut 
+March 14, 2014 
+F-2 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except share data) 
+December 31, 
+December 31, 
+2013 
+2012 
+Assets: 
+Current assets: 
+Cash and cash equivalents 
+$ 
+2,936 
+$ 
+7,537 
+Accounts receivable, net 
+13,234 
+15,927 
+Inventories 
+13,509 
+10,321 
+Prepaid income taxes 
+390 
+- 
+Deferred tax assets 
+1,655 
+1,443 
+Other current assets 
+497 
+471 
+Total current assets 
+32,221 
+35,699 
+Fixed assets, net 
+2,732 
+3,302 
+Goodwill 
+2,621 
+2,621 
+Deferred tax assets 
+920 
+1,172 
+Intangible assets, net of accumulated amortization of $1,811 and $1,298, respectively 
+1,856 
+2,328 
+Other assets 
+58 
+106 
+8,187 
+9,529 
+Total assets 
+$ 
+40,408 
+$ 
+45,228 
+Liabilities and Shareholders’ Equity: 
+Current liabilities: 
+Accounts payable 
+$ 
+4,749 
+$ 
+6,422 
+Accrued liabilities 
+2,215 
+2,927 
+Income taxes payable 
+26 
+629 
+Accrued contingent consideration (Note 3) 
+60 
+136 
+Deferred revenue 
+300 
+93 
+Total current liabilities 
+7,350 
+10,207 
+Deferred revenue, net of current portion 
+103 
+168 
+Deferred rent, net of current portion 
+244 
+308 
+Accrued contingent consideration, net of current portion (Note 3) 
+- 
+824 
+Other liabilities 
+190 
+352 
+537 
+1,652 
+Total liabilities 
+7,887 
+11,859 
+Commitments and contingencies (Note 11) 
+Shareholders’ equity: 
+Preferred stock, $0.01 par value, 4,800,000 authorized, none issued and outstanding 
+- 
+- 
+Preferred stock, Series A, $0.01 par value, 200,000 authorized, none issued and outstanding 
+- 
+- 
+Common stock, $0.01 par value, 20,000,000 authorized at December 31, 2013 and 2012; 11,106,354 and 10,903,077 shares issued; 8,319,316 and 8,720,200 shares outstanding, at December 31, 2013 and 2012, respectively 
+111 
+109 
+Additional paid-in capital 
+27,674 
+25,940 
+Retained earnings 
+27,326 
+24,708 
+Accumulated other comprehensive loss, net of tax 
+(63) 
+(55) 
+Treasury stock, 2,787,038 and 2,182,877 shares, at cost 
+(22,527) 
+(17,333) 
+Total shareholders’ equity 
+32,521 
+33,369 
+Total liabilities and shareholders’ equity 
+$ 
+40,408 
+$ 
+45,228 
+See accompanying notes to Consolidated Financial Statements. 
+F-3 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF INCOME 
+(In thousands, except per share data) 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Net sales 
+$ 
+60,141 
+$ 
+68,386 
+$ 
+65,969 
+Cost of sales 
+35,049 
+42,404 
+41,343 
+Gross profit 
+25,092 
+25,982 
+24,626 
+Operating expenses: 
+Engineering, design and product development 
+4,065 
+4,239 
+3,418 
+Selling and marketing 
+7,346 
+6,637 
+6,402 
+General and administrative 
+6,588 
+7,833 
+7,633 
+Legal fees associated with lawsuit (Note 11) 
+476 
+1,533 
+- 
+Business consolidation and restructuring (Note 8) 
+- 
+138 
+184 
+18,475 
+20,380 
+17,637 
+Operating income 
+6,617 
+5,602 
+6,989 
+Interest and other income (expense): 
+Interest expense 
+(64) 
+(61) 
+(69) 
+Interest income 
+41 
+67 
+87 
+Other, net 
+(63) 
+(23) 
+1 
+(86) 
+(17) 
+19 
+Income before income taxes 
+6,531 
+5,585 
+7,008 
+Income tax provision 
+1,596 
+1,964 
+2,332 
+Net income 
+$ 
+4,935 
+$ 
+3,621 
+$ 
+4,676 
+Net income per common share: 
+Basic 
+$ 
+0.57 
+$ 
+0.40 
+$ 
+0.50 
+Diluted 
+$ 
+0.57 
+$ 
+0.40 
+$ 
+0.49 
+Shares used in per-share calculation: 
+Basic 
+8,589 
+9,032 
+9,443 
+Diluted 
+8,703 
+9,121 
+9,603 
+Dividends declared and paid per common share: 
+$ 
+0.27 
+$ 
+0.06 
+$ 
+- 
+See accompanying notes to Consolidated Financial Statements. 
+F-4 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 
+(In thousands, except share data) 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Net income 
+$ 
+4,935 
+$ 
+3,621 
+$ 
+4,676 
+Foreign currency translation adjustment, net of tax 
+(8) 
+16 
+(2) 
+Comprehensive income 
+$ 
+4,927 
+$ 
+3,637 
+$ 
+4,674 
+See accompanying notes to Consolidated Financial Statements. 
+F-5 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY 
+(In thousands, except share data) 
+Common Stock 
+Shares Amount 
+Additional Paid-in 
+Capital 
+Retained 
+Earnings 
+Treasury 
+Stock 
+Accumulated Other Comprehensive 
+Income (Loss) 
+Total 
+Equity 
+Balance, December 31, 2010 
+9,426,443 
+$ 
+106 
+$ 
+22,875 
+$ 
+16,937 
+$ 
+(8,715) 
+$ 
+(69) 
+$ 
+31,134 
+Issuance of shares from exercise of stock options 
+239,074 
+2 
+957 
+- 
+- 
+- 
+959 
+Issuance of deferred stock units 
+- 
+- 
+141 
+- 
+- 
+- 
+141 
+Tax benefit related to employee stock sales and vesting of restricted stock 
+- 
+- 
+498 
+- 
+- 
+- 
+498 
+Purchase of treasury stock 
+(275,255) 
+- 
+- 
+- 
+(2,680) 
+- 
+(2,680) 
+Share-based compensation expense 
+- 
+- 
+587 
+- 
+- 
+- 
+587 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(2) 
+(2) 
+Net income 
+- 
+- 
+- 
+4,676 
+- 
+- 
+4,676 
+Balance, December 31, 2011 
+9,390,262 
+$ 
+108 
+$ 
+25,058 
+$ 
+21,613 
+$ 
+(11,395) 
+$ 
+(71) 
+$ 
+35,313 
+Issuance of shares from exercise of stock options 
+51,122 
+1 
+171 
+- 
+- 
+- 
+172 
+Issuance of deferred stock units 
+- 
+- 
+134 
+- 
+- 
+- 
+134 
+Tax benefit related to employee stock sales 
+- 
+- 
+57 
+- 
+- 
+- 
+57 
+Purchase of treasury stock 
+(721,184) 
+- 
+- 
+- 
+(5,938) 
+- 
+(5,938) 
+Dividends declared and paid on common stock 
+- 
+- 
+- 
+(526) 
+- 
+- 
+(526) 
+Share-based compensation expense 
+- 
+- 
+520 
+- 
+- 
+- 
+520 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+16 
+16 
+Net income 
+- 
+- 
+- 
+3,621 
+- 
+- 
+3,621 
+Balance, December 31, 2012 
+8,720,200 
+$ 
+109 
+$ 
+25,940 
+$ 
+24,708 
+$ 
+(17,333) 
+$ 
+(55) 
+$ 
+33,369 
+Issuance of shares from exercise of stock options 
+196,358 
+2 
+1,043 
+- 
+- 
+- 
+1,045 
+Issuance of deferred stock units 
+- 
+- 
+139 
+- 
+- 
+- 
+139 
+Issuance of common stock on deferred 
+stock units, net of relinquishments 
+6,919 
+- 
+(28 
+) 
+- 
+- 
+- 
+(28) 
+Tax benefit related to employee stock sales 
+- 
+- 
+132 
+- 
+- 
+- 
+132 
+Purchase of treasury stock 
+(604,161) 
+- 
+- 
+- 
+(5,194) 
+- 
+(5,194) 
+Dividends declared and paid on common stock 
+- 
+- 
+- 
+(2,317) 
+- 
+- 
+(2,317) 
+Share-based compensation expense 
+- 
+- 
+521 
+- 
+- 
+- 
+521 
+Reversal of deferred tax asset in connection with stock options forfeited 
+- 
+- 
+(73) 
+- 
+- 
+- 
+(73) 
+Foreign currency translation adj., net of tax 
+- 
+- 
+- 
+- 
+- 
+(8) 
+(8) 
+Net income 
+- 
+- 
+- 
+4,935 
+- 
+- 
+4,935 
+Balance, December 31, 2013 
+8,319,316 
+$ 
+111 
+$ 
+27,674 
+$ 
+27,326 
+$ 
+(22,527) 
+$ 
+(63) 
+$ 
+32,521 
+See accompanying notes to Consolidated Financial Statements. 
+F-6 
+TRANSACT TECHNOLOGIES INCORPORATED 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Cash flows from operating activities: 
+Net income 
+$ 
+4,935 
+$ 
+3,621 
+$ 
+4,676 
+Adjustments to reconcile net income to net cash provided by operating activities: 
+Share-based compensation expense 
+521 
+520 
+587 
+Incremental tax benefits from stock options exercised 
+(132) 
+(57) 
+(498) 
+Depreciation and amortization 
+1,741 
+1,758 
+1,608 
+Deferred income tax provision (benefit) 
+46 
+(95) 
+519 
+Loss (gain) on sale of fixed assets 
+60 
+(13) 
+24 
+Foreign currency transaction losses (gains) 
+3 
+34 
+(6) 
+Changes in operating assets and liabilities: 
+Accounts receivable 
+2,685 
+(6,332) 
+1,977 
+Inventories 
+(3,189) 
+3,684 
+(568) 
+Prepaid income taxes 
+(367) 
+479 
+(446) 
+Other current and long term assets 
+20 
+(154) 
+2 
+Accounts payable 
+(1,674) 
+3,403 
+(5,427) 
+Accrued liabilities and other liabilities 
+(2,156) 
+1,182 
+(352) 
+Net cash provided by operating activities 
+2,493 
+8,030 
+2,096 
+Cash flows from investing activities: 
+Capital expenditures 
+(709) 
+(1,082) 
+(640) 
+Additions to capitalized software 
+(42) 
+(35) 
+(616) 
+Proceeds from sale of fixed assets 
+5 
+15 
+1 
+Acquisitions 
+- 
+- 
+(4,000) 
+Net cash used in investing activities 
+(746) 
+(1,102) 
+(5,255) 
+Cash flows from financing activities: 
+Proceeds from stock option exercises 
+1,045 
+172 
+959 
+Purchases of common stock for treasury 
+(5,194) 
+(5,938) 
+(2,680) 
+Payment of dividends on common stock 
+(2,317) 
+(526) 
+- 
+Incremental tax benefits from stock options exercised 
+132 
+57 
+498 
+Payment of deferred financing costs 
+- 
+(7) 
+(31) 
+Net cash used in financing activities 
+(6,334) 
+(6,242) 
+(1,254) 
+Effect of exchange rate changes on cash and cash equivalents 
+(14) 
+(12) 
+(9) 
+(Decrease) increase in cash and cash equivalents 
+(4,601) 
+674 
+(4,422) 
+Cash and cash equivalents, beginning of period 
+7,537 
+6,863 
+11,285 
+Cash and cash equivalents, end of period 
+$ 
+2,936 
+$ 
+7,537 
+$ 
+6,863 
+Supplemental cash flow information: 
+Interest paid 
+$ 
+51 
+$ 
+51 
+$ 
+51 
+Income taxes paid 
+2,585 
+912 
+2,545 
+Non-cash financing activities 
+Purchases of common stock for treasury at year end 
+$ 
+- 
+$ 
+- 
+$ 
+(61) 
+See accompanying notes to Consolidated Financial Statements. 
+F-7 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+1. Description of business 
+TransAct Technologies Incorporated (“TransAct” or the “Company”), which has its headquarters in Hamden, CT and its primary operating facility in Ithaca, NY, operates in one operating segment: market specific solutions, including printers, terminals, software and other products for transaction-based and other industries. These industries include casino, gaming, lottery, banking, point-of-sale, food safety, oil and gas and medical and mobile. Our printers are designed based on market-specific requirements and are sold under the Ithaca®, Epic and Printrex® product brands. We distribute our products through OEMs, value-added resellers, selected distributors, and directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. We also generate revenue from the after-market side of the business, providing printer service, supplies and spare parts in addition to revenue from our software solution, the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that enables casino operators to create promotional coupons and marketing messages and print them in real-time at the slot machine. 
+2. Summary of significant accounting policies 
+Principles of consolidation: The accompanying Consolidated Financial Statements include the accounts of TransAct and its wholly-owned subsidiaries, which require consolidation, after the elimination of intercompany accounts, transactions and unrealized profit. 
+Reclassifications: Certain amounts in the prior years’ financial statements have been reclassified to conform to the current year’s presentation. 
+Use of estimates: The accompanying Consolidated Financial Statements were prepared using estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and disclosure of contingent assets and liabilities as of the date of the Consolidated Financial Statements and the reported amounts of sales and expenses during the reporting period. Actual results could differ from those estimates. 
+Segment reporting: We apply the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” We view our operations and manage our business as one segment: the design, development, assembly and marketing of transaction printers and terminals and providing printer-related software, services, supplies and spare parts . Factors used to identify TransAct’s single operating segment include the organizational structure of the Company and the financial information available for evaluation by the chief operating decision-maker in making decisions about how to allocate resources and assess performance. 
+Cash and cash equivalents: We consider all highly liquid investments with a maturity date of three months or less at date of purchase to be cash equivalents. 
+Allowance for doubtful accounts: We establish an allowance for doubtful accounts to ensure trade receivables are valued appropriately. We maintain an allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, significant one-time events and historical experience. We record a specific allowance for individual accounts when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, we would further adjust estimates of the recoverability of receivables. Allowances for doubtful accounts on accounts receivable balances were $63,000 as of December 31, 2013 and $66,000 as of December 31, 2012. 
+The following table summarizes the activity recorded in the valuation account for accounts receivable: 
+Year ended December 31, 
+(In thousands) 
+2013 
+2012 
+2011 
+Balance, beginning of period 
+$ 
+66 
+$ 
+70 
+$ 
+57 
+Additions charged to costs and expenses 
+- 
+- 
+1 
+Acquisition of business 
+- 
+- 
+15 
+Deductions 
+(3) 
+(4) 
+(3) 
+Balance, end of period 
+$ 
+63 
+$ 
+66 
+$ 
+70 
+Inventories: Inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or market. We review market value based on historical usage and estimates of future demand. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and market value. 
+Fixed assets: Fixed assets are stated at cost. Depreciation is recorded using the straight-line method over the estimated useful lives. The estimated useful life of tooling is five years; machinery and equipment is ten years; furniture and office equipment is five to ten years; and computer software and equipment is three to seven years. Leasehold improvements are amortized over the shorter of the term of the lease or the useful life of the asset. Costs related to repairs and maintenance are expensed as incurred. The costs of sold or retired assets are removed from the related asset and accumulated depreciation accounts and any gain or loss is recognized. Depreciation expense was $1,216,000, $1,183,000 and $1,339,000 in 2013, 2012 and 2011, respectively. 
+Leases: Rent expense under non-cancelable operating leases with scheduled rent increases or free rent periods are accounted for on a straight-line basis over the lease term, beginning on the date of control of physical use of the asset or of initial possession. The amount of the excess of straight-line rent expense over scheduled payments is recorded as a deferred liability. Construction allowances and other such lease incentives are recorded as deferred credits, and are amortized on a straight-line basis as a reduction of rent expense beginning in the period they are deemed to be earned, which generally coincides with the occupancy date. 
+F-8 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Goodwill and Intangible assets: We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with Accounting Standards Codification (“ASC”) 350-20 “Goodwill”, acquired goodwill is not amortized but is subject to impairment testing at least annually and when an event occurs or circumstances change, that indicate it is more likely than not an impairment exists. Factors considered that may trigger an impairment review of either acquired goodwill or intangible assets are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Definite lived intangible assets are amortized and are tested for impairment when appropriate. We have determined that no goodwill impairment has occurred based on our assessment as of December 31, 2013 when the impairment review is performed. 
+Revenue recognition: Our typical contracts include the sale of printers, which are sometimes accompanied by separately-priced extended warranty contracts. We also sell replacement parts, consumables, and other repair services (sometimes pursuant to multi-year product maintenance contracts), which are not included in the original printer sale and are ordered by the customer as needed. We recognize revenue pursuant to the guidance within ASC 605, “Revenue Recognition” (ASC 605). Specifically, revenue is recognized when evidence of an arrangement exists, delivery (based on shipping terms, which are generally FOB shipping point) has occurred, the selling price is fixed and determinable, and collectability is reasonably assured. We recognize revenue from the sale of printers and terminals to our distributors and resellers on a sell-in basis and on substantially the same terms as we recognize revenue from all our other customers. We provide for an estimate of product returns and price protection based on historical experience at the time of revenue recognition. 
+We have developed a software solution, EPICENTRAL, that will enable casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. Revenue arrangements for EPICENTRAL TM include multiple deliverables and as a result such arrangements are accounted for in accordance with both ASC 605-25, “Multiple-Element Arrangements” and ASC 985-605, “Software.” EPICENTRAL TM is primarily comprised of both a software component, which is licensed, and a hardware component, which can either be leased or sold to end users, and both components are integrated to deliver the system’s full functionality. Under leasing arrangements, revenue is generally recognized ratably over the lease term, excluding revenue allocated to installation, which is recognized upon completion. In an arrangement where the hardware is purchased, revenue, inclusive of software license fees, is generally recognized upon installation and formal acceptance by the customer with the exception of any amount allocated to free maintenance which is deferred and recognized over the free maintenance period. For EPICENTRAL TM and other multiple deliverable arrangements, we consider whether the deliverables in an arrangement are within the scope of existing higher-level GAAP and apply such literature to the extent that it provides guidance regarding whether to separate multiple-deliverable arrangements and how to allocate value among those separate units of accounting. We also determine whether revenue arrangements consist of more than one unit of accounting at inception of the arrangement and recognize revenue as each item in the arrangement is delivered. We allocate arrangement consideration to the separate units of accounting based on the relative fair value for all units of accounting in the arrangement, except where amounts allocable to the delivered units is limited to that which is contingent upon the delivery of additional deliverables or meeting other specified performance conditions. 
+Revenue related to extended warranty and product maintenance contracts is recognized pursuant to ASC 605-20-25, “Separately Priced Extended Warranty and Product Maintenance Contracts.” Pursuant to this provision, revenue related to separately priced product maintenance contracts is deferred and recognized over the term of the maintenance period. We record deferred revenue for advance payments received from customers for maintenance contracts. 
+Our customers have the right to return products that do not function properly within a limited time after delivery. We monitor and track product returns and record a provision for the estimated future returns based on historical experience. Returns have historically been within expectations and the provisions established. 
+We offer some of our customers price protection as an incentive to carry inventory of our product. These price protection plans provide that if we lower prices, we will credit them for the price decrease on inventory they hold. Our customers typically carry limited amounts of inventory, and we infrequently lower prices on current products. As a result, the amounts paid under these plans have not been material. 
+We charge our customers for shipping and handling services. The amounts billed to customers are recorded as revenue when the product ships. Any costs incurred related to these services are included in cost of sales. 
+Concentration of credit risk: Financial instruments that potentially expose us to concentrations of credit risk are limited to cash and cash equivalents held by our banks in excess of insured limits and accounts receivable. 
+Accounts receivable from customers representing 10% or more of total accounts receivable were as follows: 
+December 31, 
+2013 
+2012 
+GTECH 
+21% 
+37% 
+Customer A 
+22% 
+17% 
+F-9 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+Sales to customers representing 10% or more of total net sales were as follows: 
+Year ended December 31, 
+2013 
+2012 
+2011 
+GTECH 
+12% 
+18% 
+26% 
+Customer A 
+12% 
+15% 
+13% 
+Warranty: We generally warrant our products for up to 36 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. 
+The following table summarizes the activity recorded in the accrued product warranty liability: 
+Year ended December 31, 
+(In thousands) 
+2013 
+2012 
+2011 
+Balance, beginning of period 
+$ 
+274 
+$ 
+421 
+$ 
+249 
+Warranties issued 
+492 
+104 
+472 
+Acquisition of business 
+- 
+- 
+25 
+Warranty settlements 
+(400) 
+(251) 
+(325) 
+Balance, end of period 
+$ 
+366 
+$ 
+274 
+$ 
+421 
+Approximately $84,000 and $101,000 of the accrued product warranty liability were classified as long-term at December 31, 2013 and 2012, respectively. 
+Research and development expenses: Research and development expenses include engineering, design and product development expenses incurred in connection with specialized engineering and design to introduce new products and to customize existing products, and are expensed as a component of operating expenses as incurred. We recorded approximately $4,065,000, $4,239,000 and $3,418,000 of research and development expenses in 2013, 2012 and 2011, respectively. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. During 2010 we began the development of EPICENTRAL TM and unamortized development costs for such software were approximately $370,000 and $528,000 as of December 31, 2013 and 2012, respectively. The total amount charged to cost of sales for capitalized software development costs was approximately $199,000, $189,000 and $62,000 in 2013, 2012 and 2011, respectively. The weighted-average amortization period of unamortized capitalized software developments costs is approximately 2 years. 
+Advertising: Advertising costs are expensed as incurred. Advertising expenses, which are included in selling and marketing expense on the accompanying Consolidated Statements of Income, for 2013, 2012 and 2011 totaled $1,058,000, $949,000 and $871,000, respectively. These expenses include items such as consulting and professional services, tradeshows, and print advertising. 
+Restructuring: We continually evaluate our cost structure to ensure that it is appropriately positioned to respond to changing market conditions. We record pre-tax restructuring charges in accordance with ASC 420-10-25-4, “Exit or Disposal Cost Obligations.” See Note 8 for further discussion. 
+Income taxes: The income tax amounts reflected in the accompanying Consolidated Financial Statements are accounted for under the liability method in accordance with ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. We assess the likelihood that net deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. In accordance with ASC 740, we identified, evaluated and measured the amount of benefits to be recognized for our tax return positions. See Note 13 for information regarding our accounting for income taxes. 
+Foreign currency translation: The financial position and results of operations of our foreign subsidiary in the United Kingdom are measured using local currency as the functional currency. Assets and liabilities of such subsidiary have been translated into U.S. dollars at the year-end exchange rate, related sales and expenses have been translated at the average exchange rate for the year, and shareholders’ equity has been translated at historical exchange rates. The resulting translation gains or losses, net of tax, are recorded in shareholders’ equity as a cumulative translation adjustment, which is a component of 
+F-10 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+2. Summary of significant accounting policies (continued) 
+accumulated other comprehensive income. Foreign currency transaction gains and losses, including those related to intercompany balances, are recognized in Other, net on the Consolidated Statements of Income. 
+Share-based payments: At December 31, 2013, we had share-based employee compensation plans, which are described more fully in Note 12 - Stock incentive plans. We account for those plans under the recognition and measurement principles of ASC 718, “Compensation – Stock Compensation.” Share-based compensation expense is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. We have no awards with market or performance conditions. 
+We use the Black-Scholes option-pricing model to calculate the fair value of share based awards. The key assumptions for this valuation method include the expected term of the option, stock price volatility, risk-free interest rate, dividend yield, market price of our underlying stock and exercise price. Many of these assumptions are judgmental and highly sensitive in the determination of compensation expense. In addition, we estimate forfeitures when recognizing compensation expense, and we adjust our estimate of forfeitures over the requisite service period based on the extent to which actual forfeitures differ, or are expected to differ, from such estimates. Changes in estimated forfeitures are recognized through a cumulative true-up adjustment in the period of change and also impacts the amount of compensation expense to be recognized in future periods. 
+Net income and loss per share: We report net income or loss per share in accordance with ASC 260, “Earnings per Share (EPS).” Under this guidance, basic EPS, which excludes dilution, is computed by dividing income or loss available to common shareholders by the weighted average number of common shares outstanding for the period. Unvested restricted stock is excluded from the calculation of weighted average common shares for basic EPS. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted EPS includes restricted stock and in-the-money stock options using the treasury stock method. During a loss period, the assumed exercise of in-the-money stock options has an anti-dilutive effect, and therefore, these instruments are excluded from the computation of dilutive EPS. See Note 14 - Earnings per share. 
+3. Business acquisitions 
+On August 19, 2011, we completed the purchase of substantially all of the assets of Printrex, Inc. (“Printrex”) for $4,000,000 in cash and potential future contingent consideration further discussed below. Printrex is a leading manufacturer of specialty printers primarily sold into the oil and gas exploration and medical markets which serve commercial and industrial customers primarily in the United States, Canada, Europe and Asia. This acquisition was completed primarily to expand our product offerings into the oil and gas exploration and medical markets. We have completed our analysis of fair value attributes of the assets acquired through the Printrex acquisition and the final assessment of values did not differ materially from our preliminary assessment. 
+The following table summarizes the final fair values of the assets acquired and liabilities assumed related to the Printrex acquisition: 
+Purchase Price Allocation (In thousands) : 
+Receivables 
+$ 
+673 
+Inventories 
+677 
+Fixed assets 
+11 
+Other current assets 
+6 
+Intangible assets 
+2,280 
+Goodwill 
+1,152 
+Other assets 
+22 
+Initial estimate for liability related to potential future contingent consideration 
+(680) 
+Other liabilities 
+(141) 
+Total purchase price 
+$ 
+4,000 
+Intangible Assets: 
+Customer relationships 
+$ 
+1,300 
+Trademark 
+480 
+Developed technology 
+420 
+Other 
+80 
+Total Intangible assets 
+$ 
+2,280 
+Intangible Asset Weighted Average Amortization Period: 
+Customer relationships 
+6 years 
+Trademark 
+10 years 
+Developed technology 
+9 years 
+Other 
+1.2 years 
+Total weighted average 
+7.2 years 
+F-11 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+3. Business acquisitions (continued) 
+The fair values assigned to intangible assets were determined through the use of the income approach, specifically the relief from royalty method and the multi-period excess earnings method. The valuation of tangible assets was derived using a combination of the income approach, the market approach and the cost approach. 
+We entered into a contingent consideration arrangement with Printrex as part of the acquisition for 30% of the gross profit for a three-year period related to new products under development, less certain other adjustments, beginning on the earlier of 1) January 1, 2012 or 2) the date of first commercial introduction of the new products under development. The undiscounted fair value related to the contingent liability could range from $0 to $200,000. The fair value of the contingent consideration arrangement was $60,000 and $960,000 at December 31, 2013 and 2012, respectively, which were estimated by applying the income approach. That measure is based on significant inputs that are not observable in the market, which fair value measurement guidance refers to as Level 3 inputs. During 2013, the fair value of the contingent consideration was decreased by $900,000 and this credit is included in general and administrative expenses on the Consolidated Statements of Income. No payments were made under the arrangement during 2013 as the underlying conditions of the contingent consideration arrangement were not satisfied. 
+Key assumptions include a discount rate range of 4% to 5% and a probability-adjusted level of gross profit between $300,000 and $1,200,000. 
+The Printrex acquisition resulted in $1,152,000 of goodwill, which is deductible for tax purposes, and largely consists of expected synergies resulting from the acquisition. Key areas of potential cost savings include increased purchasing power for raw materials; manufacturing and supply chain work process improvements; and the elimination of redundant manufacturing overhead and operating expenses. We also anticipate that the transaction will produce growth synergies as a result of applying TransAct’s sales and engineering expertise to Printrex’s products. 
+The change in carrying value of goodwill for the year ended December 31, 2012 was as follows (in thousands): 
+Balance at December 31, 2011 
+$ 
+2,518 
+Inventory measurement adjustment in connection with Printrex acquisition 
+103 
+Balance at December 31, 2012 
+$ 
+2,621 
+We incurred acquisition-related costs of $159,000 during the year ended December 31, 2011. These costs included legal, accounting, valuation and other professional services and were included in general and administrative expenses in the Consolidated Statements of Income. In addition, we incurred approximately $78,000 of integration-related expenses in 2011 that were also included in general and administrative expenses in the Consolidated Statements of Income. No such expenses were incurred during 2012 or 2013. 
+The Printrex acquisition contributed $1,892,000 to net sales and reduced net income by $23,000 for the year ended December 31, 2011. This reduction includes the after-tax impact of $139,000 of amortization expense from the intangible assets acquired from Printrex as well as $78,000 of integration expenses. The following unaudited pro forma consolidated results of operations for the year ended December 31, 2011 are provided for illustrative purposes only and assume that the acquisition of Printrex occurred on January 1, 2010. This unaudited pro forma information should not be relied upon as being indicative of the historical results that would have been obtained if the acquisition had occurred on that date, nor of the results that may be obtained in the future. 
+(In thousands) 
+Sales 
+$ 
+69,694 
+Net income 
+$ 
+5,025 
+4. Inventories 
+The components of inventories are: 
+December 31, 
+(In thousands) 
+2013 
+2012 
+Raw materials and purchased component parts 
+$ 
+7,263 
+$ 
+6,871 
+Work-in-process 
+31 
+- 
+Finished goods 
+6,215 
+3,450 
+$ 
+13,509 
+$ 
+10,321 
+F-12 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+5. Fixed assets 
+The components of fixed assets, net are: 
+December 31, 
+(In thousands) 
+2013 
+2012 
+Tooling, machinery and equipment 
+$ 
+12,066 
+$ 
+12,913 
+Furniture and office equipment 
+1,492 
+1,555 
+Computer software and equipment 
+5,986 
+5,546 
+Leasehold improvements 
+1,926 
+1,800 
+21,470 
+21,814 
+Less: Accumulated depreciation and amortization 
+(18,989) 
+(18,925) 
+2,481 
+2,889 
+Construction in-process 
+251 
+413 
+$ 
+2,732 
+$ 
+3,302 
+6. Intangible assets 
+Identifiable intangible assets are recorded in Intangible assets in the accompanying Consolidated Balance Sheets and are comprised of the following: 
+December 31, 
+2013 
+2012 
+(In thousands) 
+Gross Amount 
+Accumulated Amortization 
+Gross Amount 
+Accumulated Amortization 
+Purchased technology 
+$ 
+1,604 
+$ 
+(924) 
+$ 
+1,563 
+$ 
+(679) 
+Customer relationships 
+1,300 
+(513) 
+1,300 
+(296) 
+Trademark 
+480 
+(113) 
+480 
+(65) 
+Covenant not to compete 
+146 
+(146) 
+146 
+(146) 
+Patents 
+57 
+(35) 
+57 
+(32) 
+Other 
+80 
+(80) 
+80 
+(80) 
+Total 
+$ 
+3,667 
+$ 
+(1,811) 
+$ 
+3,626 
+$ 
+(1,298) 
+Amortization expense was $513,000 in 2013, $568,000 in 2012 and $255,000 in 2011. Amortization expense for each of the next five years ending December 31 is expected to be as follows: $514,000 in 2014; $456,000 in 2015; $333,000 in 2016; $244,000 in 2017; and $309,000 thereafter. 
+7. Accrued liabilities 
+The components of accrued liabilities are: 
+December 31, 
+(In thousands) 
+2013 
+2012 
+Payroll and fringe benefits 
+$ 
+1,447 
+$ 
+1,770 
+Warranty 
+282 
+173 
+Professional and consulting 
+139 
+189 
+Other 
+347 
+795 
+$ 
+2,215 
+$ 
+2,927 
+8. Accrued business consolidation and restructuring expenses 
+In January 2012, we determined that we no longer needed to maintain the existing Printrex manufacturing facility in San Jose, California, along with certain redundant headcount. As a result, we incurred expenses of $138,000 in 2012 for employee termination benefits related to these employee reductions as well as moving costs and the closing of the San Jose manufacturing operations that was completed as of December 31, 2012. This restructuring charge was recorded in accordance with ASC 420-10-25-4 “Exit or Disposal Cost Obligations” and is included within Business consolidation and restructuring expenses in the accompanying Consolidated Statements of Income. Cash payments made under this restructuring plan were completed by October 2012. 
+In May 2011, we closed our New Britain, CT service facility which primarily serviced our first generation legacy lottery printers for GTECH Corporation (“GTECH”) and incurred $184,000 in facility closure and severance costs in the second quarter of 2011. These restructuring activities reduced the number of employees and closed a facility, which caused us to incur costs for employee termination benefits related to these employee reductions as well as lease termination costs and the disposal of fixed assets. Cash payments made under this restructuring plan were completed by April 2012. 
+F-13 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+8. Accrued business consolidation and restructuring expenses (continued) 
+The following table summarizes the activity recorded in accrued restructuring expenses during 2012, and is included in accrued liabilities in the accompanying Consolidated Balance Sheets. There was no activity in accrued restructuring expenses during 2013. 
+(In thousands) 
+Accrual balance, beginning of period 
+$ 
+45 
+Severance & moving charges 
+138 
+Cash payments 
+(183) 
+Accrual balance, end of period 
+$ 
+- 
+9. Retirement savings plan 
+We maintain a 401(k) plan under which all full-time employees are eligible to participate at the beginning of each month immediately following their date of hire. We match employees’ contributions at a rate of 50% of employees’ contributions up to the first 6% of the employees’ compensation contributed to the 401(k) plan. Our matching contributions were $265,000, $280,000 and $201,000 in 2013, 2012 and 2011, respectively. 
+10. Borrowings 
+We maintain a credit facility (the “TD Bank Credit Facility”) with TD Bank which provides for a $20,000,000 revolving credit line that expires on November 28, 2014. Borrowings under the TD Bank Credit Facility bear a floating rate of interest at the prime rate minus one percent and are secured by a lien on all of our assets. We also pay a fee of 0.25% on unused borrowings under the TD Bank Credit Facility. 
+On September 7, 2012, we signed an amendment to the TD Bank Credit Facility that allows us to declare and pay cash dividends to holders of our outstanding common shares subject to approval by our Board of Directors and provided that no default or event of default has occurred and is continuing under the credit facility on the date of the dividend payment. The amendment also allows us to use up to $5,000,000 in revolving credit loans to fund future cash dividend payments or treasury share buybacks as well as requires cash dividend payments to be treated as distributions for purposes of quarterly debt covenant calculations. 
+The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to incur additional indebtedness and the creation of other liens. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2013. 
+As of December 31, 2013, undrawn commitments under the TD Bank Credit facility were $20,000,000. 
+11. Commitments and contingencies 
+On June 8, 2012, Avery Dennison Corporation (“AD”) filed a civil complaint against the Company and a former employee of the Company and of AD, in the Court of Common Pleas (the “Court”) in Lake County, Ohio. The complaint alleges that this former employee and the Company misappropriated unspecified trade secrets and confidential information related to the design of our food safety terminals from AD. The complaint requests a preliminary and permanent injunction against the Company from manufacturing and selling our Ithaca® 9700 and 9800 food safety terminals. On July 16, 2012, the Company filed its answer, affirmative defenses and counterclaims, seeking all available damages including legal fees. A hearing on the plaintiff's motion for preliminary injunction took place in August 2012, and in November 2012, the Court denied this request. AD filed an appeal of the Court’s ruling to the Eleventh Appellate District, which heard oral arguments on the appeal on July 16, 2013. On July 23, 2013, AD requested that the Eleventh Appellate District enjoin the Company’s further sale and marketing of the food safety terminals, pending the appeals court's decision. On July 29, 2013, TransAct opposed this request. On October 15, 2013, the Eleventh District Court of Appeals affirmed the lower court’s decision in the Company’s favor and denied AD’s further request for an injunction pending the Court of Appeal’s decision. On October 24, 2013, AD filed a motion seeking that the Court of Appeals reconsider its decision. 
+At December 31, 2013, we were the lessee on operating leases for equipment and real property. Rent expense was approximately $918,000, $1,005,000 and $1,030,000 in 2013, 2012 and 2011, respectively. Minimum aggregate rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2013 are as follows: $832,000 in 2014; $821 ,000 in 2015; $563,000 in 2016 and $78,000 in 2017. 
+12. Stock incentive plans 
+Stock incentive plans . We currently have three primary stock incentive plans: the 1996 Directors’ Stock Plan, which provided for non-discretionary awards to non-employee directors; the 2001 Employee Stock Plan, which provided for the grant of awards to key employees of the Company and other non-employees who provided services to the Company; and the 2005 Equity Incentive Plan, which provides for awards to executives, key employees, directors and consultants. The plans generally provide for awards in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units, (v) stock appreciation rights or (vi) limited stock appreciation rights. However, the 2001 Employee Stock Plan does not provide for incentive stock option awards. Options granted under these plans have exercise prices equal to 100% of the fair market value of the common stock at the date of grant. Options granted have a ten-year term and generally vest over a three- to five-year period, unless automatically accelerated for certain defined events. As of May 2005, no new awards will be made under the 1996 Directors’ Stock Plan or the 2001 Employee Stock Plan. Under our 2005 Equity Incentive Plan, we may authorize up to 1,200,000 of shares of TransAct common stock. At December 31, 2013, 195,755 shares of common stock remained available for issuance under the 2005 Equity Incentive Plan. 
+F-14 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+12. Stock incentive plans (continued) 
+Under the assumptions indicated below, the weighted-average fair value of stock option grants for the years ended December 31, 2013, 2012 and 2011 was $7.94, $6.91 and $10.42, respectively. The table below indicates the key assumptions used in the option valuation calculations for options granted in the years ended December 31, 2013, 2012 and 2011 and a discussion of our methodology for developing each of the assumptions used in the valuation model: 
+Year ended December 31, 
+2013 
+2012 
+2011 
+Expected option term 
+6.8 years 
+6.7 years 
+6.8 years 
+Expected volatility 
+56.5% 
+57.8% 
+62.5% 
+Risk-free interest rate 
+0.8% 
+0.8% 
+2.0% 
+Dividend yield 
+3.1% 
+-% 
+-% 
+Expected Option Term - This is the weighted average period of time over which the options granted are expected to remain outstanding giving consideration to our historical exercise patterns. Options granted have a maximum term of ten years and an increase in the expected term will increase compensation expense. 
+Expected Volatility – The stock volatility for each grant is measured using the weighted average of historical daily price changes of our common stock over the most recent period approximately equal to the expected option term of the grant. An increase in the expected volatility factor will increase compensation expense. 
+Risk-Free Interest Rate - This is the U.S. Treasury rate in effect at the time of grant having a term approximately equal to the expected term of the option. An increase in the risk-free interest rate will increase compensation expense. 
+Dividend Yield – We began paying a quarterly dividend of $.06 per share to common shareholders in December 2012, which was increased to $.07 per share in May 2013. The dividend yield is calculated by dividing the annual dividend declared per common share by the weighted average market value of our common stock on the date of grant. An increase in the dividend yield will decrease compensation expense. 
+For the years ending December 31, 2013, 2012 and 2011, we recorded $521,000, $520,000, and $587,000 of share-based compensation expense, respectively, included primarily in general and administrative expense in our Consolidated Statements of Income. We also recorded income tax benefits of approximately $127,000, $183,000, and $195,000 in 2013, 2012, and 2011 respectively, related to such share-based compensation. At December 31, 2013, these benefits are recorded as a deferred tax asset in the Consolidated Balance Sheets. 
+The 1996 Directors’ Stock Plan, 2001 Employee Stock Plan and 2005 Equity Incentive Plan option activity is summarized below: 
+Number of Shares 
+Weighted Average Exercise Price 
+Weighted Average Remaining Contractual Term 
+Aggregate Intrinsic Value 
+Outstanding at December 31, 2012 
+849,961 
+$ 
+8.19 
+Granted 
+129,000 
+7.94 
+Exercised 
+(206,111) 
+5.45 
+Forfeited 
+(2,000) 
+6.70 
+Cancelled 
+(52,375) 
+14.24 
+Outstanding at December 31, 2013 
+718,475 
+$ 
+8.49 
+6.2 years 
+$ 
+3,349,000 
+Options exercisable at December 31, 2013 
+388,650 
+$ 
+9.26 
+4.6 years 
+$ 
+1,717,000 
+Options vested or expected to vest 
+699,575 
+$ 
+8.52 
+6.1 years 
+$ 
+3,255,000 
+F-15 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+12. Stock incentive plans (continued) 
+Shares that are issued upon exercise of employee stock options are newly issued shares and not issued from treasury stock. As of December 31, 2013, unrecognized compensation cost related to stock options is approximately $903,000, which is expected to be recognized over a weighted average period of 2.4 years. 
+The total intrinsic value of stock options exercised was $910,000, $222,000 and $1,576,000 and the total fair value of stock options vested was $815,000, $641,000, and $504,000 during the years ended December 31, 2013, 2012 and 2011, respectively. Cash received from option exercises was $1,045,000, $172,000 and $959,000 for 2013, 2012 and 2011, respectively. We recorded a realized tax benefit in 2013,2012 and 2011 from equity-based awards of $132,000, $57,000 and $498,000, respectively, related to options exercised which has been included as a component of cash flows from financing activities in the Consolidated Statement of Cash Flows. 
+Restricted stock: Under the 2001 Employee Stock Plan and 2005 Equity Incentive Plan, we granted shares of restricted common stock, for no consideration, to our officers, directors and certain key employees. As of December 31, 2013, there was no unrecognized compensation cost related to restricted stock and all previously issued restricted shares are fully vested. 
+We paid a portion of the 2012, 2011 and 2010 incentive bonus for the chief executive officer and chief financial officer in the form of 17,613, 20,055 and 14,323 deferred stock units, respectively, with a corresponding credit recorded to Additional Paid in Capital (net of share relinquishments) in the amounts of $111,000, $134,000 and $141,000 in 2013, 2012 and 2011, respectively. Such deferred stock units were granted in March 2013, 2012 and 2011, respectively, and were fully vested at the time of grant. These units will be converted three years from the grant date to shares of the Company’s common stock on a one-for-one basis. The weighted average exercise price of the deferred stock units was $7.98. 
+13. Income taxes 
+The components of the income tax provision are as follows: 
+Year Ended December 31, 
+(In thousands) 
+2013 
+2012 
+2011 
+Current: 
+Federal 
+$ 
+1,479 
+$ 
+1,973 
+$ 
+1,695 
+State 
+38 
+46 
+74 
+Foreign 
+33 
+40 
+44 
+1,550 
+2,059 
+1,813 
+Deferred: 
+Federal 
+80 
+(116) 
+448 
+State 
+(34) 
+21 
+71 
+Foreign 
+- 
+- 
+- 
+46 
+(95) 
+519 
+Income tax provision 
+$ 
+1,596 
+$ 
+1,964 
+$ 
+2,332 
+Our effective tax rates were 24.4%, 35.2% and 33.3% for the years ended December 31, 2013, 2012 and 2011, respectively. Our effective tax rate for 2013 is unusually low because it includes: 1) a $224,000 reduction in tax liabilities for unrecognized tax benefits resulting from the completion of an audit of our 2010 federal income tax return and 2) the benefit from the 2012 federal research and development credit (“R&D credit”) of approximately $220,000 as this credit was not renewed until January 2, 2013 as a component of the American Taxpayer Relief Act of 2012. 
+At December 31, 2013, we have no federal or state net operating loss carryforwards. We have approximately $67,000 in state tax credit carryforwards that begin to expire in 2014. Foreign (loss) income before taxes was $(29,000), $92,000 and $68,000 in 2013, 2012 and 2011, respectively. 
+F-16 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Income taxes (continued) 
+Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the Consolidated Financial Statements. Our gross deferred tax assets and liabilities were comprised of the following: 
+December 31, 
+(In thousands) 
+2013 
+2012 
+Deferred tax assets: 
+Foreign net operating losses 
+$ 
+242 
+$ 
+186 
+Capitalized research and development 
+68 
+136 
+Inventory reserves 
+1,050 
+961 
+Deferred revenue 
+59 
+79 
+Warranty reserve 
+127 
+96 
+Stock compensation expense 
+956 
+1,036 
+Foreign tax and other credits 
+45 
+34 
+Other liabilities and reserves 
+491 
+705 
+Gross deferred tax assets 
+3,038 
+3,233 
+Valuation allowance 
+(242) 
+(216) 
+Net deferred tax assets 
+2,796 
+3,017 
+Deferred tax liabilities: 
+Depreciation 
+175 
+365 
+Other 
+46 
+37 
+Net deferred tax liabilities 
+221 
+402 
+Total net deferred tax assets 
+$ 
+2,575 
+$ 
+2,615 
+A valuation allowance of $242,000 has been established for foreign net operating loss carryforwards that are not expected to be used. The following table summarizes the activity recorded in the valuation allowance on the deferred tax assets: 
+Year ended December 31, 
+(In thousands) 
+2013 
+2012 
+2011 
+Balance, beginning of period 
+$ 
+216 
+$ 
+176 
+$ 
+125 
+Additions charged to income tax provision 
+56 
+40 
+51 
+Reductions credited to income tax provision 
+(30) 
+- 
+- 
+Balance, end of period 
+$ 
+242 
+$ 
+216 
+$ 
+176 
+Differences between the U.S. statutory federal income tax rate and our effective income tax rate are analyzed below: 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Federal statutory tax rate 
+34.0% 
+34.0% 
+34.0% 
+State income taxes, net of federal income taxes 
+0.1 
+0.8 
+1.4 
+Tax benefit from tax credits, net of valuation allowance 
+- 
+- 
+(2.7) 
+Valuation allowance and tax accruals 
+0.9 
+0.9 
+0.7 
+Permanent items 
+(8.3) 
+(0.8) 
+(0.4) 
+Other 
+(2.3) 
+0.3 
+0.3 
+Effective tax rate 
+24.4% 
+35.2% 
+33.3% 
+At December 31, 2013 and 2012, we had approximately $106,000 and $251,000 of total gross unrecognized tax benefits that, if recognized, would favorably affect the effective income tax rate in any future periods. We are not aware of any events that could occur within the next twelve months that could cause a significant change in the total amount of unrecognized tax benefits. A tabular reconciliation of the gross amounts of unrecognized tax benefits at the beginning and end of the year is as follows: 
+(In thousands) 
+2013 
+2012 
+Unrecognized tax benefits as of January 1 
+$ 
+251 
+$ 
+228 
+Tax positions taken during the current period 
+79 
+23 
+Lapse of statute of limitations 
+(224) 
+- 
+Unrecognized tax benefits as of December 31 
+$ 
+106 
+$ 
+251 
+F-17 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+13. Income taxes (continued) 
+We are subject to U.S. federal income tax as well as income tax of certain state and foreign jurisdictions. We have substantially concluded all U.S. federal income tax, state and local, and foreign tax matters through 2009. During 2008, a limited scope examination of our 2005 and 2006 federal tax returns was completed and during 2013, an examination of our 2010 federal tax return was completed. However, our federal tax returns for the years 2010 through 2012 remain open to examination. Various state and foreign tax jurisdiction tax years remain open to examination as well, though we believe that any additional assessment would be immaterial to the Consolidated Financial Statements. 
+We do not anticipate that the total unrecognized tax benefits of approximately $106,000 will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2014. 
+We recognize interest and penalties related to uncertain tax positions in the income tax provision. As of December 31, 2013 and 2012, we have approximately $10,000 and $46,000, respectively, of accrued interest and penalties related to uncertain tax positions. 
+14. Earnings per share 
+For 2013, 2012 and 2011, earnings per share were computed as follows (in thousands, except per share amounts): 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Net income 
+$ 
+4,935 
+$ 
+3,621 
+$ 
+4,676 
+Shares: 
+Basic: Weighted average common shares outstanding 
+8,589 
+9,032 
+9,443 
+Add: Dilutive effect of outstanding options as determined by the treasury stock method 
+114 
+89 
+160 
+Diluted: Weighted average common and common equivalent shares outstanding 
+8,703 
+9,121 
+9,603 
+Net income per common share: 
+Basic 
+$ 
+0.57 
+$ 
+0.40 
+$ 
+0.50 
+Diluted 
+0.57 
+0.40 
+0.49 
+We compute earnings per share using the two-class method, which is an earnings allocation formula that determines earnings per share for common stock and participating securities. Restricted stock granted by the Company is considered a participating security since it contains a non-forfeitable right to dividends. 
+Certain stock-based awards were not included in the full year computation of earnings per diluted share because the effect would be anti-dilutive. Anti-dilutive stock options, restricted shares and deferred stock units excluded from the computation of earnings per dilutive share were 311,000, 585,125, and 309,250, at December 31, 2013, 2012 and 2011 respectively. 
+15. Stock repurchase program 
+Prior to its expiration on May 27, 2013, we maintained a stock repurchase program (the “Stock Repurchase Program”) whereby we were authorized to repurchase up to $15,000,000, as increased from $10,000,000 in March 2012, of our outstanding shares of common stock from time to time in the open market, depending on market conditions, share price and other factors. The Stock Repurchase Program expir ed on May 27, 2013 and was not renewed. We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the settlement date. From January 1, 2013 through the expiration date of the Stock Repurchase Program, we repurchased 114,161 shares of common stock for approximately $887,000, at an average price of $7.77 per share. In addition to shares repurchased under the Stock Repurchase Program, during the year ended December 31, 2013, we repurchased 490,000 shares of our common stock for approximately $4,307,000 at an average price per share of $8.79 in an open-market transaction. From January 1, 2005 through December 31, 2013, we repurchased a total of 2,787,038 shares of common stock for approximately $22,527,000 under all of our stock repurchase programs, at an average price of $8.08 per share. At December 31, 2013, no additional shares are authorized for future repurchases due to the expiration of the Stock Repurchase Program. 
+F-18 
+TRANSACT TECHNOLOGIES INCORPORATED 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+16. Geographic area information 
+Information regarding our operations by geographic area is contained in the following table. These amounts in the geographic area table are based on the location of the customer and vendor. 
+Year Ended December 31, 
+(In thousands) 
+2013 
+2012 
+2011 
+Net sales: 
+United States 
+$ 
+46,377 
+$ 
+49,932 
+$ 
+49,301 
+International 
+13,764 
+18,454 
+16,668 
+Total 
+$ 
+60,141 
+$ 
+68,386 
+$ 
+65,969 
+Fixed assets, net: 
+United States 
+$ 
+1,583 
+$ 
+1,941 
+$ 
+2,129 
+International 
+1,149 
+1,361 
+1,229 
+Total 
+$ 
+2,732 
+$ 
+3,302 
+$ 
+3,358 
+Sales to international customers were approximately 23%, 27%, and 25% in 2013, 2012, and 2011 respectively. Sales to the United Kingdom represented 52%, 52%, and 51%, sales to the Pacific Rim (which includes Australia and Asia) represented 26%, 18%, and 25%, and sales to Canada represented 10%, 16%, and 6% of total international sales in 2013, 2012, and 2011 respectively. International long-lived assets consist of net fixed assets located at our foreign subsidiary in the United Kingdom as well as our contract manufacturers in China, Thailand, Malaysia and Mexico. 
+17. Quarterly results of operations (unaudited) 
+Our quarterly results of operations for 2013 and 2012 are as follows: 
+Quarter Ended 
+(In thousands, except per share amounts) 
+March 31 
+June 30 
+September 30 
+December 31 
+2013: 
+Net sales 
+$ 
+15,057 
+$ 
+15,788 
+$ 
+16,768 
+$ 
+12,528 
+Gross profit 
+6,433 
+6,452 
+7,206 
+5,001 
+Net income 
+1,160 
+1,215 
+1,451 
+1,109 
+Net income per share: 
+Basic 
+0.13 
+0.14 
+0.17 
+0.13 
+Diluted 
+0.13 
+0.14 
+0.17 
+0.13 
+2012: 
+Net sales 
+$ 
+17,559 
+$ 
+15,853 
+$ 
+15,358 
+$ 
+19,616 
+Gross profit 
+6,778 
+5,842 
+5,679 
+7,683 
+Net income 
+1,208 
+508 
+23 
+1,882 
+Net income per share: 
+Basic 
+0.13 
+0.06 
+0.00 
+0.21 
+Diluted 
+0.13 
+0.06 
+0.00 
+0.21 
+F-19 
+Index to Exhibits 
+3.1(a) 
+Certificate of Incorporation of TransAct Technologies Incorporated (“TransAct” or the “Company”), filed with the Secretary of State of Delaware on June 17, 1996. 
+(2) 
+3.1(b) 
+Certificate of Amendment of Certificate of Incorporation of the Company, filed with the Secretary of State of Delaware on June 4, 1997. 
+(4) 
+3.1(c) 
+Certificate of Designation, Series A Preferred Stock, filed with the Secretary of State of Delaware on December 2, 1997. 
+(5) 
+3.1(d) 
+Certificate of Designation, Series B Preferred Stock, filed with the Secretary of State of Delaware on April 6, 2000. 
+(7) 
+3.2 
+Amended and Restated By-laws of the Company. 
+(6) 
+4.1 
+Specimen Common Stock Certificate. 
+(2) 
+10.1(x) 
+1996 Stock Plan, effective July 30, 1996. 
+(3) 
+10.2(x) 
+Non-Employee Directors’ Stock Plan, effective August 22, 1996. 
+(3) 
+10.3(x) 
+2001 Employee Stock Plan. 
+(8) 
+10.4(x) 
+2005 Equity Incentive Plan. 
+(12) 
+10.5(x) 
+Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. Shuldman. 
+(2) 
+10.6(x) 
+Severance Agreement by and between TransAct and Benjamin C. Wyatt, dated May 27, 2008. 
+(21) 
+10.7(x) 
+Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, 2004. 
+(11) 
+10.8(x) 
+Severance Agreement by and between TransAct and Tracey S. Chernay, dated July 29, 2005. 
+(15) 
+10.9(x) 
+Amendment to Employment Agreement, effective January 1, 2008, by and between TransAct and Bart C. Shuldman. 
+(16) 
+10.10(x) 
+Amendment to Severance Agreement by and between TransAct and Benjamin C. Wyatt, effective January 1, 2008. 
+(21) 
+10.11(x) 
+Amendment to Severance Agreement by and between TransAct and Steven A. DeMartino, effective January 1, 2008. 
+(16) 
+10.12(x) 
+Amendment to Severance Agreement by and between TransAct and Tracey S. Chernay, effective January 1, 2008. 
+(16) 
+10.13 
+Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, 1992. 
+(2) 
+10.14 
+Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated December 2, 1996. 
+(4) 
+10.15 
+Agreement regarding the Continuation and Renewal of Lease by and between Bomax Properties, LLC and TransAct, dated July 18, 2001. 
+(9) 
+10.16 
+Amendment No. 1 to Lease Agreement between Bomax Properties, LLC and TransAct. 
+(19) 
+10.17 
+Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated December 2, 2004. 
+(11) 
+10.18 
+First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 
+(17) 
+10.19 
+Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated November 27, 2006. 
+(13) 
+10.20 
+OEM Purchase Agreement by and between GTECH Corporation and TransAct, dated November 20, 2009. (Pursuant to Rule 24-b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy) 
+(17) 
+10.21 
+Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. dated November 28, 2006 
+(13) 
+10.22 
+First Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. effective September 30, 2007. 
+(14) 
+10.23 
+Second Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Bank, N.A. effective November 22, 2011. 
+(18) 
+10.24 
+Third Amendment to Amended and Restated Revolving Credit and Security Agreement 
+(20) 
+10.25 
+License Agreement between Seiko Epson Corporation and TransAct dated May 17, 2004 (Pursuant to Rule 24b-2 under the Exchange Act, the Company has requested confidential treatment of portions of this exhibit deleted from the filed copy.) 
+(10) 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+(1) 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+(1) 
+101.INS 
+XBRL Instance Document. 
+(1) 
+101.SCH 
+XBRL Taxonomy Extension Schema Document. 
+(1) 
+101.CAL 
+XBRL Taxonomy Extension Calculation Linkbase Document. 
+(1) 
+101.DEF 
+XBRL Taxonomy Extension Definition Linkbase Document. 
+(1) 
+101.LAB 
+XBRL Taxonomy Extension Label Linkbase Document. 
+(1) 
+101.PRE 
+XBRL Taxonomy Extension Presentation Linkbase Document. 
+(1) 
+(1) 
+These exhibits are filed herewith. 
+(2) 
+These exhibits, which were previously filed with the Company’s Registration Statement on Form S-1 (No. 333-06895), are incorporated by reference. 
+(3) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1996, are incorporated by reference. 
+(4) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1997, are incorporated by reference. 
+(5) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed February 18, 1999, is incorporated by reference. 
+(6) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 1998, is incorporated by reference. 
+(7) 
+These exhibits, which were previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended March 25, 2000, are incorporated by reference. 
+(8) 
+This exhibit, which was previously filed with the Company’s Registration Statement on Form S-8 (No. 333-59570), is incorporated by reference. 
+(9) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003, is incorporated by reference. 
+(10) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004, is incorporated by reference. 
+(11) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, are incorporated by reference. 
+(12) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed June 1, 2005, is incorporated by reference. 
+(13) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, are incorporated by reference. 
+(14) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 1997, is incorporated by reference. 
+(15) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, is incorporated by reference. 
+(16) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, is incorporated by reference. 
+(17) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, is incorporated by reference. 
+(18) 
+This exhibit, which was previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2011, is incorporated by reference. 
+(19) 
+This exhibit, which was previously filed with the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2012, is incorporated by reference. 
+(20) 
+This exhibit, which was previously filed with the Company’s Current Report on Form 8-K filed September 11, 2012, is incorporated by reference. 
+(21) 
+These exhibits, which were previously filed with the Company’s Annual Report on Form 10-K for the year ended December 31, 2012, are incorporated by reference. 
+(x) 
+Management contract or compensatory plan or arrangement. 
+EXHIBIT LIST 
+The following exhibits are filed herewith. 
+Exhibit 
+23.1 
+Consent of PricewaterhouseCoopers LLP. 
+31.1 
+Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+31.2 
+Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 
+32.1 
+Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+32.2 
+Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
+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.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/filing_metadata.csv b/raw/filings/0001017303/2013/0001017303-14-000015/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..1d7c53ad2335b431312de5938dbf772a71feee70
--- /dev/null
+++ b/raw/filings/0001017303/2013/0001017303-14-000015/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
+0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2014-03-14,2013-12-31,2014-03-14T17:58:18.000Z,0001017303-14-000015,form10k2013.htm,"FORM 10K FOR THE YEAR ENDED DECEMBER 31, 2013",9042305,1,0,https://www.sec.gov/Archives/edgar/data/1017303/000101730314000015/form10k2013.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730314000015/,2013,2013,1
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/item1.txt b/raw/filings/0001017303/2013/0001017303-14-000015/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e5cbd6047d99e8ff095871518711ab1439a714cf
--- /dev/null
+++ b/raw/filings/0001017303/2013/0001017303-14-000015/item1.txt
@@ -0,0 +1,75 @@
+Item 1. Business. 
+The Company 
+TransAct Technologies Incorporated (“TransAct” or the “Company”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. 
+TransAct designs, develops and sells market-specific solutions, including printers, terminals, software and other products for transaction-based and other industries. These world-class products are sold under the Epic, EPICENTRAL TM , Ithaca® and Printrex® brand names. Known and respected worldwide for innovative designs and real-world service reliability, our thermal, inkjet and impact printers and terminals generate top-quality labels and transaction records such as receipts, tickets, coupons, register journals and other documents as well as printed logging and plotting of data. We focus on the following core markets: food safety, banking and point-of-sale (“POS”), casino and gaming, lottery, and Printrex (which serves the oil and gas, medical and emergency vehicle markets). We sell our products to original equipment manufacturers (“OEMs”), value-added resellers ("VARs"), selected distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. TransAct also provides world-class printer service, spare parts, accessories and printing supplies to its growing worldwide installed base of printers. Through our TransAct Services Group (“TSG”) we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the hospitality, banking, retail, casino and gaming, government and oil and gas exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the on-line demand for these products. We have one primary operating and global research and development and eastern region service center located in Ithaca, NY. In addition, we have a casino and gaming sales headquarters and western region service center in Las Vegas, NV, a satellite research and development office in San Jose, CA, a European sales and service center in the United Kingdom, a sales office located in Macau and three other sales offices located in the United States. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT , 06518, with a telephone number of (203) 859-6800. 
+On August 19, 2011, we completed the acquisition of Printrex, Inc. (“Printrex”) for $4,000,000 in cash and potential future contingent consideration. Printrex is a leading manufacturer of specialty printers primarily sold into the oil and gas exploration and medical and mobile markets. Printrex serves commercial and industrial customers primarily in the United States, Canada, Europe and Asia. This acquisition was completed to complement our existing product offerings. 
+Financial Information about Segments 
+We operate in one reportable segment, the design, development, assembly and marketing of transaction printers and terminals and providing related software, services, supplies and spare parts. 
+Products, Services and Distribution Methods 
+Printers and terminals 
+TransAct designs, develops, assembles and markets a broad array of transaction-based and specialty printers and terminals utilizing inkjet, thermal and impact printing technology for applications, primarily in the food safety, banking and POS, casino and gaming, lottery, oil and gas, medical and emergency vehicle markets. Our printers and terminals are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, paper cutting devices, paper handling capacities and cabinetry color. In addition to our configurable printers and terminals, we design and assemble custom printers for certain OEM customers. In collaboration with these customers, we provide engineering and manufacturing expertise for the design and development of specialized printers. 
+Food safety, banking and POS: During 2012 in an effort to address the Food Safety Modernization Act, we developed a food safety terminal, a hardware device that consists of a touchscreen and one or two thermal print mechanisms, that print easy-to-read expiration and "enjoy by" date labels to help restaurants effectively manage food spoilage. In the food safety market, we use an internal sales representative to manage sales of our terminals through distribution, as well as a dedicated internal sales force to solicit sales directly from end-users. 
+Our banking and POS printers include hundreds of optional configurations that can be selected to meet particular customer needs. We believe that this is a significant competitive strength, as it allows us to satisfy a wide variety of printing applications that our customers request. In the banking market, we sell printers that are used by banks, credit unions and other financial institutions to print receipts and/ or validate checks at bank teller stations. In the POS market, we sell several models of printers utilizing inkjet, thermal and impact printing technology. Our printers are used primarily by retailers in the restaurant (including fine dining, casual dining, and fast food), hospitality, and specialty retail industries to print receipts for consumers, validate checks, or print on linerless labels or other inserted media. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we primarily sell our products directly to end-user banks and financial institutions through the use of our internal sales force. 
+Lottery: We supply lottery printers to Lottomattica’s GTECH Corporation (“GTECH”), our largest customer and the world’s largest provider of lottery terminals. These printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. Sales of our lottery products are made directly to GTECH and managed by an internal sales representative. 
+Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals (“VLT’s”) and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos, racetracks (“racinos”) and other gaming venues worldwide. These printers utilize thermal printing technology and can print tickets or receipts in monochrome or two-color (depending upon the model), and offer various other features such as jam resistant bezels and a dual port interface that enables casinos to print coupons and promotions. In addition, we sell printers using thermal printing technology for use in non-casino establishments, including game types such as Amusements with Prizes (“AWP”), Skills with Prizes (“SWP”), Fixed Odds Betting Terminals (“FOBT”) and other off-premise gaming type machines around the world. We sell our products primarily to (1) slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through distributors (one in the United States, Australia and Asia, and one in Europe and Africa). We also maintain a dedicated internal sales force to solicit sales from slot manufacturers and casinos, as well as to manage sales through our distributors. 
+1 
+We have also gained traction from our software solution, the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that enables casino operators to create promotional coupons and marketing messages and print them in real-time at the slot machine. With EPICENTRAL TM , casinos will be able to utilize the system to create multiple promotions and incentives to either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. 
+Printrex: Printrex printers include wide format, rack mounted and vehicle mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. During 2012, we launched two new color printers for this market, the Printrex 920 and Printrex 980. The Printrex 920 is the first full-color printer designed from the ground up to perform in the adverse environment of a well logging truck or off-shore platform. Using thermal printer technology, it can print in black and white, or in full color using proprietary color paper without the need for inkjet cartridges or ribbons. The Printrex 980 is the fastest full color printer available for plotting continuous logs in the data centers of the large oil field service companies. This printer uses proprietary inkjet cartridges. In addition, we sell wide format thermal printers used to print test results in ophthalmology devices in the medical industry, as well as vehicle mounted printers used to print schematics and certain other critical information in emergency services vehicles. We primarily sell our Printrex products directly to oil field service and drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. We also maintain a dedicated internal sales force with a sales office located in Houston, Texas. 
+TSG: Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper, color thermal paper and other printing supplies), replacement parts, maintenance and repair services and testing services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, 24-hour guaranteed replacement product service called TransAct Xpress SM , and other repair services for our printers. Within the United States, we provide repair services through our eastern region service center in Ithaca, NY and our western region service center in Las Vegas, NV. Internationally, we provide repair services through our European service center located in Doncaster, United Kingdom, and through partners strategically located around the world. 
+We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all of our manufactured products and our services. 
+In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our online webstore www.transactsupplies.com . 
+Sources and Availability of Raw Materials 
+We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. Approximately 90% of our printer production is primarily through one third-party contract manufacturer in Asia and to a lesser extent three others in Asia. The remaining 10% of our products are assembled in our Ithaca, NY facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. 
+We procure component parts and subassemblies for use in the assembly of our products in Ithaca, NY. Critical component parts and subassemblies include inkjet, thermal and impact print heads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, LCD screens, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, purchases of component parts have declined while purchases of fully-assembled printers produced by our contract manufacturers have increased. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. 
+We currently buy substantially all of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer models, from one foreign contract manufacturer, and to a much lesser extent, three other foreign contract manufacturers. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have a supply agreement with our foreign contract manufacturers, our relationship with them remains strong and we have no reason to believe that they will discontinue their supply of thermal print mechanisms to us during 2014 or that their terms to us will be any less favorable than they have been historically. 
+Hewlett-Packard Company (“HP”) is the sole supplier of inkjet cartridges that are used in all of our banking inkjet printers. In addition, we also sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges that are compatible with the HP inkjet cartridge are available, the loss of the supply of HP inkjet cartridges could have a material adverse effect on both the sale of our inkjet printers and TSG consumable products. Our relationship with HP remains stable and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their terms to us will be materially different than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the banking and POS market, but also in other manufacturer’s printing devices across several other markets. 
+ZINK Imaging Inc. (“ZINK”) is the sole supplier of proprietary color thermal paper used in our Printrex 920 oil and gas printer. We have a supply agreement with ZINK to exclusively supply us with ZINK color thermal paper for the oil and gas industry at fixed prices through December 31, 2014. The loss of the supply of ZINK color thermal paper would have a material adverse effect on the sale of Printrex 920 printers and ZINK color thermal paper. 
+2 
+Canon, Inc. (“Canon”) is the sole supplier of inkjet cartridges and other consumable items (“Canon Consumables”) that are used in our Printrex 980 oil and gas printer. The loss of supply of Canon Consumables would have a material adverse effect on the sale of Printrex 980 printers and the Canon Consumables. We have a supply agreement with Canon to supply us with Canon Consumables until May 2017. Prices under this agreement were fixed through May 2013, but may be changed for the remainder of the agreement due to significant exchange rate fluctuations between the Japanese yen and the U.S. dollar. 
+Patents and Proprietary Information 
+TransAct relies on a combination of trade secrets, patents, employee and third party nondisclosure agreements, copyright laws and contractual rights to establish and protect its proprietary rights in its products. We hold 29 United States and 28 foreign patents and have 10 United States and 11 foreign patent applications pending pertaining to our products. The duration of these patents range from 4 to 16 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections relied upon by the Company to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. 
+Seasonality 
+Restaurants typically reduce purchases of new food safety equipment in the fourth quarter due to the increased volume of transactions in that holiday period. 
+Working Capital 
+Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+Certain Customers 
+GTECH has been our most significant customer. In December 2009, we signed a new five-year agreement effective November 20, 2009, with GTECH (the “GTECH Thermal Printer Agreement”). Under the terms of the agreement, we provide GTECH with their latest generation thermal lottery printers for various lottery applications. The terms of the agreement require that GTECH exclusively purchase all of its requirements for thermal on-line lottery printers from us and that we exclusively sell such printers to GTECH through January 2015. 
+Sales to GTECH and other customers representing 10% or more of our total net sales were as follows: 
+Year ended December 31, 
+2013 
+2012 
+2011 
+GTECH 
+12% 
+18% 
+26% 
+Customer A 
+12% 
+15% 
+13% 
+Backlog 
+Our backlog of firm orders was approximately $4,778,000 as of February 28, 2014, compared to $4,776,000 as of February 28, 2013. Based on customers’ current delivery requirements, we expect to ship our entire current backlog during 2014. 
+Competition 
+The market for transaction-based and specialty printing solutions is extremely competitive, and we expect such competition to continue in the future. We compete with a number of companies, many of which have greater financial, technical and marketing resources than us. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. 
+In the food safety market, we compete with Avery Dennison Corporation, Ecolab Inc. and Integrated Control Corp. We compete in this market based largely on our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+In the banking and POS market, our major competitor is Epson America, Inc., which holds a dominant market position of the POS markets into which we sell. We also compete, to a much lesser extent, with Transaction Printer Group (“TPG”), Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Resources, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources, lower costs attributable to higher volume production and sometimes offer lower prices than us. 
+In the casino and gaming market (consisting principally of slot machine and video lottery terminal transaction printing and promotional coupon printing), we compete with several companies including FutureLogic, Inc., Nanoptix, Inc., Custom Engineering SPA and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. 
+In the lottery market (consisting principally of on-line lottery transaction printing), we hold a leading position, based largely on our long-term purchase agreement with GTECH. We compete in this market based solely on our ability to provide specialized, custom-engineered products to GTECH. 
+In the Printrex market, we compete with the Imaging Systems Group, Inc. (“iSys”), Neuralog Inc., GSI Group and others. We compete in this market based largely on our ability to provide specialized, custom-engineered products. 
+The TSG business is highly fragmented, and we compete with numerous competitors of various sizes, including POS and internet resellers, depending on the geographic area. 
+3 
+Our strategy for competing in our markets is to continue to develop new products (hardware and software) and product line extensions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower product costs by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain inkjet, thermal and impact printing technology. If other technologies, or variations to existing technologies, were to evolve or become available to us, it is possible that we would incorporate these technologies into our products. Alternatively, if such technologies were to evolve or become available to our competitors, our products could become obsolete, which would have a significant negative impact on our business. 
+Research and Development Activities 
+Research, development, and engineering expenditures represent costs incurred in the experimental or laboratory sense aimed at discovery and/or application of new knowledge in developing a new product or process, or in bringing about significant improvement in an existing product or process. We spent approximately $4,065,000, $4,239,000 and $3,418,000 in 2013, 2012 and 2011, respectively, on engineering, design and product development efforts in connection with specialized engineering and design to introduce new hardware and software products and to customize or improve existing products. 
+Costs incurred in researching and developing a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheets until the product is available for sale to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs will be included in cost of sales over the estimated life of the product. During 2010 we began the development of EPICENTRAL TM, , which enables casino customers to print coupons and promotions at the slot machine. Unamortized development costs for such software were approximately $370,000 and $528,000 as of December 31, 2013 and 2012, respectively. The total amount charged to cost of sales for capitalized software development costs were approximately $199,000, $189,000 and $62,000 in 2013, 2012 and 2011, respectively. 
+Environment 
+We are not aware of any material noncompliance with federal, state and local provisions that have been enacted or adopted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment. 
+Employees 
+As of December 31, 2013, TransAct and our subsidiaries employed 139 persons, of whom 138 were full-time employees and 1 was a temporary employee. None of our employees are unionized, and we consider our relationships with our employees to be good. 
+Financial Information About Geographic Areas 
+For financial information regarding our geographic areas see Note 16 – Geographic Area Information in the Notes to the Consolidated Financial Statements. Risks related to our foreign operations are described in Item 1A below. 
+Trademarks, Service Marks and Copyrights 
+We own or have rights to trademarks, service marks, trade names and copyrights that we use in connection with the operation of our business, including our corporate names, logos and website names. Other trademarks, service marks and trade names appearing in this annual report on Form 10-K are the property of their respective owners. The trademarks we own include TransAct®, EPICENTRAL TM , Ithaca® and Printrex®. Solely for convenience, some of the trademarks, service marks, trade names and copyrights referred to in this annual report on Form 10-K are listed without the ©, ® and ™ symbols, but we will assert, to the fullest extent under applicable law, our rights to our trademarks, service marks, trade names and copyrights. 
+Available Information 
+We make available free of charge through our internet website, www.transact-tech.com , 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 as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). You may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. This information is also available at www.sec.gov. The reference to these website addresses does not constitute incorporation by reference of the information contained on the websites and should not be considered part of this document. 
+We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. This Code, which requires continued observance of high ethical standards such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our internet website. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/item13.txt b/raw/filings/0001017303/2013/0001017303-14-000015/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9dda5d300f48e96600fd4bb3101f49b818372286
--- /dev/null
+++ b/raw/filings/0001017303/2013/0001017303-14-000015/item13.txt
@@ -0,0 +1,2 @@
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information in response to this item will be contained in the Proxy Statement and is incorporated herein by reference.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/item9a.txt b/raw/filings/0001017303/2013/0001017303-14-000015/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..6f9834361e89eb75e4667fe6b6a0defc623e9115
--- /dev/null
+++ b/raw/filings/0001017303/2013/0001017303-14-000015/item9a.txt
@@ -0,0 +1,8 @@
+Item 9A. Controls and Procedures. 
+Attached as exhibits to this Form 10-K are certifications of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), which are required in accordance with Rule 13a-14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This “Controls and Procedures” section includes information concerning the controls and controls evaluation referred to in the certifications. 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2013, the Company, with the participation of its CEO and CFO conducted an evaluation of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on that evaluation, our CEO and CFO concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15 of the Exchange Act) were effective as of December 31, 2013. There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. 
+Management’s Annual Report on Internal Control Over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. 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. 
+Management assessed our internal control over financial reporting as of December 31, 2013. Management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“1992 COSO”). Based on our assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2013 
+The effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
\ No newline at end of file
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/rp_note.txt b/raw/filings/0001017303/2013/0001017303-14-000015/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391
diff --git a/raw/filings/0001017303/2013/0001017303-14-000015/rpt_disclosure.txt b/raw/filings/0001017303/2013/0001017303-14-000015/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e1dbbf986c6bee804dd08d162a4f131b65a96ce7
--- /dev/null
+++ b/raw/filings/0001017303/2013/0001017303-14-000015/rpt_disclosure.txt
@@ -0,0 +1,4 @@
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 
+The Company maintains policies that relate to the identification, review and approval of related party transactions. As part of a review of possible related person transactions, the Company annually distributes and collects questionnaires that solicit information about any direct or indirect transactions with the Company from each of our directors and officers. 
+Our Standards of Business Conduct require all directors, officers and employees to avoid any situation that involves an actual or apparent conflict of interest in personal and professional relationships or with their duty to, or with any interest of, the Company. Under our Standards of Business Conduct, situations that involve, or may reasonably be inferred to involve, a conflict between a director, officer or employee’s personal interests and the interests of the Company should be disclosed to the Chair of the Audit Committee. The Audit Committee is then responsible for reviewing the related party transaction. No related party transaction shall be approved or ratified if such transaction is contrary to the best interests of the Company. In determining whether to approve or ratify a related party transaction, the Audit Committee takes into account such factors as it deems appropriate, which may include whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the related person’s interest in the transaction . 
+From January 1, 2013 to the date of this proxy statement, there have not been any transactions subject to the Company’s related party transaction policy or of the type described in Item 404 of Regulation S-K, and currently no such transactions are proposed.
\ No newline at end of file
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/filing.txt b/raw/filings/0001520006/2011/0001193125-12-145249/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..5c28e6e05bd10ffc74c3859ce04f1397e4f9ecd1
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/filing.txt
@@ -0,0 +1,8395 @@
+10-K
+1
+d325766d10k.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 PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2011 
+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 001-34574
+Matador Resources Company 
+(Exact name of registrant as specified in its charter) 
+Texas 
+27-4662601 
+(State or other jurisdiction of 
+incorporation or organization) 
+(I.R.S. Employer 
+Identification No.) 
+5400 LBJ Freeway, Suite 1500 
+Dallas, Texas 75240 
+75240 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code: (972) 371-5200 
+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 
+New York Stock Exchange 
+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 ¨ No x 
+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 during the preceding 12 months (or for 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 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 
+¨ 
+Non-accelerated filer 
+x (Do not check if a smaller reporting company) 
+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 
+As of June 30, 2011, the registrant was a privately held company and not publicly traded. Accordingly, the market value of its common
+stock held by non-affiliates on such date cannot be reasonably determined. 
+As of March 30, 2012, there were 55,272,860
+shares of common stock outstanding. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+The information required by Part III of this annual report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to
+the 2012 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this annual report on Form 10-K relates. 
+Table of Contents 
+MATADOR RESOURCES COMPANY 
+FORM 10-K 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011 
+TABLE OF CONTENTS 
+Page 
+PART I 
+I TEM 1. 
+B USINESS . 
+3 
+I TEM 1A. 
+R ISK F ACTORS . 
+35 
+I TEM 1B. 
+U NRESOLVED S TAFF C OMMENTS . 
+57 
+I TEM 2. 
+P ROPERTIES . 
+57 
+I TEM 3. 
+L EGAL P ROCEEDINGS . 
+57 
+I TEM 4. 
+M INE S AFETY D ISCLOSURES . 
+57 
+PART II 
+I TEM 5. 
+M ARKET FOR R EGISTRANT ’ S C OMMON E QUITY , R ELATED S TOCKHOLDER
+M ATTERS AND I SSUER P URCHASES OF E QUITY S ECURITIES . 
+58 
+I TEM 6. 
+S ELECTED F INANCIAL D ATA . 
+60 
+I TEM 7. 
+M ANAGEMENT ’ S D ISCUSSION AND A NALYSIS OF F INANCIAL C ONDITION
+AND R ESULTS OF O PERATIONS . 
+64 
+I TEM 7A. 
+Q UANTITATIVE AND Q UALITATIVE D ISCLOSURES ABOUT M ARKET R ISK
+. 
+87 
+I TEM 8. 
+F INANCIAL S TATEMENTS AND S UPPLEMENTARY D ATA . 
+90 
+I TEM 9. 
+C HANGES IN AND D ISAGREEMENTS W ITH A CCOUNTANTS ON A CCOUNTING
+AND F INANCIAL D ISCLOSURE . 
+90 
+I TEM 9A. 
+C ONTROLS AND P ROCEDURES . 
+90 
+I TEM 9B. 
+O THER I NFORMATION . 
+90 
+PART III 
+I TEM 10. 
+D IRECTORS , E XECUTIVE O FFICERS AND C ORPORATE 
+G OVERNANCE . 
+91 
+I TEM 11. 
+E XECUTIVE C OMPENSATION . 
+91 
+I TEM 12. 
+S ECURITY O WNERSHIP OF C ERTAIN B ENEFICIAL O WNERS AND M ANAGEMENT
+AND R ELATED S TOCKHOLDER M ATTERS . 
+91 
+I TEM 13. 
+C ERTAIN R ELATIONSHIPS AND R ELATED T RANSACTIONS , AND D IRECTOR
+I NDEPENDENCE . 
+91 
+I TEM 14. 
+P RINCIPAL A CCOUNTING F EES AND S ERVICES . 
+91 
+PART IV 
+I TEM 15. 
+E XHIBITS AND F INANCIAL S TATEMENT S CHEDULES . 
+92 
+i 
+Table of Contents 
+Cautionary Note Regarding Forward-Looking Statements 
+Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable
+U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by
+the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,”
+“predict,” “project,” “should” or other similar words. 
+By their very nature, forward-looking
+statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity
+and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions,
+uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them,
+the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in
+this report and in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: 
+• 
+our business strategy; 
+• 
+our reserves; 
+• 
+our technology; 
+• 
+our cash flows and liquidity; 
+• 
+our financial strategy, budget, projections and operating results; 
+• 
+our oil and natural gas realized prices; 
+• 
+the timing and amount of future production of oil and natural gas; 
+• 
+the availability of drilling and production equipment; 
+• 
+the availability of oil field labor; 
+• 
+the amount, nature and timing of capital expenditures, including future exploration and development costs; 
+• 
+the availability and terms of capital; 
+• 
+our drilling of wells; 
+• 
+government regulation and taxation of the oil and natural gas industry; 
+• 
+our marketing of oil and natural gas; 
+• 
+our exploitation projects or property acquisitions; 
+• 
+our costs of exploiting and developing our properties and conducting other operations; 
+• 
+general economic conditions; 
+• 
+competition in the oil and natural gas industry; 
+1 
+Table of Contents 
+• 
+the effectiveness of our risk management and hedging activities; 
+• 
+environmental liabilities; 
+• 
+counterparty credit risk; 
+• 
+developments in oil-producing and natural gas-producing countries; 
+• 
+our future operating results; 
+• 
+estimated future reserves and the present value thereof; and 
+• 
+our plans, objectives, expectations and intentions contained in this report that are not historical. 
+Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us
+on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition. 
+You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could
+differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular
+forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially
+affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements. 
+2 
+Table of Contents 
+PART I 
+Item 1. 
+Business. 
+In this
+Annual Report on Form 10-K, references to “we,” “our,” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador
+Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC Energy
+Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its
+corporate name to Matador Resources Company. 
+Unless the context otherwise requires, the term “common stock”
+refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only
+class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of
+our initial public offering. 
+For certain oil and natural gas terms used in this report, please see the “Glossary
+of Oil and Natural Gas Terms” included in this report. 
+General 
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources
+in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in
+northwest Louisiana and east Texas. We expect the majority of our near-term capital expenditures will focus primarily on increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the Eagle Ford shale play
+will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. In addition to these primary operating areas, we have acreage positions in southeast New Mexico and west Texas
+and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify new oil and natural gas prospects. 
+We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E. King, Co-Founder and Vice
+President, Geophysics and New Ventures. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was
+later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in
+an all cash transaction for an enterprise value of approximately $388.5 million. 
+Since our first well in 2004, we have
+drilled or participated in drilling 236 wells through December 31, 2011, including 106 Haynesville and nine Eagle Ford wells. From December 31, 2008 through December 31, 2011, we grew our estimated proved reserves from 20.0 Bcfe to
+193.2 Bcfe. At December 31, 2011, 34% of our estimated proved reserves were proved developed reserves, 12% of our estimated proved 
+3 
+Table of Contents 
+reserves were oil and 88% of our estimated proved reserves were natural gas. Our average daily production for the year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of
+natural gas per day and 422 Bbl of oil per day as compared to an average daily production of 23.6 MMcfe per day, including 23.0 MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31, 2010. We have achieved this
+growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses) from $1.16 per Mcfe for the year ended December 31, 2009, to $0.88 per Mcfe for the year ended
+December 31, 2011, or a decrease of approximately 24%. 
+The following table presents certain summary data for each of our
+operating areas as of and for the year ended December 31, 2011: 
+Producing 
+Wells 
+Total Identified 
+Drilling Locations (1) 
+Estimated Net Proved 
+Reserves 
+Avg. Daily 
+Production 
+(MMcfe) 
+Net Acreage 
+Gross 
+Net 
+Gross 
+Net 
+Bcfe (2) 
+% 
+Developed 
+South Texas: 
+Eagle Ford 
+28,673 
+9.0 
+7.3 
+193.0 
+153.1 
+27.9 
+37.9 
+3.3 
+Austin Chalk 
+14,849 
+– 
+– 
+16.0 
+16.0 
+– 
+– 
+– 
+Area Total (3) 
+28,673 
+9.0 
+7.3 
+209.0 
+169.1 
+27.9 
+37.9 
+3.3 
+NW Louisiana/E Texas: 
+Haynesville 
+14,527 
+106.0 
+11.6 
+524.0 
+102.9 
+150.4 
+26.4 
+32.3 
+Cotton Valley (4) 
+23,054 
+108.0 
+71.7 
+60.0 
+36.0 
+14.2 
+100.0 
+6.5 
+Area Total (5) 
+25,339 
+214.0 
+83.3 
+584.0 
+138.9 
+164.6 
+32.7 
+38.8 
+SW Wyoming, NE Utah, SE Idaho 
+135,862 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+6,658 
+13.0 
+5.7 
+– 
+– 
+0.7 
+100.0 
+0.2 
+Total 
+196,532 
+236.0 
+96.3 
+793.0 
+308.0 
+193.2 
+33.7 
+42.3 
+(1) 
+These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is
+calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At December 31, 2011, these identified drilling locations included 8 gross and 8 net locations to
+which we have assigned proved undeveloped reserves in the Eagle Ford and 102 gross and 17 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling
+locations in the Austin Chalk or Cotton Valley at December 31, 2011. 
+(2) 
+These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell & Associates, Inc.
+(3) 
+Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation.
+Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for south Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
+(4) 
+Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in
+Zavala County, Texas. 
+(5) 
+Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville formation.
+Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for northwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
+At December 31, 2011, our properties included approximately 51,000 gross acres and 29,000 net acres in the
+Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In
+addition, portions of the acreage are also prospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to produce predominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by
+production or not burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Ford position and from November 2010 through December 2011, we completed our first seven operated wells in this area. 
+4 
+Table of Contents 
+At December 31, 2011, we have identified 193 gross locations and 153 net locations for
+potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from
+nearby wells based on available public data, drilling densities observed from other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among others. At
+December 31, 2011, we have identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additional locations
+for drilling. At December 31, 2011, these identified potential future drilling locations in the Eagle Ford shale play included 8 gross and 8 net locations to which we have assigned proved undeveloped reserves. 
+In addition, at December 31, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in
+northwest Louisiana and east Texas. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data and
+information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 5,500 of our net acres are located in what we believe is the core area of the play. We believe the core area of
+the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Over 90% of our Haynesville acreage is held by production from the
+Haynesville or other formations, and we believe much of it is also prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle
+Bossier shale play. 
+At December 31, 2011, we have identified 524 gross locations and 103 net locations for potential
+future drilling in our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from our producing
+Haynesville wells and other nearby wells based on available public data, drilling densities observed from other operators including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established
+by regulatory authorities and surface conditions, among others. Of the 524 gross locations identified for future drilling, 449 of these locations (52 net locations) have been identified within the 5,500 net acres that we believe are located in the
+core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2011, these identified potential future
+drilling locations included 102 gross and 17 net locations in the Haynesville shale play to which we have assigned proved undeveloped reserves. 
+We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utah and Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gas
+shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September
+2011 and completed drilling and coring operations on this well in November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the well logs and awaiting results from various core analysis tests. In
+addition, we have leasehold interests in the Delaware and Midland Basins in southeast New Mexico and west Texas where we are developing new oil and natural gas prospects. 
+We are active both as an operator and as a co-working interest owner with larger industry participants including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and
+others. Of the 236 gross wells we have drilled or participated in drilling, we drilled approximately 40% of 
+5 
+Table of Contents 
+these wells as the operator, although our working interest is small in many of the non-operated wells, particularly in the Haynesville shale. At December 31, 2011, we were the operator for
+approximately 85% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in that core area is operated by a
+subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in southwest Wyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in southeast New Mexico and west Texas. 
+We are a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal Dutch Shell plc and several
+other companies in the Haynesville shale and with EOG Resources, Inc. in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation governing the Haynesville operations underlying our
+Elm Grove/Caspiana properties in southern Caddo Parish, Louisiana and a joint operating agreement with EOG Resources, Inc. governing all operations on our joint acreage in Atascosa County, Texas. We have not entered into a joint operating agreement
+with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our working interest is small, we do not always enter into formal operating agreements with the
+operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices. 
+Where we do have joint operating agreements with affiliates of Chesapeake Energy Corporation and EOG Resources, Inc., these agreements call for significant penalties should we elect not to participate in
+the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s
+future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have
+the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose. 
+While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to
+maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations. We review
+these locations with Netherland, Sewell & Associates, Inc., our independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.
+6 
+Table of Contents 
+The following table presents our 2012 anticipated capital expenditure budget of
+approximately $313.0 million segregated by target formation and by whether the wells are expected to be exploration or development wells. 
+2012 Anticipated Drilling 
+2012 Anticipated Capital 
+Expenditure Budget 
+Gross Wells (1) 
+Net Wells (1) 
+(in millions) (2) 
+Exploration 
+Development 
+Total 
+Exploration 
+Development 
+Total 
+Exploration 
+Development 
+Total 
+South Texas 
+Eagle Ford 
+13.0 
+15.0 
+28.0 
+11.8 
+13.8 
+25.6 
+$ 
+122.3 
+$ 
+134.9 
+$ 
+257.2 
+Austin Chalk 
+2.0 
+– 
+2.0 
+2.0 
+– 
+2.0 
+11.3 
+– 
+11.3 
+Area Total 
+15.0 
+15.0 
+30.0 
+13.8 
+13.8 
+27.6 
+133.6 
+134.9 
+268.5 
+NW Louisiana / E Texas 
+Haynesville 
+6.0 
+19.0 
+25.0 
+0.2 
+1.3 
+1.5 
+1.9 
+11.6 
+13.5 
+Cotton Valley 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+6.0 
+19.0 
+25.0 
+0.2 
+1.3 
+1.5 
+1.9 
+11.6 
+13.5 
+SW Wyoming, NE Utah, SE Idaho 
+1.0 
+– 
+1.0 
+0.4 
+– 
+0.4 
+2.5 
+– 
+2.5 
+(3) 
+SE New Mexico, West Texas 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Other 
+N/A 
+N/A 
+N/A 
+N/A 
+N/A 
+N/A 
+25.0 
+3.5 
+28.5 
+(4) 
+Total 
+22.0 
+34.0 
+56.0 
+14.4 
+15.1 
+29.5 
+$ 
+163.0 
+$ 
+150.0 
+$ 
+313.0 
+(1) 
+Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a non-operator in 2012.
+(2) 
+Our capital expenditure budget is based on our net working interests in the properties. 
+(3) 
+We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in the drilling of this well.
+(4) 
+Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast New Mexico and west Texas.
+Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration,
+development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in
+the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production.
+While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results. Since at December 31, 2011, over 90% of our Haynesville acreage was
+held by production and approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013, we possess the financial flexibility to allocate our capital when we believe it is economical and
+justified. 
+Recent Developments 
+At March 30, 2012, we had drilled an aggregate of 15 Eagle Ford horizontal wells in south Texas as operator, including 10 wells in LaSalle County, one well in Dimmit County, three wells in Karnes
+County and one well in DeWitt County. Thirteen of these wells have been completed and are producing and two of these wells are awaiting completion. At March 30, 2012, we had two contracted drilling rigs operating in the Eagle Ford play in south
+Texas: one in LaSalle County and one in Karnes County. 
+7 
+Table of Contents 
+On February 7, 2012, we completed our initial public offering of 14,883,334 shares of
+common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold by us and the selling shareholders pursuant to the partial
+exercise of the underwriters’ over-allotment option on March 7, 2012. 
+Between November 2011 and February 2012, we
+entered into various costless collars to mitigate our exposure to oil price volatility and enhance predictability of our cash flows. As of March 30, 2012, we had hedged a total of 1,180,000 Bbls of oil for 2012, 1,260,000 Bbls of oil for 2013
+and 120,000 Bbls of oil for 2014. For 2012, these collars have a weighted average price floor of $90.51 per Bbl and a weighted average price ceiling of $109.84 per Bbl. For 2013, these collars have a weighted average price floor of $87.14 per Bbl
+and a weighted average price ceiling of $110.26 per Bbl. For 2014, these collars have a weighted average price floor of $90.00 per Bbl and a weighted average price ceiling of $114.90 per Bbl. 
+In December 2011, we amended and restated our senior secured revolving credit agreement. This amendment increased the maximum facility
+amount from $150.0 million to $400.0 million. Borrowings are limited to the lesser of $400.0 million or the borrowing base, which was $125.0 million as of March 30, 2012. 
+In November and December 2011, we completed three operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H in northeastern LaSalle County, Texas. During initial flow tests on these wells,
+the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at
+approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three wells were turned to sales in late December 2011. We are the operator and have a 100% working interest in these three wells. 
+Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson
+and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the Eagle Ford play. We believe that the acreage in Wilson and Gonzales Counties and
+a portion of DeWitt County will be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. We paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the acreage
+(approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the
+operator. 
+Principal Areas of Interest 
+Our focus since inception has been the exploration for oil and natural gas in unconventional resource plays with a particular focus over the last few years in the Haynesville shale play and more recently
+in the Eagle Ford shale play. Our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance
+the risk profile of our prospects, as well as to explore for more conventional targets in addition to the unconventional resource plays. 
+At December 2011, our principal areas of interest consisted of (1) the Eagle Ford shale play in south Texas, (2) the Haynesville shale play, including the Middle Bossier shale play, as well as
+the traditional Cotton Valley and Hosston (Travis Peak) formations in northwest Louisiana and east Texas, (3) the Meade Peak shale play in southwest Wyoming and the adjacent areas of Utah and Idaho and (4) southeast New Mexico and west
+Texas, including the Delaware and Midland Basins. 
+8 
+Table of Contents 
+South Texas 
+Eagle Ford Shale and Other Formations 
+About 8% of our daily production, or
+3.3 MMcfe per day, including 331 Bbls of oil per day and 1.3 MMcf of natural gas per day, was produced from the Eagle Ford shale in south Texas for the year ended December 31, 2011. The Eagle Ford contributed approximately 78% of our daily oil
+production and about 3% of our daily natural gas production for 2011. For the month of December 2011, about 13% of our daily production, or 5.6 MMcfe per day, including 706 Bbls of oil per day and 1.3 MMcf per day, was produced from the Eagle Ford.
+During December 2011, the Eagle Ford contributed 91% of our daily oil production and about 4% of our daily natural gas production. At December 31, 2011, approximately 14% of our proved reserves, or 27.9 Bcfe, was attributable to the Eagle Ford,
+including approximately 3.6 million Bbls of oil and 6.1 Bcf of natural gas. Our Eagle Ford proved reserves at December 31, 2011 comprised approximately 96% of our proved oil reserves and approximately 4% of our proved natural gas reserves.
+The present value discounted at 10% for our proved reserves in the Eagle Ford at December 31, 2011 was $130.2 million, or about 52% of the PV-10 for our total proved reserves of $248.7 million. We anticipate that the percentage of our daily
+production and reserves attributable to the Eagle Ford shale will grow in 2012 as we intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle
+Ford play in an effort to grow the oil and liquids component of our production and reserves. 
+The Eagle Ford shale extends
+across portions of south Texas from the Mexican border into east Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale, in places transitioning to an organic, argillaceous
+lime-mudstone. It lies between the deeper Buda limestone and the shallower Austin Chalk formation. Most, if not all, of the oil found in the Austin Chalk and Buda formations is generally believed to be sourced from the Eagle Ford shale. In the
+prospective areas for the Eagle Ford shale, the interval averages 200 feet thick, is found at depths ranging from as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the play is overpressured. The Eagle Ford
+shale has a total organic carbon content of 1% to 7% that is comparable to the Haynesville shale, and is generally porous, with core-measured porosities ranging between 4% and 14%. 
+Along the entire length of the Eagle Ford trend the structural dip of the formation is consistently down to the south with relatively
+few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the formation is shallow, it is less thermally mature and therefore more oil prone,
+and as it gets deeper and becomes more thermally mature, the Eagle Ford shale is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet gas with condensate. We
+believe that approximately 85% of our Eagle Ford acreage lies within those portions of the Eagle Ford shale that are prone to produce oil or wet gas with condensate. 
+Most of the current Eagle Ford shale activity is concentrated in Atascosa, Bee, DeWitt, Dimmit, Frio, Gonzales, Karnes, LaSalle, Lavaca, Live Oak, Maverick, McMullen, Webb, Wilson and Zavala Counties in
+south Texas. The first horizontal wells drilled specifically for the Eagle Ford shale were drilled in 2008, leading to a discovery in LaSalle County. Since then, the play has expanded significantly across a large portion of south Texas. 
+Publicly available information indicates that operators are typically drilling 3,500 to 7,000 feet horizontal laterals and applying
+hydraulic fracture stimulation in multiple stages along the full length of the horizontal laterals to complete the wells and establish production. Although production rates vary across the 
+9 
+Table of Contents 
+different areas of the play, initial production rates in the oil areas have been reported as high as 1,000 to 1,500 Bbls of oil per day with varying amounts of associated natural gas. In the
+natural gas areas of the Eagle Ford play, initial production rates as high as 5.0 to 15.0 MMcfe per day have been reported with varying amounts of associated oil and liquids. 
+At December 31, 2011, our aggregate leasehold interests consisted of approximately 51,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle,
+Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe portions of this acreage are also prospective for the Austin Chalk, Buda, Olmos and other formations, from which we expect to produce predominantly oil and liquids. In particular,
+the Austin Chalk formation, which is a naturally fractured carbonate ranging in thickness from 200 to 400 feet, has produced from several fields on or nearby portions of our acreage. Our Zavala County acreage, for example, is located within the
+historic Pearsall (Austin Chalk) field. 
+We believe that approximately 85% of our Eagle Ford acreage is prospective
+predominantly for oil and liquids. At December 31, 2011, we owned a 100% working interest in approximately 26,000 gross acres and 23,000 net acres in Dimmit, Gonzales, Karnes, LaSalle, Webb, Wilson and Zavala Counties and a 50% working interest
+in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of this acreage. We also owned an approximate 21% working interest in approximately 22,000 gross acres in Atascosa County operated by EOG Resources, Inc. At
+December 31, 2011, approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013. 
+At December 31, 2011, we had drilled and completed seven Eagle Ford wells on our operated properties. All of these wells were producing to sales, although four of these wells were initially placed on
+production in late December. At December 31, 2011, we had also participated in two Eagle Ford wells with EOG Resources, Inc. as operator, on the Atascosa County acreage. Our first operated Eagle Ford horizontal well, the JCM Jr. Minerals #1H in
+southern LaSalle County along the Edwards Reef, was completed in November 2010. First sales of oil and natural gas began from this well in late January 2011, and during December 2011, the well produced at an average daily rate of approximately 0.5
+MMcf of natural gas and 9 Bbls of condensate per day, and through December 31, 2011, had produced a total of approximately 430 MMcf of natural gas and 11,200 Bbls of condensate. Our second operated Eagle Ford horizontal well, the Martin Ranch
+#1H in northeastern LaSalle County, was completed in January 2011 and tested approximately 1,200 Bbls of oil per day during an initial flow test. First sales of oil and natural gas from this well began in late March at approximately 700 Bbls of oil
+and 350 Mcf of natural gas per day. During December 2011, the well produced at an average daily rate of approximately 330 Bbls of oil and 0.6 MMcf of natural gas per day, and through December 31, 2011, had produced a total of 117,000 Bbls of
+oil and 144 MMcf of natural gas. 
+Our third operated Eagle Ford horizontal well, the Affleck #1H, was completed in February
+2011 in eastern Dimmit County, Texas, and tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per day during an initial flow test. During December 2011, the well produced at an average daily rate of 0.8 MMcf of natural gas and 38
+Bbls of oil per day. In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H in DeWitt County, Texas. This well tested at approximately 2.7 MMcf of natural gas and 1,040 Bbls of condensate per day during an
+initial flow test. The Lewton well began producing to sales in late December 2011. 
+In November and December 2011, we
+completed three additional operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H, in northeastern LaSalle County, Texas. During initial flow tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and
+1.8 MMcf of 
+10 
+Table of Contents 
+natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6
+MMcf of natural gas per day. All three wells were turned to sales in late December 2011. 
+Between March and July 2011, we
+acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We paid approximately $31.5 million to acquire this
+acreage. We currently own a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net
+acres) in Karnes, Wilson and Gonzales Counties and are the operator. At December 31, 2011, we had drilled and completed only one well on this acreage, the Lewton #1H in DeWitt County. 
+We will pay 100% of the costs to drill and complete the first six wells drilled on the acreage in DeWitt County. We will have an 85%
+working interest in these six wells until we have recovered all of our acquisition, drilling and completion costs from each well, at which time Orca’s working interest will increase to 50%. When the cumulative production from each of the first
+six wells reaches 500,000 BOE, on a well-by-well basis, then Orca’s working interest in that well increases to 55%. If the cumulative production from each of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s
+working interest in that well will increase to 70%. Both we and Orca will own a 50% working interest in all subsequent wells drilled after the first six wells on the acreage in DeWitt County. 
+We will have a 100% working interest in the first five wells drilled on the acreage in Karnes, Wilson and Gonzales Counties. When we have
+recovered all of our acquisition, drilling and completion costs from each of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in these wells. In addition, Orca retains a one-time election for a short
+period of time after we complete these first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchase price equal to 25% of our costs to acquire the acreage in Karnes, Wilson and
+Gonzales Counties. 
+At March 30, 2012, we had drilled an aggregate of 15 Eagle Ford horizontal wells in south Texas as
+operator, including 10 wells in LaSalle County, one well in Dimmit County, three wells in Karnes County and one well in DeWitt County. Thirteen of these wells have been completed and are producing and two of these wells are awaiting completion. At
+March 30, 2012 we had two contracted drilling rigs operating in the Eagle Ford play in south Texas: one in LaSalle County and one in Karnes County. We are not currently experiencing difficulties in securing completion, and particularly hydraulic
+fracturing services, for our newly drilled wells, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and
+completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors – The Unavailability or High Cost of Drilling Rigs, Completion
+Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could
+Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+We experienced
+temporary pipeline interruptions from time to time during 2011 associated with natural gas production from our Eagle Ford wells and have been required to either shut in wells for brief periods or to flare some of the natural gas we produce. At March
+30, 2012, we were experiencing pipeline capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the natural gas we are producing there as a result. We believe that these pipeline interruptions and
+capacity 
+11 
+Table of Contents 
+constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days.
+If we were required to shut in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors
+– The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Agreements Would
+Have a Material Adverse Effect on Our Revenue.” 
+In addition to the Eagle Ford potential on our acreage, we believe that
+approximately 24,000 gross acres and 15,000 net acres in south Texas are prospective primarily for the Austin Chalk formation, which has historically been targeted by operators in south Texas. We have not yet drilled an Austin Chalk well, and
+although we believe that other prospective well locations exist on this acreage, we have only included 16 gross and net well locations in our total identified drilling locations at December 31, 2011. 
+Northwest Louisiana and East Texas 
+At December 31, 2011, most of our production and proved reserves was attributable to our acreage in northwest Louisiana and east Texas. For the year ended December 31, 2011, about 76% of our
+daily production, or 32.3 MMcfe per day, was produced from the Haynesville shale, with another 15%, or 6.5 MMcfe per day, produced from the Cotton Valley and other shallower formations in this area. At December 31, 2011, approximately
+78% of our proved reserves, or 150.4 Bcfe, were attributable to the Haynesville shale underlying this acreage with another 7% of our proved reserves, or 14.2 Bcfe, associated with the Cotton Valley and shallower formations. In addition, we are
+evaluating the Bossier shale play which is generally encountered above the Haynesville shale and below the Cotton Valley formation. 
+We operate all of our Cotton Valley and shallower production under this acreage, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the
+Haynesville play. Of the approximately 5,500 net acres that we consider to be in the core area of the Haynesville play, we operate about 22% of that acreage. 
+In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at
+$2.13 per MMBtu. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improved substantially from these levels or unless the costs to drill and complete these
+wells were also to decline substantially from their recent levels. See “Risk Factors – Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the
+Occurrence or Timing of Their Drilling.” 
+Haynesville and Middle Bossier Shales 
+The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above
+the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout northwest Louisiana and east Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and
+Shelby Counties in Texas. The Haynesville shale has a typical thickness ranging from 100 to 300 feet. Total organic carbon ranges from 0.5% to 5.0%, with core-measured porosities from 3% to 15%. The Haynesville shale produces primarily dry natural
+gas with almost no associated liquids. 
+12 
+Table of Contents 
+The oil and natural gas industry has focused significant attention on the Haynesville shale
+play over the last several years. Operators are typically drilling 4,500 to 5,000 feet horizontal laterals and applying hydraulic fracture stimulation in multiple stages along the entire length of the horizontal laterals to complete the wells and
+establish production. Although initial production rates vary widely across the play, initial production rates as high as 20.0 to 25.0 MMcf per day of natural gas have been reported by operators from horizontal wells drilled and completed in the
+Haynesville shale. 
+The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle
+Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics to the deeper
+Haynesville shale. Typically, the Middle Bossier shale is found at depths ranging from 500 to 800 feet shallower than the Haynesville shale, has a typical thickness ranging from 150 to 300 feet, has core-measured porosities ranging between 5% and
+14%, and total organic carbon values between 0.5% and 4%. Although there is some overlap between the Bossier and Haynesville shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation.
+At December 31, 2011, we had leasehold and mineral interests in approximately 23,000 gross and 15,000 net acres prospective
+for the Haynesville shale. Portions of our acreage are located in Caddo, DeSoto, Bossier and Red River Parishes, Louisiana and in Harrison County, Texas. This acreage includes approximately 5,500 net acres in what we believe is the core area of the
+play. Over 90% of our Haynesville acreage is held by production and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that
+approximately 1,700 net acres are prospective for the Middle Bossier play as well. We have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations exist on this acreage, we have not yet included any
+Middle Bossier locations in our identified drilling locations at December 31, 2011. 
+Within the 5,500 net acres that we
+believe to be in the core area of the Haynesville shale play, we are the operator in two sections where we have working interests of 95% and 100% in all wells to be drilled. In October 2010, as operator, we drilled and completed our L.A. Wildlife H
+#1 horizontal Haynesville well in the section in which we have a 95% working interest and on December 31, 2010 first sales of natural gas began from this well. During December 2011, the well produced at an average daily rate of approximately
+8.7 MMcf of natural gas per day, and through December 31, 2011, had produced a total of approximately 3.4 Bcf of natural gas. In March 2011, we completed our operated Williams 17 H #1 horizontal Haynesville well on the second section where we
+have a 100% working interest. During December 2011, this well produced at an average daily rate of 3.9 MMcf of natural gas per day and, through December 31, 2011, had produced approximately 1.8 Bcf of natural gas. We began producing both of
+these wells at a constrained rate of about 10.0 MMcf of natural gas per day. We have identified 12 gross and approximately 12 net potential additional Haynesville locations that we may drill and operate in the future in these two sections.
+The remainder of our acreage in the core area of the Haynesville shale play, about 4,300 net acres, is operated by other
+companies. Just over half of our non-operated Haynesville acreage in this area of the play results from a transaction with a subsidiary of Chesapeake in July 2008. The remainder of our non-operated Haynesville acreage is attributable to leasehold
+interests that we hold in approximately 87 sections in Caddo, DeSoto, Bossier and Red River Parishes. Our working interests in the Haynesville wells in these sections range from less than 1% to more than 30%. At December 31, 2011, our
+production from these non-operated Haynesville wells averaged approximately 22 MMcfe per day. 
+13 
+Table of Contents 
+We do not plan to drill any operated Haynesville wells in 2012, but we have budgeted capital
+expenditures of approximately $13 million for our anticipated participation in approximately 25 gross (1.5 net) non-operated wells that may be drilled in order to hold expiring acreage or that may be proposed in multi-well development programs to
+evaluate optimal well spacing. 
+Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations 
+Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in northwest
+Louisiana and east Texas were attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in northwest Louisiana and east
+Texas. 
+All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in northwest Louisiana,
+approximately 10,000 gross and net acres at December 31, 2011, is held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to
+discovery of the Haynesville shale. The Cotton Valley formation is a low permeability gas sand that ranges in thickness from 200 to 300 feet and has porosities ranging from 6% to 10%. 
+In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. in our Elm Grove/Caspiana properties,
+in DeSoto Parish and commenced sales of natural gas from this well. Prior to this time, we had only drilled and completed vertical Cotton Valley and Hosston wells on these properties. During December 2011, this well produced at an average daily rate
+of approximately 1.6 MMcf of natural gas per day and through December 31, 2011, had produced a total of approximately 950 MMcf of natural gas. We are the operator and have a 100% working interest in this well. We have identified 60 gross and 36
+net additional drilling locations for future Cotton Valley horizontal wells in our Elm Grove/Caspiana properties. We do not plan to drill any of these locations in 2012. As all of this acreage is held by existing production, we expect to allocate
+the majority of our near-term capital expenditures primarily to exploration and development of our Eagle Ford shale acreage in south Texas. 
+We also continue to hold the shallow rights by existing production or by leases that are still in their primary terms in our central and southwest Pine Island, Longwood, Woodlawn and other prospect areas
+in northwest Louisiana and east Texas. At December 31, 2011, we held an estimated 11,500 net leasehold and mineral acres by existing production in these areas. 
+Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale 
+The Meade Peak shale is an organic-rich source rock that has sourced much of the oil and natural gas in conventional reservoirs in the western Wyoming and eastern Utah area. The Meade Peak shale has an
+observed shale thickness of 70 to 350 feet, total organic carbon of 3% to 7% and vitrinite reflectance values ranging from 1.8% to 2.7%. The Meade Peak shale is encountered at drill depths of 3,000 to 14,000 feet, with the majority of our acreage in
+the depth range of 3,000 to 10,000 feet. The shale has been penetrated by over 100 wells in the area, most of which have natural gas shows. Seismic and subsurface data show distinct, stacked thrust plates with areas of sediment prospective for
+natural gas. 
+At December 31, 2011, we had assembled approximately 144,000 gross, or approximately 136,000 net, acres in
+southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploratory prospect targeting the Meade Peak shale. The majority of this acreage, with lease terms of five to ten years, has been acquired by us within the past
+four to five years, and we are the operator of this prospect. 
+14 
+Table of Contents 
+We believe there have been no previous attempts to drill horizontally or to hydraulically
+fracture the Meade Peak shale in this area. Our focus to date has been to confirm the structure of the Meade Peak shale, understand its characteristics and evaluate its potential. We have gathered well log data in the area and studied the
+petrophysical characteristics. In addition, we have purchased 2-D seismic data and have worked with a structural geologist that has experience in the immediate area to better understand the area’s tectonic history. 
+We have entered into a participation and joint operating agreement with other parties covering the initial exploration efforts and, if
+successful, the future development of this acreage. We began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feet above
+the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations on this well in
+November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the well logs and awaiting results from various core analysis tests. 
+Approximately 102,000 gross, or approximately 93,000 net, acres in this prospect are scheduled to expire at various times during 2012. Although we plan to seek extensions on some of this acreage, certain
+leases, particularly those taken on state lands, do not offer the opportunity for automatic extension, and we will be required to obtain new leases on these lands should we desire and be able to do so. We expect that a significant portion of the
+93,000 net acres will be allowed to expire during 2012, while we and our partners continue to evaluate the results from our initial test well and plan for its completion and further testing. We have no production and no proved reserves attributable
+to this acreage at December 31, 2011. 
+Southeast New Mexico and West Texas — Delaware and Midland Basins
+The Delaware and Midland Basins are mature exploration and production provinces with extensive developments in a wide
+variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in these basins has focused on relatively conventional reservoir targets, but we believe the combination of advanced
+formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of these basins. 
+One example of such an opportunity appears to be the so-called “Wolf-Bone” play of the Delaware Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp
+formations span several thousand feet of stacked shales, sandstones, limestones and dolomites representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural
+gas have been produced primarily from conventional sandstone and carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones
+have been recognized by a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a result, several large industry players are expanding positions and conducting drilling programs throughout Lea and
+Eddy Counties in southeast New Mexico and Loving, Reeves and Ward Counties in west Texas. 
+Although the Delaware and Midland
+Basins have not been a primary focus of our recent operations or exploration efforts, we were developing new oil and natural gas prospects in these basins at December 31, 2011. Most notably, we have identified potential drilling opportunities
+on our acreage, particularly in southeast New Mexico, near old vertical wells, some of which have produced up to 1,000,000 BOE from the Wolfcamp formation and up to 500,000 BOE from the Bone Spring formation. These wells suggest a hydrocarbon-rich
+environment in the area of our acreage, and after completing our internal geologic studies, we may determine to drill a Wolfcamp or Bone Spring vertical well or to drill a horizontal well to test these formations on our acreage.
+15 
+Table of Contents 
+At December 31, 2011, we had not included any potential drilling locations on our acreage in our total identified drilling locations, and we had not budgeted any capital expenditures to
+drill wells in southeast New Mexico or west Texas during 2012. We have budgeted $20.0 million of our anticipated 2012 capital expenditures to acquire additional leasehold interests primarily prospective for oil and liquids production in areas of
+southeast New Mexico and west Texas where we are developing new prospects. Although we do have existing leasehold interests in this area of approximately 11,000 gross and approximately 7,000 net acres at December 31, 2011, we believe
+approximately 8,000 gross and 4,000 net acres are no longer prospective, and we plan to let them expire without drilling. 
+Operating
+Summary 
+The following table sets forth certain unaudited production data for the years ended December 31, 2011, 2010
+and 2009: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Unaudited Production Data 
+Net Production Volumes: 
+Oil (MBbls) 
+154 
+33 
+30 
+Natural gas (Bcf) 
+14.5 
+8.4 
+4.8 
+Total natural gas equivalents
+(Bcfe) (1) 
+15.4 
+8.6 
+5.0 
+Average daily production (MMcfe/d) (1) 
+42.3 
+23.6 
+13.7 
+Average Sales Prices: 
+Oil (per Bbl) 
+$ 
+93.80 
+$ 
+76.39 
+$ 
+57.72 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+4.11 
+$ 
+4.38 
+$ 
+5.17 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+3.62 
+$ 
+3.75 
+$ 
+3.59 
+Operating Expenses (per Mcfe): 
+Production taxes and marketing 
+$ 
+0.41 
+$ 
+0.23 
+$ 
+0.22 
+Lease operating 
+$ 
+0.47 
+$ 
+0.61 
+$ 
+0.94 
+Depletion, depreciation and amortization 
+$ 
+2.06 
+$ 
+1.81 
+$ 
+2.15 
+General and administrative 
+$ 
+0.87 
+$ 
+1.13 
+$ 
+1.42 
+(1) 
+Estimated using a conversion ratio of one Bbl per six Mcf. 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2010 from our primary operating areas: 
+Average Net Daily Production 
+Total Net 
+Production 
+(MMcfe) 
+Percentage of 
+Total Net 
+Production 
+Gas 
+(Mcf/d) 
+Oil 
+(Bbls/d) 
+Gas 
+Equivalent 
+(Mcfe/d) 
+South Texas: 
+Eagle Ford 
+4 
+19 
+119 
+43 
+0.5 
+% 
+Austin Chalk (1) 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+4 
+19 
+119 
+43 
+0.5 
+NW Louisiana/E Texas: 
+Haynesville 
+17,127 
+1 
+17,132 
+6,253 
+72.7 
+Cotton Valley (2) 
+5,840 
+40 
+6,074 
+2,218 
+25.8 
+Area Total 
+22,967 
+41 
+23,206 
+8,471 
+98.5 
+SW Wyoming, NE Utah, SE Idaho (1) 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+43 
+31 
+228 
+83 
+1.0 
+Total 
+23,014 
+91 
+23,553 
+8,597 
+100.0 
+% 
+(1) 
+We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation
+in south Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing
+from the San Miguel formation in Zavala County, Texas. 
+16 
+Table of Contents 
+The following table sets forth information regarding our average net daily production and
+total production for the year ended December 31, 2011 from our primary operating areas: 
+Average Net Daily Production 
+Total Net 
+Production 
+(MMcfe) 
+Percentage of 
+Total Net 
+Production 
+Gas 
+(Mcf/d) 
+Oil 
+(Bbls/d) 
+Gas 
+Equivalent 
+(Mcfe/d) 
+South Texas: 
+Eagle Ford 
+1,298 
+331 
+3,286 
+1,200 
+7.8 
+% 
+Austin Chalk (1) 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+1,298 
+331 
+3,286 
+1,200 
+7.8 
+NW Louisiana/E Texas: 
+Haynesville 
+32,319 
+– 
+32,319 
+11,797 
+76.4 
+Cotton Valley (2) 
+6,084 
+64 
+6,465 
+2,360 
+15.3 
+Area Total 
+38,403 
+64 
+38,784 
+14,157 
+91.7 
+SW Wyoming, NE Utah, SE Idaho (1) 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+59 
+27 
+221 
+81 
+0.5 
+Total 
+39,760 
+422 
+42,291 
+15,438 
+100.0 
+% 
+(1) 
+We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation
+in south Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing
+from the San Miguel formation in Zavala County, Texas. 
+Our total production of 15.4 Bcfe for the year ended
+December 31, 2011 was an increase of 79% over our total production of 8.6 Bcfe for the year ended December 31, 2010. This increased production was primarily due to drilling operations in the Haynesville shale, but a portion of the increase
+also reflects production due to our initial drilling operations in the Eagle Ford shale. Our total production of 8.6 Bcfe for the year ended December 31, 2010 was an increase of 72% over our total production of 5.0 Bcfe for the year ended
+December 31, 2009. Most of this increase was attributable to our drilling operations in the Haynesville shale play. In addition, as a result of production from new wells that were completed in 2011, our daily production for the year ended
+December 31, 2011 averaged approximately 42.3 MMcfe per day, as compared to 23.6 MMcfe per day for the year ended December 31, 2010. Our daily oil production for the year ended December 31, 2011 averaged 422 Bbls per day, an
+approximate five-fold increase from 91 Bbls per day for the year ended December 31, 2010. 
+17 
+Table of Contents 
+Producing Wells 
+The following table sets forth information relating to producing wells at December 31, 2011. Wells are classified as oil or natural gas according to their predominant production stream. We do not
+have any currently active dual completions. We have an approximate average working interest of 92% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 44%, and average
+approximately 9%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. 
+Natural Gas Wells 
+Oil Wells 
+Total Wells 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+2.0 
+2.0 
+7.0 
+5.3 
+9.0 
+7.3 
+Austin Chalk (1) 
+– 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+2.0 
+2.0 
+7.0 
+5.3 
+9.0 
+7.3 
+NW Louisiana/E Texas: 
+Haynesville 
+106.0 
+11.6 
+– 
+– 
+106.0 
+11.6 
+Cotton Valley (2) 
+106.0 
+69.7 
+2.0 
+2.0 
+108.0 
+71.7 
+Area Total 
+212.0 
+81.3 
+2.0 
+2.0 
+214.0 
+83.3 
+SW Wyoming, NE Utah, SE Idaho (1) 
+– 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+1.0 
+0.6 
+12.0 
+5.1 
+13.0 
+5.7 
+Total 
+215.0 
+83.9 
+21.0 
+12.4 
+236.0 
+96.3 
+(1) 
+We currently have no producing wells on our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk
+formation in south Texas. 
+(2) 
+Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in
+Zavala County, Texas. 
+18 
+Table of Contents 
+Estimated Proved Reserves 
+The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2011, 2010 and 2009. The reserves estimates were based on evaluations prepared by our engineering
+staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves
+reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be
+attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which
+geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total estimated proved reserves are estimated using a conversion
+ratio of one Bbl per six Mcf. 
+At
+December 31, (1) 
+2011 
+2010 
+2009 
+Estimated Proved Reserves
+Data: (2) 
+Estimated proved reserves: 
+Oil (MBbls) 
+3,794 
+152 
+103 
+Natural Gas (Bcf) 
+170.4 
+127.4 
+63.9 
+Total (Bcfe) 
+193.2 
+128.3 
+64.5 
+Estimated proved developed reserves: 
+Oil (MBbls) 
+1,419 
+152 
+103 
+Natural Gas (Bcf) 
+56.5 
+43.1 
+25.4 
+Total (Bcfe) 
+65.1 
+44.1 
+26.0 
+Percent developed 
+33.7 
+% 
+34.3 
+% 
+40.3 
+% 
+Estimated proved undeveloped reserves: 
+Oil (MBbls) 
+2,375 
+– 
+– 
+Natural Gas (Bcf) 
+113.9 
+84.3 
+38.6 
+Total (Bcfe) 
+128.1 
+84.3 
+38.6 
+PV-10 (3) (in millions) 
+$ 
+248.7 
+$ 
+119.9 
+$ 
+70.4 
+Standardized Measure (4) (in millions) 
+$ 
+215.5 
+$ 
+111.1 
+$ 
+65.1 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative
+transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for
+natural gas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas. These
+prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. 
+(3) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2009, 2010 and 2011 may be reconciled to our Standardized Measure
+of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2009, 2010 and 2011 were, in millions, $5.3, $8.8
+and $33.2, respectively. 
+(4) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+19 
+Table of Contents 
+Our total proved oil and natural gas reserves increased from 128.3 Bcfe at
+December 31, 2010 to 193.2 Bcfe at December 31, 2011. Most of this increase is attributable to proved reserves added due to our drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved oil
+reserves specifically from 152 MBbls at December 31, 2010 to 3,794 MBbls at December 31, 2011 is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved reserves at
+December 31, 2011 were made up of approximately 88% natural gas and 12% oil. Our proved developed reserves increased from 44.1 Bcfe at December 31, 2010 to 65.1 Bcfe at December 31, 2011 due primarily to proved developed reserves
+added as a result of drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved developed oil reserves specifically from 152 MBbls at December 31, 2010 to 1,419 MBbls at December 31, 2011 is attributable
+to proved developed oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved undeveloped reserves increased from 84.3 Bcfe at December 31, 2010 to 128.1 Bcfe at December 31, 2011 due primarily to our
+drilling operations in the Eagle Ford and Haynesville shale plays. The increase in our proved undeveloped oil reserves specifically from zero to 2,375 MBbls at December 31, 2011 is attributable to our drilling operations in the Eagle Ford shale
+play. The net increase of 43.8 Bcfe in our proved undeveloped reserves from December 31, 2010 to December 31, 2011 is composed of (1) additions of 49.0 Bcfe to proved undeveloped reserves identified through drilling operations, less
+(2) the conversion of 3.4 Bcfe of proved undeveloped reserves to proved developed reserves, less (3) the downward revisions of proved undeveloped reserves by 1.8 Bcfe in the period. During this period, we recorded no changes to proved
+undeveloped reserves as a result of the acquisition or divestment of reserves. At December 31, 2011, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking. 
+The following table sets forth additional summary information by operating area with respect to our estimated proved reserves at
+December 31, 2011: 
+Net Proved
+Reserves (1) 
+PV-10 (2) 
+Standardized 
+Measure (3) 
+Oil 
+Gas 
+Gas 
+Equivalent 
+(MBbls) 
+(Bcf) 
+(Bcfe) 
+(in millions) 
+(in millions) 
+South Texas: 
+Eagle Ford 
+3,636 
+6.1 
+27.9 
+$ 
+130.2 
+$ 
+112.8 
+Austin Chalk (4) 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+3,636 
+6.1 
+27.9 
+130.2 
+112.8 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+150.4 
+150.4 
+96.6 
+83.7 
+Cotton Valley (5) 
+61 
+13.8 
+14.2 
+19.5 
+16.9 
+Area Total 
+61 
+164.2 
+164.6 
+116.1 
+100.6 
+SW Wyoming, NE Utah, SE Idaho (4) 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+97 
+0.1 
+0.7 
+2.4 
+2.1 
+Total 
+3,794 
+170.4 
+193.2 
+$ 
+248.7 
+$ 
+215.5 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2011 may be reconciled to our Standardized Measure of discounted
+future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2011 were approximately $33.2 million. 
+(3) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+20 
+Table of Contents 
+(4) 
+At December 31, 2011, we had no proved reserves attributable to the Austin Chalk formation in south Texas or to our acreage in southwest Wyoming and adjacent areas
+of Utah and Idaho. 
+(5) 
+Includes Cotton Valley and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San
+Miguel formation in Zavala County, Texas. 
+Technology Used to Establish Reserves 
+Under current SEC rules, proved reserves are those quantities of oil and natural gas, 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 economic conditions, operating methods and government regulations. The term “reasonable
+certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven 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 have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. 
+In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been
+demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and
+available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production
+history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods.
+Internal Control Over Reserves Estimation Process 
+We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the
+data used in our reserves estimation process. Our Reserves Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over 15 years of industry experience. Our Reserves Manager received his Ph.D. degree in
+Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a certificate of completion in a prescribed course of study in Reserves and Evaluation from Texas A&M University in May
+2009. Our Vice President – Reservoir Engineering is responsible for reviewing and approving our reserves estimates and has over 30 years of industry experience. Following the preparation of our reserves estimates, we had our reserves estimates
+audited for their reasonableness by Netherland, Sewell & Associates, Inc., our independent petroleum engineers. The Engineering Committee of our board of directors reviews the reserves report and our reserves estimation process, and the
+results of the reserves report and the independent audit of our reserves are reviewed by members of our board of directors, including members of our Audit Committee. 
+21 
+Table of Contents 
+Acreage Summary 
+The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2011. At that date, only about 12% of our total acreage had been
+developed, although these percentages are much higher in northwest Louisiana and east Texas. 
+Developed Acres 
+Undeveloped Acres 
+Total Acres 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+2,514 
+2,130 
+48,225 
+26,543 
+50,739 
+28,673 
+Austin Chalk 
+– 
+– 
+24,473 
+14,849 
+24,473 
+14,849 
+Area Total (1) 
+2,514 
+2,130 
+48,225 
+26,543 
+50,739 
+28,673 
+NW Louisiana/E Texas: 
+Haynesville 
+18,713 
+10,599 
+4,158 
+3,928 
+22,871 
+14,527 
+Cotton Valley (2) 
+20,942 
+17,846 
+5,327 
+5,208 
+26,269 
+23,054 
+Area Total (3) 
+23,033 
+19,691 
+5,866 
+5,648 
+28,899 
+25,339 
+SW Wyoming, NE Utah, SE Idaho 
+– 
+– 
+144,368 
+135,862 
+144,368 
+135,862 
+SE New Mexico, West Texas 
+1,160 
+1,038 
+9,554 
+5,620 
+10,714 
+6,658 
+Total 
+26,707 
+22,859 
+208,013 
+173,673 
+234,720 
+196,532 
+(1) 
+Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+(2) 
+Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas. 
+(3) 
+Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+Undeveloped Acreage Expiration
+The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2011 that
+will expire prior to December 31, 2013 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates or unless the existing leases are renewed prior to expiration: 
+Acres 
+Expiring 2012 
+Acres 
+Expiring 2013 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+15,044 
+4,349 
+12,165 
+7,149 
+Austin Chalk 
+5,731 
+1,133 
+3,851 
+2,646 
+Area Total (1) 
+15,044 
+4,349 
+12,165 
+7,149 
+NW Louisiana/E Texas 
+Haynesville 
+644 
+395 
+40 
+5 
+Cotton Valley 
+750 
+401 
+40 
+5 
+Area Total (2) 
+750 
+401 
+40 
+5 
+SW Wyoming, NE Utah, SE Idaho 
+101,905 
+93,356 
+8,461 
+8,301 
+SE New Mexico, West Texas 
+1,712 
+79 
+8,454 
+2,715 
+Total 
+119,411 
+98,185 
+29,120 
+18,170 
+(1) 
+Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+(2) 
+Some of the same leases cover the net acres shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than the Haynesville shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+22 
+Table of Contents 
+Many of the leases comprising the acreage set forth in the table above will expire at the
+end of their respective primary terms unless production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. We also have options to
+extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there
+may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. Our leases are mainly fee leases with three to five years of primary
+term. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. 
+Drilling Results 
+The following table summarizes our drilling activity for
+the three years ended December 31, 2011, 2010 and 2009: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development Wells 
+Productive 
+30 
+0.6 
+5 
+1.7 
+3 
+1.3 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Exploration Wells 
+Productive 
+30 
+10.2 
+36 
+3.4 
+15 
+6.0 
+Dry 
+– 
+– 
+– 
+– 
+2 
+2.0 
+Total Wells 
+Productive 
+60 
+10.8 
+41 
+5.1 
+18 
+7.3 
+Dry 
+– 
+– 
+– 
+– 
+2 
+2.0 
+Marketing 
+Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting
+price. As a consequence, the prices we receive for crude oil and liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil are also deducted
+from the price received for crude oil. 
+Our natural gas is sold under both long-term and short-term natural gas purchase
+agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based
+on various pipeline indices less any associated fees. When there is an opportunity to do so, the mid-stream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are
+then paid for the extracted liquids based on a negotiated percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or based on other negotiated pricing arrangements. 
+The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the
+level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political
+conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall 
+23 
+Table of Contents 
+economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term
+disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations
+do curtail our production capabilities and ability to maintain a steady source of revenue for our company. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder
+winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to
+Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+For the year ended December 31, 2009, we had
+three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (32%), Regency Gas Services LP (25%), and J-W Operating Company (17%). For the year ended December 31, 2010,
+we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (42%), Regency Gas Services LP (17%) and Petrohawk Energy Corporation (11%). For the year ended
+December 31, 2011, we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Sequent Energy Management (24%), Chesapeake Operating Inc. (21%) and Eastex Crude Company (15%). Due to
+the nature of the markets for oil and natural gas, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of
+time. 
+While we do not have any commitments to sell a fixed and determinable quantity of oil or natural gas to a particular
+buyer, we were party to two natural gas transportation agreements at December 31, 2011 that require us to deliver a specified volume of natural gas through pipelines for a fixed period of time. If we fail to meet the volume requirements, we are
+required to pay an amount to the owners of the pipelines to offset a portion of the expenses they incurred in building the pipelines to our well locations. Neither of these contracts constitutes a material commitment. 
+Title to Properties 
+We
+endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual
+arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests
+will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will
+not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by making lease rental payments or by producing wells in paying quantities prior to expiration of various
+time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result
+of Title Deficiencies in the Properties in Which We Invest.” 
+Competition 
+The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural
+gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, 
+24 
+Table of Contents 
+operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to
+absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects
+and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling
+rigs. 
+Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to
+conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while our competitors have a longer history of operations, and
+most of them have also demonstrated the ability to operate through industry cycles. 
+The oil and natural gas industry also
+competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors – Competition in the Oil and Natural Gas Industry Is Intense Making It More
+Difficult for Us to Acquire Properties, Market Natural Gas and Secure Trained Personnel.” 
+Regulation 
+Oil and Natural Gas Regulation 
+Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules
+and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or
+reinterpreted and new rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas
+industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. 
+Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and
+reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas matters,
+including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are
+drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes
+prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas
+wells below natural production capacity in order to conserve supplies of oil and natural gas. 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. 
+25 
+Table of Contents 
+Some of our oil and natural gas leases are issued by agencies of the federal government, as
+well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. 
+Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of
+transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as
+under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural
+gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
+In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act,
+among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly
+increase the penalties for violations of the NGA, the NGPA, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related
+regulations, in addition to FERC-imposed penalties, we may also be subject to third party damage claims. 
+Intrastate natural
+gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and
+services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our
+operations in any way that is materially different from our competitors that are similarly situated. 
+The price we receive
+from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though
+other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the
+effects, if any, of these regulations on our operations. 
+In 2007, the Energy Independence & Security Act of 2007, or
+the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations
+that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future regulations or their impact. 
+U.S. Federal and State Taxation 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions
+of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and 
+26 
+Table of Contents 
+presidential administrations concerning a variety of energy tax proposals. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and natural
+gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Many states have raised state
+taxes on energy sources, and additional increases may occur. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become
+Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect
+Our Business, Financial Condition, Results of Operations and Cash Flows.” 
+Hydraulic Fracturing Policies and
+Procedures 
+We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in almost
+every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary,
+as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our horizontal wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other
+costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs
+and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or
+Delays.” 
+The protection of groundwater quality is important to us. We believe that we follow all state and federal
+regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage). Our policy and
+practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing. A surface casing string is typically set deeper than the deepest usable quality fresh water zones and cemented back to the surface in
+accordance with the appropriate regulations, lease requirements and legal requirements. This surface string of casing is then pressure tested to ensure mechanical integrity of the casing string prior to continuing drilling operations. We follow
+strict quality control procedures for conducting hydraulic fracturing operations that include a multi-point safety checklist, managing inventories of all materials and chemicals on the well site and ensuring that Material Safety Data Sheets are on
+location for every well that is hydraulically fractured. We contract with third parties to conduct hydraulic fracturing operations, and we send at least one of our own engineers or an experienced consultant to the well site to personally supervise
+each hydraulic fracture treatment. On a real-time basis, we closely monitor pump rates and pressures on existing casing strings to ensure that wellbore integrity is maintained during hydraulic fracturing operations. Our policy regarding monitoring
+well pressures would require stopping the hydraulic fracturing operations upon any indication that wellbore integrity may have been compromised. 
+We follow additional regulatory requirements and recommended practices to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These include the
+following: 
+• 
+Prior to perforating the production casing and hydraulic fracturing operations, a cement bond log is run to verify cement integrity between the
+formation to be fractured and shallow formations. Then, the casing is pressure tested to ensure no leaks exist within the casing; 
+27 
+Table of Contents 
+• 
+Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all high pressure lines and
+connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, the service companies we engage must provide specialized equipment to monitor and record surface pressures, pumping
+rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Our engineers at the job site have laptop computers with special software to monitor and collect, for permanent
+archiving, information from the hydraulic fracturing operations. As part of this process, when fracturing operations are being performed down casing, we also monitor the casing annular pressure to ensure that there is no communication of hydraulic
+pressure and fracture fluids outside the casing that could communicate with shallow formations. Should any problem be detected at any time during the hydraulic fracturing treatment, the operation would be shut down until the problem is evaluated,
+reported and remediated; and 
+• 
+As a means to further protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing
+operation, special precautions are taken both during and after the operation. During the fracturing operation, all chemicals are mixed into the fracturing fluid as it is being pumped into the well as opposed to being pre-mixed in the “frac
+pits” or work tanks. While chemical additives are stored on location in independent containment vessels, only fresh water is stored in the frac pits or work tanks. All pumping equipment used during the operation is pressure tested and
+monitored. When the well is flowed back, after the fracturing operation, all fluids are produced into closed-top storage tanks. All flowback equipment and piping are pressure tested to ensure no leaks are present and the fluids are properly
+contained. 
+Once the final string of casing is set in place, cement is pumped into the casing/wellbore
+annulus where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design establishes a pressure seal essentially eliminating any pathway for the
+fracturing fluid to contact fresh water aquifers during the hydraulic fracturing operation. Furthermore, in the areas in which we conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable quality underground
+fresh water aquifers by thousands of feet of impermeable rock layers. This natural geological separation serves as a protective barrier, preventing migration of fracturing fluids or hydrocarbons upwards into any fresh water zones. 
+Although rare, if and when the cement and steel casing used in well construction need to be remediated, we deal with these problems by
+evaluating the issue, running diagnostic tools including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs. We repair wellhead leaks by replacing wellhead components, re-installing components to proper
+specifications and re-testing. In wellbores that utilize downhole packers, pressure integrity issues are rectified by repairing or replacing packers. Casing integrity lost due to corrosion on a producing well is remedied by identifying the specific
+location of the leak by cased hole logging tools, mechanical isolation and pressure testing or other diagnostic methods, followed by high pressure squeeze cementing and subsequent pressure testing to ensure the leak has been repaired. Throughout the
+process we believe we abide by applicable regulations. 
+The vast majority of hydraulic fracturing treatments are made up of
+water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies.
+These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to
+28 
+Table of Contents 
+develop more environmentally friendly fracturing fluids. As previously mentioned, we also follow strict safety procedures and monitor all aspects of the fracturing operation to ensure
+environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. 
+While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture
+stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed
+of in permitted and regulated disposal facilities. 
+Environmental Regulation 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells,
+are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety
+of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the
+Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject
+to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Civil and criminal
+fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities,
+limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and
+regulations and expect that these laws and regulations will not have a material adverse impact on us. 
+The OPA 90 and its
+regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic
+zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal
+costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to
+comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with
+applicable requirements under the OPA 90 will not have a material and adverse effect on us. 
+The CWA and comparable state laws
+impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions
+will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the
+federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, 
+29 
+Table of Contents 
+produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental
+Protection Agency, or the EPA, has 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. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of
+removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and
+meet construction and operating standards. 
+CERCLA, also known as the “Superfund” law, and comparable state statutes
+impose liability, without regard to fault or the legality of the original conduct, on various 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 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 responsible for releases of hazardous substances under
+CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. 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 hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will,
+involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Certain state statutes may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have
+been subjected to, or have caused or contributed to, prior releases of hazardous wastes. 
+RCRA and comparable state and local
+statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a
+statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the
+wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of
+this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors,
+to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. 
+The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose
+stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On
+July 28, 2011, the EPA proposed new regulations targeting air emissions from the oil and natural gas industry. The proposed rules, if adopted, would impose new requirements on production and processing and transmission and storage facilities
+and on hydraulic fracturing activities. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air
+emission-related issues, we do not believe that such requirements will affect our operations in any way that is materially different from our competitors. 
+30 
+Table of Contents 
+Changes in environmental laws and regulations occur frequently, and any changes that result
+in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general.
+For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
+atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas
+emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural
+gas. 
+The EPA has published its findings that emissions of greenhouse gases presented an endangerment to human health and the
+environment. 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 CAA. Subsequently, the EPA proposed and adopted
+two sets of regulations, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulated emissions of greenhouse gases from certain large stationary sources. In addition, on October 30,
+2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final
+rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities.
+Reporting of greenhouse gas emissions from such onshore production will be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or
+limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could
+adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development
+of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric
+plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative
+initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from
+oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a
+regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.
+The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate five underground injection wells and expect to own other similar wells. Failure to obtain,
+or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. 
+31 
+Table of Contents 
+Our activities involve the use of hydraulic fracturing. For more information on our
+hydraulic fracturing operations, see “Business — Regulation — Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from
+regulation as underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of
+“underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain
+construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of
+chemicals used in the fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in
+any such legislation could have a significant impact on our financial condition, results of operations and cash flows. 
+In
+addition, at the federal level and in some states, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and in some areas to severely restrict or prohibit those activities. Certain bills have been
+introduced in the Senate and the House of Representatives that, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased
+operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. At the state level, Wyoming and Texas, for
+example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during hydraulic
+fracturing in Texas. The law went into effect in 2011 and implementing regulations have been adopted. In addition, at least a few local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local
+ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will
+result in additional expense and delay in our operations. 
+The EPA has recently been taking action to assert federal
+regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. Interim results of
+the study are expected in 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This
+study remains subject to review and public comment but such studies could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous
+owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire reserves
+against some of the liability for environmental claims associated with these properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties
+will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. 
+32 
+Table of Contents 
+Additionally, in the course of our routine oil and natural gas operations, surface spills
+and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is
+present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams.
+Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our
+lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 
+We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community
+right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations.
+Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. 
+We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to
+our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We cannot assure you that more stringent laws
+and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to
+Government Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.” 
+The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment,
+and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse
+effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will
+not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. 
+We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may
+not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is
+not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 
+Office
+Lease 
+Our corporate headquarters are located in 28,743 square feet of office space in One Lincoln Centre, 5400 LBJ
+Freeway, Suite 1500, Dallas, Texas. In April 2011, we entered into a third amended and restated office lease agreement pursuant to which our office space was increased from 20,849 to 28,743 square feet and the term of our lease was extended from
+July 1, 2011 to June 30, 2022. Beginning July 1, 2011, through 
+33 
+Table of Contents 
+June 30, 2012, we are not required to pay a monthly base rent. From July 1, 2012 through June 30, 2015, our monthly base rent is $47,905. From July 1, 2015 through
+June 30, 2017, our monthly base rent is $50,300. From July 1, 2017 through June 30, 2019, our monthly base rent is $52,696. From July 1, 2019 through June 30, 2020, our monthly base rent is $55,091. From July 1, 2020
+through the expiration date of the lease, our monthly base rent is $57,726. In addition, the lease contains a renewal option in our favor for an additional 60-month period at the then existing market rate as determined in accordance with the lease.
+Employees 
+At December 31, 2011, we had 41 full-time employees. We believe that our relationships with our employees are satisfactory. No
+employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, construction,
+design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and
+on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to
+employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. 
+Available Information
+Our Internet website address is www.matadorresources.com . We expect to make available, free of charge, through our
+website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit
+Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a written request to the
+Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this report or any other report or document we file and any reference to
+our website is intended to be an inactive textual reference only. 
+34 
+Table of Contents 
+Item 1A. 
+Risk Factors. 
+Risks Related to the
+Oil and Natural Gas Industry and Our Business 
+Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas
+Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. 
+The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital
+expenditures, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for
+oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:
+• 
+the domestic and foreign supply of oil and natural gas; 
+• 
+the domestic and foreign demand for oil and natural gas; 
+• 
+the prices and availability of competitors’ supplies of oil and natural gas; 
+• 
+the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production
+controls; 
+• 
+the price and quantity of foreign imports; 
+• 
+the impact of U.S. dollar exchange rates on oil and natural gas prices; 
+• 
+domestic and foreign governmental regulations and taxes; 
+• 
+speculative trading of oil and natural gas futures contracts; 
+• 
+the availability, proximity and capacity of gathering and transportation systems for natural gas; 
+• 
+the availability of refining capacity; 
+• 
+the prices and availability of alternative fuel sources; 
+• 
+weather conditions and natural disasters; 
+• 
+political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America; 
+• 
+the continued threat of terrorism and the impact of military action and civil unrest; 
+• 
+public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate
+hydraulic fracturing activities; 
+• 
+the level of global oil and natural gas inventories and exploration and production activity; 
+• 
+the impact of energy conservation efforts; 
+• 
+technological advances affecting energy consumption; and 
+• 
+overall worldwide economic conditions. 
+Approximately 98% of our production during the year ended December 31, 2010, 94% of our production during the year ended December 31, 2011 and 88% of our proved reserves at December 31,
+35 
+Table of Contents 
+2011 are attributable to natural gas. In addition, three of our largest prospects, our Haynesville shale, Cotton Valley properties and our Meade Peak shale prospect, currently produce or are
+expected to produce predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices. 
+One of
+our current business strategies is to focus on increasing our oil and liquids production. Specifically, our near-term drilling opportunities in the Eagle Ford shale play focus on oil and liquids. We currently intend to allocate approximately 84% of
+our 2012 capital expenditure budget to the exploration of the Eagle Ford shale. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil and liquids production, and we have identified 193 gross locations for
+potential future drilling in our Eagle Ford acreage. Therefore, our Eagle Ford shale play is highly susceptible to changes in oil prices. 
+Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease to
+economically unattractive levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain
+prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. 
+In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub
+natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploration prospects like the Meade Peak shale, until
+natural gas prices improved substantially from these levels or unless the costs to drill and complete these wells were also to decline substantially from their recent levels. 
+Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business. 
+Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from
+definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial
+additional interpretation before it can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling
+and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration
+wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and
+development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. 
+If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or
+produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to
+predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or
+natural gas exist, we may 
+36 
+Table of Contents 
+damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves
+from the well or abandonment of the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following: 
+• 
+general economic and industry conditions, including the prices received for oil and natural gas; 
+• 
+shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; 
+• 
+potential drainage by operators on adjacent properties; 
+• 
+loss of or damage to oilfield development and service tools; 
+• 
+problems with title to the underlying properties; 
+• 
+increases in severance taxes; 
+• 
+adverse weather conditions that delay drilling activities or cause producing wells to be shut down; 
+• 
+domestic and foreign governmental regulations; and 
+• 
+proximity to and capacity of transportation facilities. 
+If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. 
+We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells or in Production Activities, Which Could Adversely
+Affect Our Business. 
+While we are drilling and completing wells or involved in production activities, we may have
+accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing
+formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well. 
+Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in Production and Markets Relating to Any Property Could Have a Material Impact on Our Business.
+Almost all of our current oil and natural gas production and our proved reserves are attributable to properties in
+northwest Louisiana and east Texas, and we expect that most of our operations in the near future will be primarily in south Texas. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these
+wells caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or
+plant closures for scheduled maintenance. In particular, our operations in south Texas may be adversely impacted by a lack of pipeline infrastructure and natural gas processing facilities in light of the oil and natural gas industry’s increased
+focus on the exploration and development of the Eagle Ford shale. Our operations in south Texas may also be adversely affected by hurricanes and tropical storms resulting in delays in exploration and drilling, damage to facilities and equipment and
+the inability to receive equipment or to access personnel and products at affected job sites in a timely manner. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at
+the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on
+our financial condition, results of operations and cash flows. 
+37 
+Table of Contents 
+Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would
+Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The rate of production from our
+oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in: (i) efficiently developing and
+exploiting our current reserves on properties owned by us or by other persons or entities and (ii) economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our
+production and reserves from the Eagle Ford shale play, an area in which industry activity has increased rapidly. As a result of this increased activity, we may have difficulty expanding our current production or acquiring new properties in this
+area and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our
+current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. 
+Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Receive, and Significant Inaccuracies in These Reserves Estimates or Underlying
+Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. 
+The process of estimating
+accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and
+reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
+The accuracy of a reserves estimate is a function of: 
+• 
+the quality and quantity of available data; 
+• 
+the interpretation of that data; 
+• 
+the judgment of the persons preparing the estimate; and 
+• 
+the accuracy of the assumptions. 
+The accuracy of any estimates of proved reserves generally increases with the length of the production history. Due to the limited production history of many of our properties, the estimates of future
+production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data is available, the estimated
+proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other
+factors. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses
+and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially
+affect the quantities and present value of our reserves. 
+The Calculated Present Value of Future Net Revenues from Our Proven Reserves Will
+Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. 
+It should not be
+assumed that the present value of future net cash flows included in this report is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves
+on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index 
+38 
+Table of Contents 
+prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs
+used for these estimates and will be affected by factors such as: 
+• 
+actual prices we receive for oil and natural gas; 
+• 
+actual cost and timing of development and production expenditures; 
+• 
+the amount and timing of actual production; and 
+• 
+changes in governmental regulations or taxation. 
+In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under Generally Accepted Accounting Principles, or GAAP, is not
+necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. 
+Approximately 67% of Our Total Proved Reserves at December 31, 2011 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those
+Reserves May Not Ultimately Be Developed or Produced. 
+At December 31, 2011, approximately 66% of our total proved
+reserves were undeveloped and approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have
+projected or at the costs we have budgeted. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues
+estimated for such reserves, resulting in some projects becoming uneconomical. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have
+to reclassify our proved reserves as unproved reserves, which would materially affect our business, financial condition, results of operations and ability to raise capital. 
+Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to
+Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. 
+Our exploration and
+development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash and cash
+equivalents, operating cash flows and future potential borrowings under our credit agreement or otherwise may not be adequate to fund our future acquisitions or future capital expenditure requirements. The rate of our future growth may be dependent,
+at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. 
+We may sell
+additional securities to raise capital. If we succeed in selling additional securities to raise funds, at such time the ownership of our existing shareholders would likely be diluted, and new investors may demand rights, preferences or privileges
+senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. 
+Our cash flows from operations and access to capital are subject to a number of variables, including: 
+• 
+our estimated proved oil and natural gas reserves; 
+• 
+the amount of oil and natural gas we produce from existing wells; 
+• 
+the prices at which we sell our production; 
+39 
+Table of Contents 
+• 
+the costs of developing and producing our oil and natural gas reserves; 
+• 
+our ability to acquire, locate and produce new reserves; 
+• 
+the ability and willingness of banks to lend to us; and 
+• 
+our ability to access the equity and debt capital markets. 
+In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large
+company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely
+review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could
+adversely affect our access to funding for our operations in the future. 
+If our revenues decrease as a result of lower oil
+and gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or
+invest in additional exploration opportunities. Alternatively, a significant improvement in oil and gas prices could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially
+through the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are unable to raise additional capital from
+available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. 
+Our
+Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. 
+There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:
+• 
+unusual or unexpected geologic formations; 
+• 
+natural disasters; 
+• 
+adverse weather conditions; 
+• 
+unanticipated pressures; 
+• 
+loss of drilling fluid circulation; 
+• 
+blowouts where oil or natural gas flows uncontrolled at a wellhead; 
+• 
+cratering or collapse of the formation; 
+• 
+pipe or cement leaks, failures or casing collapses; 
+• 
+fires or explosions; 
+• 
+releases of hazardous substances or other waste materials that cause environmental damage; 
+• 
+pressures or irregularities in formations; and 
+• 
+equipment failures or accidents. 
+In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum
+40 
+Table of Contents 
+hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and
+waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental
+pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase
+the level of damages resulting from these risks. 
+Insurance against all operational risks is not available to us. We are not
+fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may
+elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance
+coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types
+of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all
+potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business,
+financial condition, results of operations and cash flows. 
+The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot
+Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Future Cash Flows and Results of Operations. 
+We intend to employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable.
+These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by
+drilling unproductive wells based on these technologies. Poor results from our exploration activities could limit our ability to replace and grow reserves and materially and adversely affect our future cash flows and results of operations.
+We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty Obtaining Additional Data at a
+Reasonable Cost, Which Could Adversely Affect Our Future Cash Flows and Results of Operations. 
+We currently own only a
+limited amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access
+to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost. 
+The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment
+and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash
+Flows. 
+Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay
+or adversely affect our operations. When drilling activity in the United States increases, 
+41 
+Table of Contents 
+associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These
+costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we
+may incur these higher costs, which may negatively affect our financial condition, results of operations and cash flows. 
+In
+addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment
+due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. If demand for fracturing services continues to
+increase or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business and results of operations. 
+Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. 
+Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill
+and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of risks, costs and drilling results. The final
+determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations.
+Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling
+locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our financial condition, results of operations and cash flows. 
+We Have Limited Control Over Activities on Properties We Do Not Operate. 
+We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not
+operate one of our most significant natural gas assets in the Haynesville shale. We have also acquired other non-operated acreage positions in northwest Louisiana. Because we are not the operator for these properties, our ability to exercise
+influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or
+control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others
+therefore depends upon a number of factors, including: 
+• 
+timing and amount of capital expenditures; 
+• 
+the operator’s expertise and financial resources; 
+• 
+the rate of production of reserves, if any; 
+• 
+approval of other participants in drilling wells; and 
+• 
+selection of technology. 
+42 
+Table of Contents 
+In areas where we do not have the right to propose the drilling of wells, we may have
+limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing,
+both of which could limit our ability to develop and monetize the underlying natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties
+during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. 
+A Component of Our Growth May Come Through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our
+Earnings and Hamper Our Growth. 
+We may be unable to identify properties for acquisition or to make acquisitions on terms
+that we consider economically acceptable. 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. The completion and
+pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in
+operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and
+current operations, and could negatively impact our results of operations and growth potential. Our financial position, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of
+significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted. 
+We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our
+capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our credit agreement
+includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to
+acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. 
+We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a
+Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. 
+Before acquiring oil
+and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates,
+and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and
+capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us
+contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did
+not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. 
+43 
+Table of Contents 
+Strategic Relationships Upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to
+Conduct Our Operations. 
+Our ability to explore, develop and produce oil and natural gas resources successfully and
+acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive
+environment. These realities are subject to change and may impair our ability to grow. 
+To develop our business, we will
+endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that
+supply equipment and other resources that we expect to use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with
+strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not
+established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. 
+The
+Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Arrangements Would Have a
+Material Adverse Effect on Our Revenue. 
+The unavailability of satisfactory oil and natural gas transportation
+arrangements may hinder our access to oil and natural gas markets or delay production from our wells. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of,
+oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned
+and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering
+system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated
+to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. 
+The disruption of third party
+facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. The third parties control when or if such facilities are restored and what prices will be charged. We generally do not purchase firm
+transportation on third party facilities, and, therefore, our production transportation can be interrupted by those having firm arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies,
+changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas. 
+Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. 
+To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless
+collars,” with respect to a portion of our future production. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option
+proceeds are used to offset the cost of the put option, this arrangement is 
+44 
+Table of Contents 
+initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigate price volatility and increase the predictability of cash flows. These
+transactions limit our potential gains if oil or natural gas prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the
+volumes then hedged. 
+In addition, hedging transactions may expose us to the risk of financial loss in certain other
+circumstances, including instances in which our production is less than expected or the counterparties to our put and call option contracts fail to perform under the contracts. 
+Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to
+perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that
+risk may be limited depending upon market conditions. 
+Furthermore, there may be times when we have not hedged our production
+when, in retrospect, it would have been advisable to do so. Decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil and gas prices, and we may not
+always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging
+strategies may be successful. 
+An Increase in the Differential Between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the
+Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The
+difference between the benchmark price and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could adversely affect our business,
+financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be
+exposed to any increase in such differentials. 
+We Are Subject to Government Regulation and Liability, including Complex Environmental
+Laws, Which Could Require Significant Expenditures. 
+The exploration, development, production and sale of oil and natural
+gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning
+operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures
+that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for: 
+• 
+personal injuries; 
+• 
+property damage; 
+• 
+containment and clean up of oil and other spills; 
+• 
+the management and disposal of hazardous materials; 
+45 
+Table of Contents 
+• 
+remediation and clean-up costs; and 
+• 
+other environmental damages. 
+We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or
+termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed
+frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may
+also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and
+state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on
+alleged non-compliance with certain of these laws, rules and regulations. 
+We Are Subject to Federal, State and Local Taxes, and May Become
+Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect
+Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The federal, state and local governments in the
+areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of
+discussion by legislators and presidential administrations concerning a variety of energy tax proposals. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws that are applicable to us could
+adversely affect our business and our financial results. 
+Periodically, legislation is introduced to eliminate certain key
+U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. 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 United States production activities and (iv) the increase in the amortization
+period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. These changes were included in the White House budget proposals, released on
+February 26, 2009, February 1, 2010, February 14, 2011 and February 13, 2012, and may be raised again in the future. The passage of any legislation as a result of the budget proposals or any other similar change in U.S.
+federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash
+flows. 
+We May Be Required to Write Down the Carrying Value of Our Proved Properties Under Accounting Rules and these Write-Downs Could
+Adversely Affect Our Financial Condition. 
+There is a risk that we will be required to write down the carrying value of
+our oil and natural gas properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have: 
+• 
+downward adjustments to our estimated proved reserves; 
+46 
+Table of Contents 
+• 
+increases in our estimates of development costs; or 
+• 
+deterioration in our exploration results. 
+We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less
+related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved
+reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the
+excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, but it does reduce the book value of our net tangible assets, retained earnings and
+shareholders’ equity and could lower the value of our common stock. 
+We May Incur Losses or Costs as a Result of Title Deficiencies in
+the Properties in Which We Invest. 
+If an examination of the title history of a property that we have purchased reveals an
+oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any
+royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. 
+It is our
+practice, in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under
+lease. Rather, we will rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work in examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral
+interest. 
+Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas
+industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title
+to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely
+impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed
+acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash
+flows. 
+The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our
+Business. 
+On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer
+Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulating certain derivative products including
+the commodity hedges of the type used by us, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result, it is difficult to 
+47 
+Table of Contents 
+anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited
+assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the
+Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have
+a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. 
+If these
+types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of
+derivative arrangements could also materially affect our future ability to conduct acquisitions. 
+Federal and State Legislation and
+Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. 
+In past sessions, Congress has considered, but did not pass, legislation to amend the SDWA to remove the exemption from restrictions on underground injection of fluids near drinking water sources granted
+to most hydraulic fracturing operations and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand or other propping
+agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas from shale formations such as the Eagle Ford
+and the Haynesville shales, where we focus our operations. Sponsors of bills before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation,
+if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in
+additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. Moreover, the EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic
+fracturing may have on drinking water and groundwater. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming, although this
+study remains subject to review and public comments. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal
+legislation and regulation of hydraulic fracturing or similar production operations. 
+In addition, a number of states are
+considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit further production of natural gas through the use of hydraulic fracturing or
+similar operations. For example, Texas has adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation and any
+implementing regulation could increase our costs of compliance and doing business. 
+The adoption of new laws or regulations
+imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations. In addition, if hydraulic fracturing becomes regulated at the federal
+level as a result of federal 
+48 
+Table of Contents 
+legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases
+in cost, which could adversely affect our business and results of operations. 
+Legislation or Regulations Restricting Emissions of
+“Greenhouse Gases” Could Result in Increased Operating Costs and Reduced Demand for the Natural Gas, Natural Gas Liquids and Oil We Produce While the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur
+Significant Costs in Preparing for or Responding to those Effects. 
+The EPA has published its final findings that
+emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere
+and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Accordingly, the EPA has adopted regulations that would require a
+reduction in emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published 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. On November 30, 2010, the EPA released a final rule that expands
+its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports due to the EPA in
+2012. 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. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or
+reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the natural gas, oil and liquids that we produce. 
+A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It 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 NGA exempts natural gas gathering facilities from regulation by
+FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas
+company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services 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. A change in the jurisdictional characterization by FERC or Congress or a change in policy by either of them may result in increased regulation of our assets, which may cause our
+revenues to decline and operating expenses to increase. 
+Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules,
+Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. 
+Under the Energy Policy Act, FERC has
+civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. Our systems have not yet been regulated by FERC, as a
+natural gas company subject to the provisions of the NGA. FERC has adopted regulations that may subject certain of our otherwise 
+49 
+Table of Contents 
+non-FERC/NGA jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional laws, rules and regulations pertaining to those and other
+matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. 
+Competition in the Oil and Natural Gas Industry Is Intense Making It More Difficult for Us to Acquire Properties, Market Natural Gas and Secure Trained Personnel. 
+Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and
+select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for
+investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas
+properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages
+to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete
+successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
+Our Competitors May Use Superior Technology and Data Resources that We May Be Unable to Afford or that Would Require a Costly Investment
+by Us in Order to Compete with Them More Effectively. 
+Our industry is subject to rapid and significant advancements in
+technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to
+implement new technologies at a substantial cost. In addition, many of our competitors will 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 cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may
+become obsolete, and we may be adversely affected. 
+Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases that Will Expire
+Over the Next Several Years Unless Production Is Established on Units Containing the Acreage. 
+At December 31, 2011,
+we had leasehold interests in approximately 116,000 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2013. Unless
+we establish production in paying quantities on units containing these leases during their terms or we renew such leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties. 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. In addition, on certain portions of our acreage, third party leases may have been taken and could become immediately
+effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. 
+50 
+Table of Contents 
+We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on
+Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. 
+Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our
+activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management
+resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers,
+geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. 
+Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flow
+from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. 
+We derive essentially
+all of our revenues from the sale of our oil and natural gas to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by
+them will have an immediate negative effect on our results of operations and cash flows. 
+Liquidity and cash flow problems
+encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay
+their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a
+farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these
+contingencies or that we would be able to find a new farmout party. 
+We May Incur Indebtedness Which Could Reduce Our Financial
+Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. 
+At March 30, 2012, we
+had available borrowings of approximately $108.7 million under our credit agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our
+existing and future acquired oil and gas reserves. Our credit agreement is secured by substantially all of our interests in our oil and gas properties and other assets and contains covenants restricting our ability to incur additional indebtedness,
+which may limit our ability to obtain additional financing. In addition, the borrowing base under our credit agreement is subject to periodic redeterminations, and we could be forced to repay a portion of our borrowings due to redeterminations of
+our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. 
+Borrowings under our
+credit agreement at March 30, 2012 bear interest at a variable rate of 1.75% plus a Eurodollar-based rate per annum, which equated to approximately 2.0% per annum. In the future, we may incur significant amounts of additional indebtedness,
+including under our credit agreement, in order to make acquisitions or to develop our properties. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. 
+51 
+Table of Contents 
+Our level of indebtedness could affect our operations in several ways, including the
+following: 
+• 
+a significant portion of our cash flows could be used to service our indebtedness; 
+• 
+a high level of debt would increase our vulnerability to general adverse economic and industry conditions; 
+• 
+any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets,
+pay dividends and make certain investments; 
+• 
+a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take
+advantage of opportunities that our indebtedness may prevent us from pursuing; 
+• 
+our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and
+• 
+a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and
+general corporate or other purposes. 
+A high level of indebtedness increases the risk that we may default on
+our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our
+operations and our future performance. We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.
+Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital. If we do not have
+sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our
+business and financial results. 
+Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman
+of the Board, Chief Executive Officer and President, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations.
+Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the
+success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including
+our Chairman, President and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into
+employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or any of these other key personnel resign or become unable
+to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of
+any of these individuals. 
+We have an active board of directors that meets several times throughout the year and is intimately
+involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. Many of our directors have
+been involved with us since our inception and have a deep 
+52 
+Table of Contents 
+understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge
+and experience and as a result, our operations may be adversely affected. 
+In addition, our board consults regularly with our
+special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making
+decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. 
+Our Management Team Owns Approximately 13% of Our Common Stock Which Could Give Them Influence in Corporate Transactions and Other Matters, and the
+Interests of Our Management Could Differ from Other Shareholders. 
+Our directors and officers beneficially own
+approximately 13% of our outstanding shares of common stock. These shareholders are positioned to influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any
+amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the company may have the effect of delaying or preventing a change of control of the company
+and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, they may be able to remain entrenched in their positions. 
+Risks Relating to Our Common Stock 
+Our Common Stock Has Only Been Publicly Traded Since February 2, 2012, and the Price of our Common Stock Has Fluctuated Substantially Since Then
+and May Fluctuate Substantially in the Future. 
+Our common stock has been publicly traded only since February 2,
+2012. The market price of our common stock could vary significantly as a result of a number of factors. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. In the event of a drop in the
+market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating
+performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. 
+Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: 
+• 
+our actual or anticipated operating and financial performance and drilling locations, including reserves estimates; 
+• 
+quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies
+that are perceived to be similar to us; 
+• 
+changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; 
+• 
+speculation in the press or investment community; 
+• 
+public reaction to our press releases, announcements and filings with the Securities and Exchange Commission, or SEC; 
+• 
+sales of our common stock by us or shareholders, or the perception that such sales may occur; 
+53 
+Table of Contents 
+• 
+general financial market conditions and oil and gas industry market conditions, including fluctuations in commodity prices;
+• 
+the realization of any of the risk factors presented in this report; 
+• 
+the recruitment or departure of key personnel; 
+• 
+commencement of or involvement in litigation; 
+• 
+the prices of oil and natural gas; 
+• 
+the success of our exploration and development operations, and the marketing of any oil and natural gas we produce; 
+• 
+changes in market valuations of companies similar to ours; and 
+• 
+domestic and international economic, legal and regulatory factors unrelated to our performance. 
+The Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended,
+and the Requirements of the Sarbanes-Oxley Act of 2002, May Strain Our Resources, Increase Our Costs and Distract Management; and It May Be Difficult to Comply with These Requirements in a Timely or Cost-Effective Manner. 
+As a new public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain
+corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we were not required to comply as a private company. Complying with these
+statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to: 
+• 
+institute a more comprehensive compliance function; 
+• 
+establish and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the
+Sarbanes-Oxley Act and the related rules and regulations of the SEC; 
+• 
+comply with rules promulgated by the NYSE; 
+• 
+prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; 
+• 
+establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; and 
+• 
+involve and retain to a greater degree outside counsel and accountants in the above activities. 
+In addition, as a result of being subject to these rules and regulations, we may have to accept less director and officer liability
+insurance coverage than we desire or to incur substantial costs to obtain acceptable coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our
+Audit Committee, and qualified executive officers. 
+If Any of the Material Weaknesses Previously Identified by Our Independent Registered
+Public Accountants Persist or if We Fail to Establish and Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. 
+Until February 1, 2012, we were a private company and maintained internal controls and procedures in accordance with being a private
+company. We have maintained limited accounting personnel to perform our 
+54 
+Table of Contents 
+accounting processes and limited supervisory resources with which to address our internal control over financial reporting. In connection with our audits for the years ended December 31,
+2011 and 2010, our independent registered public accountants identified and communicated material weaknesses. In 2010, the material weaknesses related to controls over accounting and reporting for deferred income taxes, impairment of oil and natural
+gas properties, assessment of unproved and unevaluated properties and the administration of our stock and incentive plan. In 2011, the material weakness related only to accounting and reporting for stock compensation expense. 
+A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such
+that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected and corrected on a timely basis. We have begun the process of evaluating our internal control over
+financial reporting and expect to put into place new accounting processes and control procedures to address the weaknesses described above, including the hiring of outside consultants to review significant or complex accounting issues and
+calculations, the implementation of a more formalized closing process, the formation of a disclosure committee and the hiring of additional personnel. 
+As a public company, we are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act, which require our management to certify financial and
+other information in our quarterly and annual reports and to provide an annual management report on the effectiveness of our internal control over financial reporting. We will be required to make our first assessment of our internal control over
+financial reporting for the year ended December 31, 2012. To comply with the requirements of being a public company, we are upgrading our systems, including information technology, implementing additional financial and management controls,
+reporting systems and procedures and have hired additional accounting and financial reporting staff. 
+Further, our independent
+registered public accountants are not yet required to formally attest to the effectiveness of our internal control over financial reporting. Once they are required to do so, our independent registered public accountants may issue a report that is
+adverse in the event they are not satisfied with the level at which our controls are documented, designed, operated or reviewed. Our remediation efforts may not enable us to remedy or avoid material weaknesses in the future. 
+Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over
+our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to remedy or avoid material
+weaknesses in the future. Any failure to remediate deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal control over financial reporting, could result in
+material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also
+cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. 
+We Do Not
+Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. 
+We do not presently intend to
+pay any cash dividends on our common stock. Any payment of future dividends will be at the discretion of the board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness,
+statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems 
+55 
+Table of Contents 
+relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain
+covenants in our credit agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment and there is no
+guarantee that the price of our common stock that will prevail in the market will exceed the price paid by you. 
+The Trading Volume in Our
+Common Stock Has Been Low, and the Sale of a Substantial Number of Shares in the Public Market Could Depress the Price of Our Common Stock. 
+Our common stock is listed on the NYSE, but since the completion of our initial public offering, it has had a relatively low average daily trading volume relative to many other stocks. Thinly traded stock
+can be more volatile than stock trading in an active public market, which can lead to significant price swings even when a relatively small number of shares are being traded and can limit an investor’s ability to quickly sell blocks of stock.
+Shareholders holding more than 75% of our outstanding shares of common stock are subject to lockup agreements that prohibit the disposition of those shares until at least July 30, 2012, subject to certain exceptions. We cannot predict what effect,
+if any, the expiration of these lockups will have on future sales of our common stock in the market, including the availability of our common stock for sale in the market and the market price of our common stock. 
+Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our
+Common Stock. 
+The market price of our common stock could decline as a result of sales of a large number of shares of our
+common stock in the market, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the
+public market after any contractual lockup and other legal restrictions on resale lapse, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the
+future at a time and at a price that we deem appropriate. These sales also could cause our stock price to fall and make it more difficult for you to sell shares of our common stock. 
+We may also sell additional shares of common stock or securities convertible into common stock in subsequent offerings. We cannot predict
+the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities will have on the market price of our common stock. 
+Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects that Could Prevent a Change in Control Even if It
+Might Be Beneficial to Our Shareholders. 
+Our certificate of formation and bylaws contain certain provisions that may
+discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: 
+• 
+authorization for our board of directors to issue preferred stock without shareholder approval; 
+• 
+a classified board of directors so that not all members of our board of directors are elected at one time; 
+• 
+the prohibition of cumulative voting in the election of directors; and 
+• 
+a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.
+56 
+Table of Contents 
+Provisions of Texas law also may discourage, delay or prevent someone from acquiring or
+merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquire us for a period of
+three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our board of directors before this person became an affiliated shareholder or approval of the holders
+of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. 
+Our Board of Directors Can
+Authorize the Issuance of Preferred Stock, which Could Diminish the Rights of Holders of Our Common Stock, and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. 
+Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences
+and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise
+adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a
+change of control of the company, even if that change of control might benefit our shareholders. 
+Item 1B. 
+Unresolved Staff Comments. 
+Not applicable. 
+Item 2. 
+Properties. 
+See
+“Business” for descriptions of our properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Note 12, Commitments and Contingencies , to the consolidated financial
+statements for the future minimum rental payments. Such information is incorporated herein by reference. 
+Item 3. 
+Legal Proceedings. 
+Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business,
+we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us. 
+Item 4. 
+Mine Safety Disclosures 
+Not applicable. 
+57 
+Table of Contents 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+General Market Information 
+On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we
+completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering, and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold
+by us and the selling shareholders pursuant to the partial exercise of the underwriters’ over-allotment on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+On March 30, 2012, we had 55,272,860 shares of common stock outstanding held by approximately 516 record holders, excluding
+shareholders for whom shares are held in “nominee” or “street” name. 
+The following table sets forth the
+high and low sales prices of our common stock as reported by the NYSE for the period indicated: 
+High 
+Low 
+Period from February 2, 2012 to March 30, 2012 
+$ 
+12.33 
+$ 
+10.85 
+On March 30, 2012, the last reported sales price of our common stock on the NYSE was $10.95 per
+share. 
+Dividend Policy 
+We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our
+business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition,
+certain covenants in our credit agreement may limit our ability to pay dividends on our common stock. 
+Prior to consummation
+of our initial public offering, the holders of our Class B common stock were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends accrued and
+were payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding. For the years ended December 31, 2011, 2010 and 2009, we declared dividends on our outstanding shares of Class B common stock totaling $274,853
+in each year. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of our initial public offering, the right of the holders of Class B common stock to dividends was terminated and such holders were paid
+approximately $28,000 during the first quarter of 2012 for all accrued but unpaid dividends existing at the time of such conversion. 
+58 
+Table of Contents 
+Equity Compensation Plan Information 
+The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2011.
+Equity Compensation Plan
+Information 
+Plan Category 
+Number of 
+Shares to be 
+Issued Upon 
+Exercise
+of 
+Outstanding 
+Options, 
+Warrants 
+and 
+Rights 
+Weighted- 
+Average 
+Exercise 
+Price of 
+Outstanding 
+Options, 
+Warrants 
+and
+Rights 
+($) 
+Number of 
+Shares 
+Remaining 
+Available for 
+Future 
+Issuance 
+Under
+Equity 
+Compensation 
+Plans 
+Equity compensation plans approved by security
+holders (1) 
+1,024,500 
+$ 
+9.75 
+– 
+Equity compensation plans not approved by security
+holders (2) 
+– 
+– 
+4,000,000 
+Total 
+1,024,500 
+$ 
+9.75 
+4,000,000 
+(1) 
+Our board of directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan.
+(2) 
+Our 2012 Long-Term Incentive Plan was approved by our board of directors in December 2011 and took effect on January 1, 2012. For a description of our 2012
+Long-Term Incentive Plan, see Note 17 to our consolidated financial statements included elsewhere in this Form 10-K. 
+Recent
+Sales of Unregistered Securities 
+From October 2010 through January 2011, we sold 1,922,199 shares of our common stock to
+accredited investors for the aggregate consideration of $21,144,189. These shares were issued in a transaction exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act and Rule 506. 
+During 2011, we issued an aggregate of 93,001 shares of common stock pursuant to the exercise of stock options held by certain directors
+and employees and received an aggregate of $837,009 for such exercises. The issuance of these shares was exempt from the registration requirements of the Securities Act pursuant to Rule 701. 
+During 2011, we issued an aggregate of 17,500 shares of our common stock to our outside directors and advisors in connection with their
+service to the board. These shares were issued in transactions exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act. 
+In October 2011, we issued an aggregate of 2,575 shares of our common stock to General Mills, Inc. Benefits Finance Committee on behalf of General Mills Group Trust and Voluntary Employees Beneficiary
+Assoc. Trust General Mills & Bakery, Confectionary, Tobacco & Grain Millers in connection with prior service on the board by officers of General Mills, Inc. Benefits Finance Committee. These shares were issued in transactions
+exempt from the registration requirements of the Securities Act under Section 4(2) of the Securities Act. 
+59 
+Table of Contents 
+Use of Proceeds 
+Our initial public offering of common stock was effected through a Registration Statement on Form S-1 (File No. 333-176263), which was declared effective by the SEC on February 1, 2012. RBC
+Capital Markets, LLC; Citigroup Global Markets Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Stephens Inc.; and Comerica Securities, Inc. acted as underwriters for the
+offering. RBC Capital Markets, LLC and Citigroup Global Markets Inc. acted as the co-managers for the offering. Under the Form S-1, we registered the offer and sale of an aggregate of 15,333,334 shares of our common stock, 12,209,167 shares of which
+were issued and sold by us and 2,674,167 shares of which were sold by the selling shareholders named in the Form S-1, including shares sold by us and certain of the selling shareholders pursuant to the partial exercise of the underwriters’
+option to purchase additional shares. The initial public offering closed on February 7, 2012 and the over-allotment option closed on March 7, 2012. We issued and sold all but 450,000 of the shares that were registered. 
+The shares were sold at a price to the public of $12.00 per share and we received cash proceeds of approximately $133.6 million from this
+transaction, net of underwriting discounts and commissions. We did not receive any proceeds from the sale of shares by the selling shareholders. The underwriters received underwriting discounts and commissions totaling approximately $9.9 million,
+and we incurred additional costs of approximately $3.0 million in connection with the offering, which amounted to total fees and costs of approximately $12.9 million. No offering costs were paid directly or indirectly to any of our directors or
+officers (or their associates) or persons owning 10% or more of any class of our equity securities or to any other affiliates, other than advancement of legal fees for one counsel to represent the selling shareholders. 
+We used $123.0 million to repay the then outstanding borrowings under our credit agreement. We used the remaining proceeds to fund a
+portion of our 2012 capital expenditure requirements. 
+Item 6. 
+Selected Financial Data. 
+You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this report. The financial information included in this report may not be indicative of our future results
+of operations, financial position or cash flows. 
+60 
+Table of Contents 
+The following selected financial information is summarized from our results of operations
+for the five-year period ended December 31, 2011 and selected consolidated balance sheet data at December 31, 2011, 2010, 2009, 2008 and 2007 and should be read in conjunction with the consolidated financial statements at the years ended
+December 31, 2011, 2010 and 2009 included herewith. 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+(In thousands) 
+Statement of operations data: 
+Revenues: 
+Oil and natural gas revenues 
+$ 
+67,000 
+$ 
+34,042 
+$ 
+19,039 
+$ 
+30,645 
+$ 
+13,988 
+Realized gain (loss) on derivatives 
+7,106 
+5,299 
+7,625 
+(1,326 
+) 
+213 
+Unrealized gain (loss) on derivatives 
+5,138 
+3,139 
+(2,375 
+) 
+3,592 
+(211 
+) 
+Total revenues 
+79,244 
+42,480 
+24,289 
+32,911 
+13,990 
+Expenses: 
+Production taxes and marketing 
+6,278 
+1,982 
+1,077 
+1,639 
+779 
+Lease operating 
+7,244 
+5,284 
+4,725 
+4,667 
+3,099 
+Depletion, depreciation and amortization 
+31,754 
+15,596 
+10,743 
+12,127 
+7,889 
+Accretion of asset retirement obligations 
+209 
+155 
+137 
+92 
+70 
+Full-cost ceiling impairment 
+35,673 
+– 
+25,244 
+22,195 
+– 
+General and administrative 
+13,394 
+9,702 
+7,115 
+8,252 
+5,189 
+Total expenses 
+94,552 
+32,719 
+49,041 
+48,972 
+17,026 
+Operating (loss) income 
+(15,308 
+) 
+9,761 
+(24,752 
+) 
+(16,061 
+) 
+(3,036 
+) 
+Other (expense) income: 
+Net (loss) gain on asset sales and inventory impairment 
+(154 
+) 
+(224 
+) 
+(379 
+) 
+136,977 
+– 
+Interest expense 
+(683 
+) 
+(3 
+) 
+– 
+– 
+– 
+Interest and other income 
+315 
+364 
+781 
+2,984 
+2,736 
+Total other (expense) income 
+(522 
+) 
+137 
+402 
+139,962 
+2,736 
+Net (loss) income 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+$ 
+103,878 
+$ 
+(300 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+$ 
+2.50 
+$ 
+(0.05 
+) 
+Class B 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+$ 
+2.77 
+$ 
+0.22 
+Diluted 
+Class A 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+$ 
+2.46 
+$ 
+(0.05 
+) 
+Class B 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+$ 
+2.73 
+$ 
+0.22 
+Class B dividend declared, per share 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+61 
+Table of Contents 
+At December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+(In thousands) 
+Balance sheet data: 
+Cash and cash equivalents 
+$ 
+10,284 
+$ 
+21,060 
+$ 
+104,230 
+$ 
+150,768 
+$ 
+9,017 
+Certificates of deposit 
+1,335 
+2,349 
+15,675 
+20,782 
+– 
+Short-term investments 
+– 
+– 
+– 
+– 
+57,925 
+Net property and equipment 
+399,865 
+303,880 
+142,078 
+125,261 
+105,814 
+Total assets 
+439,469 
+346,382 
+277,400 
+314,539 
+179,152 
+Current liabilities 
+74,576 
+30,097 
+8,868 
+35,475 
+5,541 
+Long term liabilities 
+93,377 
+34,408 
+4,210 
+2,059 
+1,568 
+Total shareholders’ equity 
+$ 
+271,515 
+$ 
+281,877 
+$ 
+264,321 
+$ 
+277,005 
+$ 
+172,043 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+Other financial data: 
+Net cash provided by operating activities 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+$ 
+25,851 
+$ 
+7,881 
+Net cash (used in) provided by investing activities 
+(160,088 
+) 
+(147,334 
+) 
+(49,415 
+) 
+115,481 
+(108,296 
+) 
+Oil and natural gas properties capital expenditures 
+(156,431 
+) 
+(159,050 
+) 
+(54,244 
+) 
+(104,119 
+) 
+(50,310 
+) 
+Expenditures for other property and equipment 
+(4,671 
+) 
+(1,610 
+) 
+(307 
+) 
+(3,012 
+) 
+(1,300 
+) 
+Net cash provided by financing activities 
+87,444 
+36,891 
+1,086 
+419 
+66,250 
+Adjusted EBITDA (1) 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+$ 
+18,411 
+$ 
+8,090 
+(1) 
+Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash
+provided by operating activities, see “Non-GAAP Financial Measures” below. 
+Non-GAAP Financial
+Measures 
+We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and
+amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, non-recurring income and expenses and non-cash stock-based compensation expense, including stock option and grant expense and
+restricted stock grants. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial
+statements, such as industry analysts, investors, lenders and rating agencies. 
+Management believes Adjusted EBITDA is
+necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss)
+in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were
+acquired. 
+Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from
+operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial
+performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The
+following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. 
+62 
+Table of Contents 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+(In thousands) 
+Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): 
+Net (loss) income 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+$ 
+103,878 
+$ 
+(300 
+) 
+Interest expense 
+683 
+3 
+– 
+– 
+– 
+Total income tax (benefit) provision 
+(5,521 
+) 
+3,521 
+(9,925 
+) 
+20,023 
+– 
+Depletion, depreciation and amortization 
+31,754 
+15,596 
+10,743 
+12,127 
+7,889 
+Accretion of asset retirement obligations 
+209 
+155 
+137 
+92 
+70 
+Full-cost ceiling impairment 
+35,673 
+– 
+25,244 
+22,195 
+– 
+Unrealized (gain) loss on derivatives 
+(5,138 
+) 
+(3,139 
+) 
+2,375 
+(3,592 
+) 
+211 
+Stock option and grant expense 
+2,362 
+824 
+622 
+605 
+205 
+Restricted stock grants 
+44 
+74 
+34 
+60 
+15 
+Net loss (gain) on asset sales and inventory impairment 
+154 
+224 
+379 
+(136,977 
+) 
+– 
+Adjusted EBITDA 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+$ 
+18,411 
+$ 
+8,090 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+2008 
+2007 
+(In thousands) 
+Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: 
+Net cash provided by operating activities 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+$ 
+25,851 
+$ 
+7,881 
+Net change in operating assets and liabilities 
+(12,594 
+) 
+(2,230 
+) 
+15,717 
+(17,888 
+) 
+209 
+Interest expense 
+683 
+3 
+– 
+– 
+– 
+Current income tax (benefit) provision 
+(46 
+) 
+(1,411 
+) 
+(2,324 
+) 
+10,448 
+– 
+Adjusted EBITDA 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+$ 
+18,411 
+$ 
+8,090 
+63 
+Table of Contents 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our
+consolidated financial statements and related notes appearing elsewhere in this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution
+that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our
+expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the
+commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or
+litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the
+forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” 
+Overview
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and
+natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the
+Haynesville shale play in northwest Louisiana and east Texas. We expect the majority of our near-term capital expenditures will focus primarily on increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the
+Eagle Ford shale play will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. In addition to these primary operating areas, we have acreage positions in southeast New
+Mexico and west Texas and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify new oil and natural gas prospects. 
+We were founded in July 2003 by Mr. Joseph Wm. Foran and Mr. Scott E. King, and we drilled our first well in 2004. Since that time, we have drilled or participated in drilling 236 wells
+through December 31, 2011, including 106 Haynesville and nine Eagle Ford wells. At December 31, 2011, based on the reserves audit by our independent reservoir engineers, we had 193.2 Bcfe of estimated proved reserves with a PV-10 of $248.7
+million and a Standardized Measure of $215.5 million. At December 31, 2011, 34% of our estimated proved reserves were proved developed reserves, 12% of our estimated proved reserves were oil and 88% of our estimated proved reserves were natural
+gas. Our average daily production for the year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of natural gas per day and 422 Bbl of oil per day, as compared to an average daily production of 23.6 MMcfe per day, including
+23.0 MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31, 2010. We have achieved this growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses)
+from $1.16 per Mcfe for the year ended December 31, 2009 to $0.88 per Mcfe for the year ended December 31, 2011, or a decrease of approximately 24%. 
+Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy.
+Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory
+storage levels, natural gas price differentials and other factors. Prices for oil 
+64 
+Table of Contents 
+and natural gas will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil or natural gas prices would not only
+reduce our revenues, but could also reduce the amount of oil and/or natural gas that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. 
+In response to the recent commodity price environment, and in particular, the general decline in natural gas prices since July 2008 in
+contrast with the rebound in oil prices since February 2009, we have sought to balance our exploration and development plans by targeting more oil prone reservoirs, such as the Eagle Ford shale. While most of our historical and current production is
+natural gas, we believe that our future production profile will reflect a more balanced oil and natural gas commodity mix as a result of our strategic shift to target more oil development than we have historically. 
+In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub
+natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploratory prospects like the Meade Peak shale, until
+natural gas prices improved substantially from these levels or unless the costs to drill and complete these wells were also to decline substantially from their recent levels. See “Risk Factors – Our Identified Drilling Locations Are
+Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” 
+During 2012, we intend to allocate 84% of our 2012 capital expenditure budget of $313.0 million to the exploration, development and acquisition of additional interests in the Eagle Ford shale play.
+Including these anticipated capital expenditures in the Eagle Ford shale, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted $313.0
+million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results. 
+As we transition our operations from the Haynesville shale and Cotton Valley in northwest Louisiana to the Eagle Ford shale in south Texas, we may face challenges associated with establishing operations
+and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to transport, process and market the oil and natural gas that we produce. We may also incur higher than
+anticipated costs associated with establishing new operating infrastructure and facilities on our leases throughout the area. We believe we have successfully secured the necessary drilling and completion services for our current Eagle Ford
+operations, and at March 30, 2012, we had two contracted drilling rigs operating in south Texas: one in LaSalle County and one in Karnes County. We are not currently experiencing difficulties in securing completion, and particularly hydraulic
+fracturing services, for our newly drilled wells, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and
+completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors – The Unavailability or High Cost of Drilling Rigs, Completion
+Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could
+Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+We experienced
+temporary pipeline interruptions from time to time during 2011 associated with natural gas production from our Eagle Ford wells and have been required to either shut in wells for brief periods or to flare some of the natural gas we produce. At March
+30, 2012, we were experiencing pipeline 
+65 
+Table of Contents 
+capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the natural gas we are producing there as a result. We believe that these pipeline
+interruptions and capacity constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to shut
+in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors – The Marketability of
+Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Agreements Would Have a Material Adverse
+Effect on Our Revenue.” 
+On February 2, 2012, our common stock began trading on the NYSE under the symbol
+“MTDR.” We believe that our general and administrative expenses will increase as a result of us operating as a public company. This increase will consist primarily of legal and accounting fees and additional expenses associated with
+compliance with the Sarbanes-Oxley Act and other regulations and increases in our staff compensation and other ongoing general and administrative expenses necessary to maintain and grow a publicly traded exploration and production company. A large
+part of this increase will be due to the cost of accounting and legal support services, filing annual and quarterly reports with the SEC, investor relations activities, directors’ fees, incremental directors’ and officers’ liability
+insurance costs and transfer and registrar agent fees. As a result, we believe that our general and administrative expenses for future periods will increase significantly. Our consolidated financial statements for future periods will reflect the
+impact of these increased expenses and affect the comparability of our financial statements with periods before the completion of this offering. 
+Revenues 
+Our revenues are derived primarily from the sale of oil and
+natural gas production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil or natural gas prices. 
+Realized gain (loss) on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil and natural gas prices. This revenue item includes the net
+realized cash gains and losses associated with the settlement of these derivative financial instruments for a given reporting period. 
+Unrealized gain (loss) on derivatives . We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil and natural gas prices. This revenue item recognizes the
+non-cash change in the fair value of our open derivative contracts between reporting periods. 
+66 
+Table of Contents 
+The following table summarizes our revenues and production data for the periods indicated:
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Operating Results: 
+Revenues (in thousands): 
+Oil 
+$ 
+14,457 
+$ 
+2,507 
+$ 
+1,719 
+Natural gas 
+52,543 
+31,535 
+17,320 
+Total oil and natural gas revenues 
+67,000 
+34,042 
+19,039 
+Realized gain (loss) on derivatives 
+7,106 
+5,299 
+7,625 
+Unrealized gain (loss) on derivatives 
+5,138 
+3,139 
+(2,375 
+) 
+Total revenues 
+$ 
+79,244 
+$ 
+42,480 
+$ 
+24,289 
+Net Production Volumes: 
+Oil (MBbls) 
+154 
+33 
+30 
+Natural gas (Bcf) 
+14.5 
+8.4 
+4.8 
+Total natural gas equivalents (Bcfe)
+(1) 
+15.4 
+8.6 
+5.0 
+Average net daily production (MMcfe/d)
+(1) 
+42.3 
+23.6 
+13.7 
+Average Sales Prices: 
+Oil (per Bbl) 
+$ 
+93.80 
+$ 
+76.39 
+$ 
+57.72 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+4.11 
+$ 
+4.38 
+$ 
+5.17 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+3.62 
+$ 
+3.75 
+$ 
+3.59 
+(1) 
+Estimated using a conversion ratio of one Bbl per six Mcf. 
+Year Ended December 31, 2011 as Compared to Year Ended December 31, 2010 
+Oil and natural gas revenues . Our oil and natural gas revenues increased by $33.0 million to $67.0 million, or an increase of about 97%, for the year ended December 31, 2011 as compared to the
+year ended December 31, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 79% in our oil and natural gas production to 15.4 Bcfe for the year ended December 31, 2011 from 8.6 Bcfe for the year ended
+December 31, 2010. This increased production was almost entirely due to drilling operations in the Eagle Ford and Haynesville shales. A portion of the increase in oil and natural gas revenues reflects the approximate five-fold increase in our
+oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price of $93.80 per Bbl realized during 2011 as compared to an average oil price of $76.39 per Bbl
+realized during 2010. 
+Realized gain (loss) on derivatives . Our realized gain on derivatives increased by approximately
+$1.8 million to $7.1 million for the year ended December 31, 2011 from $5.3 million for the year ended December 31, 2010. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the
+decline in natural gas prices during the comparable periods. We realized approximately $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011 as compared to $0.89 per MMBtu hedged
+on all of our open natural gas costless collar contracts during the year ended December 31, 2010. Our total natural gas volumes hedged for the year ended December 31, 2011 were also approximately 16% higher than the total natural gas
+volumes hedged for 2010. 
+Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately
+$5.14 million for the year ended December 31, 2011 as compared to an unrealized gain of $3.14 million for the year ended December 31, 2010. During the period from December 31, 2010 to December 31, 2011, the net fair value of our
+open natural gas costless collar contracts increased from approximately $4.14 million to approximately $9.28 million, resulting in an unrealized gain on derivatives of approximately $5.14 million for the year ended December 31, 2011. This
+increase in the net fair value of our open natural gas costless collar contracts was due primarily to a decrease in natural gas prices during 2011 as compared to 2010, as well as an increase in the total number of our open contracts at
+December 31, 2011 as compared to December 31, 2010. 
+67 
+Table of Contents 
+Year Ended December 31, 2010 as Compared to Year Ended December 31, 2009
+Oil and natural gas revenues. Our oil and natural gas revenues increased by $15.0 million to
+$34.0 million, or an increase of about 79%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Approximately $13.7 million of the increase was primarily due to a 72% increase in our production to 8.6
+Bcfe during the year ended December 31, 2010 from 5.0 Bcfe during the year ended December 31, 2009, and approximately $1.3 million of the increase was due to increases in the average prices we received for both oil and natural gas over
+these respective periods. For the year ended December 31, 2010, we received an average natural gas price of $3.75 per Mcf and an average oil price of $76.39 per Bbl as compared to an average natural gas price of $3.59 per Mcf and an average oil
+price of $57.72 per Bbl for the year ended December 31, 2009. Our increased production during this period was primarily due to drilling operations in the Haynesville shale. 
+Realized gain (loss) on derivatives . Our realized gain on derivatives decreased by approximately $2.3 million to $5.3 million
+for the year ended December 31, 2010 from $7.6 million for the year ended December 31, 2009. This decrease was due primarily to a decrease of about $1.50 per MMBtu in the average price floor of our open natural gas costless collar
+contracts in 2010 as compared with 2009 and despite the fact that we had almost twice the natural gas volumes hedged in 2010 as compared to 2009. 
+Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was $3.14 million for the year ended December 31, 2010, compared to an unrealized loss of $2.38 million for the year
+ended December 31, 2009. During the period from December 31, 2009 to December 31, 2010, the net fair value of our open natural gas costless collar contracts increased from $1.00 million to $4.14 million, resulting in an unrealized
+gain on derivatives of $3.14 million for the year ended December 31, 2010. This increase in the net fair value of our open natural gas costless collar contracts was due primarily to lower natural gas prices at December 31, 2010 as compared
+to December 31, 2009. 
+Expenses 
+Production taxes and marketing. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates
+established by federal, state or local taxing authorities. We attempt to take advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes in our oil and
+natural gas revenues. Marketing expenses are fees charged by the purchasers of the oil and natural gas we produce and sell and principally include marketing, compression and transportation fees. 
+Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil and natural gas, as well as the
+daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional workover expenses related to our oil and natural gas
+properties. 
+Depletion, depreciation and amortization . Depletion, depreciation and amortization includes the systematic
+expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and
+development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration or development activities and do not include
+any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of
+68 
+Table of Contents 
+proved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion, depreciation and amortization.
+Accretion of asset retirement obligations . Asset retirement obligations relate to the future costs associated with
+plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. We recognize the fair value of an asset retirement obligation in the period it is
+incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and
+facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in our statement of operations. 
+Full-cost ceiling impairment . The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center
+ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil
+and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less
+(d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these reserves. The fair value of our derivative
+instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. 
+General and administrative expenses. General and administrative expenses include, but are not limited to, compensation and benefits for our employees, costs of renting and maintaining our
+headquarters, office service contracts, board of directors fees, franchise taxes, stock-based compensation expense and accounting, legal and other professional fees. 
+Other Income (Expense) 
+Net gain (loss) on asset sales and inventory
+impairment . This other income (expense) item includes the net gain or loss we experience on infrequent asset sales or impairment charges associated with certain equipment held in inventory. This item also includes infrequent sales of oil and
+natural gas properties that we consider to be extraordinary when considered in relation to the normal course of our business. 
+Interest expense. Interest expense includes interest paid to our lenders as a result of borrowings under our revolving credit
+agreement. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under the credit agreement, and as a result, we incur interest expense that is affected by both fluctuations in interest rates
+and our financing decisions. In addition, we include any amortization of deferred financing costs (including origination and amendment fees), commitment or facility fees and annual agency fees as interest expense. 
+Interest and other income . Interest income includes interest earned periodically on the cash and cash equivalents we hold in money
+market accounts composed of United States Treasury securities offering daily liquidity and the interest earned periodically on our certificates of deposit. Other income includes income we receive for providing salt water disposal and natural gas
+transportation services to other working interest participants in wells that we operate. 
+69 
+Table of Contents 
+Total income tax provision (benefit) . Total income tax provision (benefit) includes
+the net current and deferred portions of our estimated income tax liabilities. We file a United States federal income tax return and state tax returns in those states where we conduct oil and natural gas operations. The current portion of our income
+tax provision (benefit) reflects actual income tax payments made or refunds received by us as a result of filing these income tax returns. The deferred portion of our income tax provision is the result of temporary timing differences between the
+financial statement carrying values and the tax bases of our assets and liabilities. 
+The following table summarizes our
+operating expenses and other income (expense) for the periods indicated: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+(In thousands, except expenses per Mcfe) 
+Expenses: 
+Production taxes and marketing 
+$ 
+6,278 
+$ 
+1,982 
+$ 
+1,077 
+Lease operating 
+7,244 
+5,284 
+4,725 
+Depletion, depreciation and amortization 
+31,754 
+15,596 
+10,743 
+Accretion of asset retirement obligations 
+209 
+155 
+137 
+Full-cost ceiling impairment 
+35,673 
+– 
+25,244 
+General and administrative 
+13,394 
+9,702 
+7,115 
+Total expenses 
+94,552 
+32,719 
+49,041 
+Operating (loss) income 
+(15,308 
+) 
+9,761 
+(24,752 
+) 
+Other (expense) income: 
+Net loss on asset sales and inventory impairment 
+(154 
+) 
+(224 
+) 
+(379 
+) 
+Interest expense 
+(683 
+) 
+(3 
+) 
+– 
+Interest and other income 
+315 
+364 
+781 
+Total other (expense) income 
+(522 
+) 
+137 
+402 
+(Loss) income before income taxes 
+(15,830 
+) 
+9,898 
+(24,350 
+) 
+Total income tax (benefit) provision 
+(5,521 
+) 
+3,521 
+(9,925 
+) 
+Net (loss) income 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+Expenses per Mcfe: 
+Production taxes and marketing 
+$ 
+0.41 
+$ 
+0.23 
+$ 
+0.22 
+Lease operating 
+$ 
+0.47 
+$ 
+0.61 
+$ 
+0.94 
+Depletion, depreciation and amortization 
+$ 
+2.06 
+$ 
+1.81 
+$ 
+2.15 
+General and administrative 
+$ 
+0.87 
+$ 
+1.13 
+$ 
+1.42 
+Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 
+Production taxes and marketing. Our production taxes and marketing expenses increased by $4.3 million to $6.3 million, or an
+increase of approximately 217% for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our production taxes and marketing expenses reflects the increases in both our oil and natural gas
+production and revenues by 79% and 97%, respectively, during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The majority of this increase was due to higher marketing, transportation and compression
+charges on portions of our non-operated Haynesville shale production in 2011 as compared to 2010. Some of this increase was also due to Haynesville shale wells completed in 2011, several of which were turned to sales or produced their first
+significant production volumes during 2011. Although we or our outside operating partners have applied for exemptions from initial production taxes on these recently completed Haynesville shale wells, and although we expect these applications will
+be approved by the state of Louisiana, some of these wells had not yet been approved for production tax exemptions at December 31, 2011. Thus, we have paid and/or accrued for the associated production taxes on these wells during the year ended
+December 31, 2011, although we expect these production taxes will be refunded to us in future periods. We will adjust our production taxes and marketing 
+70 
+Table of Contents 
+expenses accordingly when and if these production tax exemptions are approved. The remainder of the increase in production taxes and marketing expenses for the year ended December 31, 2011
+was due to production taxes paid on production from our initial Eagle Ford shale wells in south Texas. 
+Lease operating
+expenses. Our lease operating expenses increased by $2.0 million to $7.2 million, or an increase of about 37%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. During these respective periods,
+however, our oil and natural gas production increased 79% from 8.6 Bcfe to 15.4 Bcfe. As a result, our lease operating expenses per unit of production decreased by 23% to $0.47 per Mcfe for the year ended December 31, 2011 as compared to $0.61
+per Mcfe for the year ended December 31, 2010. During the year ended December 31, 2011, both our total Haynesville shale production, as well as the percentage of our Haynesville production for which we were the operator increased, as
+compared to the year ended December 31, 2010. The unit lease operating costs associated with the Haynesville production are much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water
+disposal costs associated with the Cotton Valley production and given the early stages of production associated with many of these Haynesville wells. 
+Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $16.2 million to $31.8 million, or an increase of about 104%, for the year ended
+December 31, 2011 as compared to the year ended December 31, 2010. The increase in our depletion, depreciation and amortization expenses was due primarily to an increase of approximately 79% in our oil and natural gas production from 8.6
+Bcfe to 15.4 Bcfe during the respective time periods. Our depletion, depreciation and amortization expenses on a unit-of-production basis increased to $2.06 for the year ended December 31, 2011, or an increase of about 14%, from $1.81 per Mcfe
+for the year ended December 31, 2010. This per unit increase reflects increases in drilling and completion costs for wells drilled to the Haynesville shale during 2011, as well as higher drilling and completion costs on a per Mcfe basis
+associated with oil reserves added in the Eagle Ford shale in south Texas. 
+Accretion of asset retirement obligations .
+Our accretion of asset retirement obligations expenses increased by approximately $54,000 to approximately $209,000, or an increase of about 35%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The
+increase in our accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an
+insignificant component of our overall expenses. 
+Full-cost ceiling impairment. During the quarter ended March 31,
+2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs
+of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our expenses for the year ended December 31, 2011. No impairment to the net carrying value of our oil and natural gas properties on
+the balance sheet resulting from the full-cost ceiling limitation was recorded at December 31, 2010. 
+General and
+administrative. Our general and administrative expenses increased by $3.7 million to $13.4 million, or an increase of about 38%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in our
+general and administrative expenses was due primarily to increased cash and non-cash compensation expenses and increased accounting expenses for the year ended December 31, 2011 as compared to the year ended December 31, 2010. We recorded
+approximately $2.4 million in non-cash compensation expense for the year ended December 31, 2011 as compared to approximately $0.9 million recorded for the year ended December 31, 2010. This increase was primarily
+71 
+Table of Contents 
+due to a change in accounting method for valuing our outstanding stock options. We awarded no new stock options during 2011. As a result of our increased oil and natural gas production, however,
+our general and administrative expenses decreased by 27% on a unit-of-production basis to $0.87 per Mcfe for the year ended December 31, 2011 as compared to $1.13 per Mcfe for the year ended December 31, 2010. 
+Net gain (loss) on asset sales and inventory impairment . We incurred a loss on asset sales and inventory impairment of
+approximately $154,000 for the year ended December 31, 2011, as compared to a loss of approximately $224,000 for the year ended December 31, 2010. During the year ended December 31, 2011, this loss was primarily related to the sale of
+pipe and other equipment and the impairment of certain equipment held in inventory, consisting primarily of drilling rig parts. During the year ended December 31, 2010, we wrote off the Boise South pipeline asset in Orange County, Texas and
+recognized a net loss of approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment, consisting primarily of drilling
+rig parts, was less than the cost. 
+Interest expense. For the year ended December 31, 2011, we incurred total
+interest expense of approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2011 and expensed the remaining $683,000 to operations. During the
+year ended December 31, 2011, we incurred incremental net borrowings of $88.0 million under our credit agreement to finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at December 31,
+2011 were $113.0 million, and the interest rate on these borrowings was approximately 5.3% per annum. In early January 2012, we converted this $113.0 million base rate advance to a Eurodollar-based advance, which then bore interest at 3.5% per
+annum. In December 2010, we borrowed $25.0 million under our credit agreement to finance a portion of our working capital requirements and capital expenditures, which remained outstanding at December 31, 2010. We incurred interest expense of
+approximately $3,000 for the year ended December 31, 2010. 
+Interest and other income. Our interest and other
+income decreased by approximately $50,000 to approximately $314,000, or a decrease of about 14%, for the year ended December 31, 2011 as compared to the year ended December 31, 2010. The decrease in our interest and other income was due
+primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we received interest income between the two periods. Our cash and cash equivalents and certificates of deposit decreased to
+approximately $11.6 million at December 31, 2011 from approximately $23.4 million at December 31, 2010, as we used cash and incremental borrowings to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in
+the core area of the Haynesville shale play in northwest Louisiana and to fund our operated and non-operated drilling and completion activities in both areas. 
+Total income tax provision (benefit) . We recorded a total income tax benefit of approximately $5.5 million for the year ended December 31, 2011 as compared to a total income tax provision of
+approximately $3.5 million for the year ended December 31, 2010. The total income tax benefit for the year ended December 31, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax
+refund of approximately $46,000 recorded during this period. During the first quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by
+$23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million. We recorded a total income tax provision of
+approximately $3.5 million for the year ended December 31, 2010. The total income tax provision for the year ended December 31, 2010 included a deferred income tax provision of approximately $4.9 million and a current income tax benefit of
+approximately $1.4 million, which was attributable to a refund of U.S. federal income taxes received by us. For the year ended 
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+Table of Contents 
+December 31, 2010, the deferred income tax provision was consistent with our income before income taxes, which included approximately $3.1 million in unrealized hedging gains. We had a net
+loss for the year ended December 31, 2011, and our effective tax rate for the year ended December 31, 2010 was 35.57%. 
+Year Ended December 31, 2010 Compared to Year Ended December 31, 2009 
+Production taxes and marketing. Our production taxes and marketing expenses increased by $0.9 million to $2.0 million, or an increase of about 84%, for the year ended December 31, 2010 as
+compared to the year ended December 31, 2009. The increase in our production taxes and marketing expenses was due primarily to the increase in our oil and natural gas revenues from $19.0 million to $34.0 million, or an increase of about 79%,
+during the respective time periods. On a unit-of-production basis, our production taxes and marketing expenses remained relatively constant year-over-year, increasing to $0.23 per Mcfe for the year ended December 31, 2010 from $0.22 per Mcfe
+for the year ended December 31, 2009. 
+Lease operating expenses. Our lease operating expenses increased by
+$0.6 million to $5.3 million, or an increase of about 12%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. During these respective periods, however, our oil and natural gas production increased
+72% to 8.6 Bcfe from 5.0 Bcfe. As a result, our lease operating expenses per unit of production decreased by 35% to $0.61 per Mcfe for the year ended December 31, 2010 as compared to $0.94 per Mcfe for the year ended December 31, 2009. In
+2010, the percentage of our production attributed to the Haynesville shale continued to increase. The unit lease operating costs associated with the Haynesville production are much less than those associated with our Cotton Valley natural gas
+production, primarily due to the greater salt water disposal costs associated with the Cotton Valley production. 
+Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $4.9 million to
+$15.6 million, or an increase of about 45%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our depletion, depreciation and amortization expenses was due primarily to the increase in
+our oil and natural gas production to 8.6 Bcfe from 5.0 Bcfe during the respective time periods. The finding and development costs associated with our Haynesville shale reserves have been less than finding and development costs associated with our
+reserves producing from the Cotton Valley and other formations. As a result, our depletion, depreciation and amortization expenses on a unit-of-production basis decreased as our Haynesville production increased; these expenses decreased to $1.81 per
+Mcfe during the year ended December 31, 2010 from $2.15 per Mcfe during the year ended December 31, 2009. 
+Accretion of asset retirement obligations . Our accretion of asset retirement obligations expenses increased by approximately
+$18,000 to approximately $155,000, or an increase of about 13%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in our accretion of asset retirement obligations was due primarily to the
+addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses. 
+Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties on the balance
+sheet resulting from the full-cost ceiling limitation was recorded at December 31, 2010. At December 31, 2009, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center
+ceiling by $16.3 million. As a result, we recorded an impairment charge of $25.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $8.9 million. A corresponding charge of $25.2 million was
+also recorded to the consolidated statement of operations for the year ended December 31, 2009. 
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+Table of Contents 
+General and administrative. Our general and administrative expenses increased by
+$2.6 million to $9.7 million, or an increase of about 36%, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Approximately $1.0 million of this increase was due to legal and other due diligence fees
+resulting from an unsuccessful effort to acquire oil and natural gas producing properties and associated acreage. The remainder of the increase was due primarily to increased compensation expenses resulting from both increased salaries and retention
+and performance bonuses paid to certain employees during the year ended December 31, 2010. As a result of our increased oil and natural gas production, however, our general and administrative expenses decreased by 20% on a unit-of-production
+basis to $1.13 per Mcfe for the year ended December 31, 2010 as compared to $1.42 per Mcfe for the year ended December 31, 2009. 
+Net gain (loss) on asset sales and inventory impairment . During the year ended December 31, 2010, we wrote off the Boise South Pipeline asset in Orange County, Texas and recognized a net loss
+of approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment, consisting primarily of drilling rig parts, was less
+than the cost. During the year ended December 31, 2009, we recognized impairments to these drilling rig parts and tubular goods held in inventory and sold rod parts held in inventory, recognizing a net loss of approximately $379,000.
+Interest expense. In December 2010, we borrowed $25.0 million under our credit agreement to finance a portion of our
+working capital requirements and capital expenditures. We incurred approximately $3,000 in interest expense for the year ended December 31, 2010. At December 31, 2010, the interest rate on the outstanding borrowings was approximately 1.6%
+per annum. We had no borrowings under the credit agreement in 2009, and as a result, we incurred no interest expense for the year ended December 31, 2009. 
+Interest and other income. Our interest and other income decreased by approximately $0.4 million to approximately $0.4 million, or a decrease of about 53%, for the year ended December 31,
+2010 as compared to the year ended December 31, 2009. The decrease in our interest and other income was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we receive
+interest income during the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our cash and cash equivalents and certificates of deposit decreased to $23.4 million at December 31, 2010 from $119.9 million at
+December 31, 2009, as we used cash during this period primarily to acquire additional leasehold acreage in the Eagle Ford shale play in south Texas and in the core area of the Haynesville shale play in northwest Louisiana and to fund our
+operated and non-operated drilling and completion activities in both areas. 
+Total income tax provision (benefit). We
+recorded a total income tax provision of approximately $3.5 million for the year ended December 31, 2010 as compared to a total income tax benefit of approximately $9.9 million recorded for the year ended December 31, 2009. For the year
+ended December 31, 2010, we recorded a current income tax benefit of approximately $1.4 million, which was attributable to a refund of U.S federal income taxes received by us, and we also recorded a deferred income tax provision of $4.9 million
+consistent with the increase in our income before income taxes for that year. For the year ended December 31, 2009, we recorded a current income tax benefit of approximately $2.3 million, primarily attributable to a net refund of U.S. federal
+income taxes and a refund of income taxes from the state of Louisiana. We also recorded a deferred income tax benefit of approximately $7.6 million, primarily attributable to the full-cost ceiling impairment recorded in 2009. Our effective tax rate
+for the year ended December 31, 2010 was 35.57%, and we had a net loss for the year ended December 31, 2009. 
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+Table of Contents 
+Liquidity and Capital Resources 
+Prior to the consummation of our initial public offering on February 7, 2012, our primary sources of liquidity were capital
+contributions from private investors, our cash flows from operations, borrowings under our credit agreement and the proceeds from a significant sale of a portion of our assets in 2008. Our primary use of capital has been, and will continue to be
+during 2012 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including equity and debt financings and additional borrowings, in
+order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital. At December 31, 2011, we had
+cash and certificates of deposits totaling approximately $11.6 million. 
+In December 2011, we amended and restated our senior
+secured revolving credit agreement for which Comerica Bank serves as administrative agent. This amendment increased the maximum facility amount from $150.0 million to $400.0 million. Borrowings are limited to the lesser of $400.0 million or the
+borrowing base. At December 31, 2011, the borrowing base was $125.0 million, and we had $113.0 million of outstanding indebtedness, excluding $1.3 million in outstanding letters of credit. Subsequent to year end, we used the net proceeds from
+our initial public offering to repay the outstanding indebtedness under our credit agreement in full and our borrowing base was reduced to $100.0 million. On February 28, 2012, our borrowing base increased to $125.0 million pursuant to a
+borrowing base redetermination made by the lenders at our request. We may request additional redeterminations in accordance with our credit agreement as we increase our proved reserves. The new amended and restated credit agreement matures in
+December 2016. In March 2012, we borrowed $15.0 million under the credit agreement to finance a portion of our working capital requirements. At March 30, 2012, our borrowings bore interest at a variable rate of 1.75% plus a Eurodollar-based
+rate per annum, which equated to approximately 2.0% per annum. 
+We actively review acquisition opportunities on an
+ongoing basis. While we believe our cash and cash equivalents, together with our cash flows and future potential borrowings under our credit agreement, will be adequate to fund our capital expenditure requirements and any acquisitions of interests
+and acreage for 2012, funding for future acquisitions of interests and acreage or our future capital expenditure requirements for 2013 and subsequent years may require additional sources of financing, which may not be available. As a result of our
+anticipated increases in production and reserves, we expect to have a sufficient increase in our cash flows from operations during the year ending December 31, 2012, as compared to our cash flows from operations in prior periods, as well as a
+sufficient increase in the borrowing base under our credit agreement to help fund our 2012 capital expenditure budget. A majority of our anticipated increase in cash flows during the year ending December 31, 2012 is expected to come from our
+exploration activities on unproved properties at December 31, 2011 in the Eagle Ford shale play assuming such exploration activities are successful. These anticipated increases in our cash flows from operations are based upon current oil and
+natural gas prices and the hedges we currently have in place. If our exploration activities result in less cash flows than anticipated, we may seek additional sources of capital, including through borrowings under our credit agreement (assuming
+availability under our borrowing base). In addition to future borrowings under our credit agreement, we may also seek to raise additional funds by selling shares of our common stock or securities convertible or exercisable into our common stock
+(including debt securities or other preferential securities) in the public markets or otherwise. It is likely that any such sales would dilute the ownership interest of our existing shareholders. It is also possible that, to the extent we are not
+able to obtain additional sources, we may modify our planned capital expenditure budget for 2012 accordingly. Exploration activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our
+reserves, cash flows from operations and borrowing base under our credit agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That
+75 
+Table of Contents 
+May Exceed Our Cash Flows From Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,”
+“Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified
+Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” 
+Our cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+(In thousands) 
+Net cash provided by operating activities 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+Net cash used in investing activities 
+(160,087 
+) 
+(147,334 
+) 
+(49,415 
+) 
+Net cash provided by financing activities 
+87,444 
+36,891 
+1,086 
+Net change in cash and cash equivalents 
+$ 
+(10,775 
+) 
+$ 
+(83,170 
+) 
+$ 
+(46,538 
+) 
+Cash Flows Provided by Operating Activities 
+Net cash provided by operating activities increased by $34.6 million to $61.9 million for the year ended December 31, 2011 as
+compared to net cash provided by operating activities of $27.3 million for the year ended December 31, 2010. Net cash provided by oil and natural gas operations increased significantly to $49.3 million for the year ended December 31, 2011
+from $25.0 million for the year ended December 31, 2010. This increase reflects primarily the 79% increase in our oil and natural gas production to 15.4 Bcfe from 8.6 Bcfe between the respective periods. A portion of the increase in net cash
+provided by operating activities also reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil price of $93.80
+per Bbl realized during 2011 as compared to an average oil price of $76.39 per Bbl realized during 2010. Some of this increase in net cash provided by operating activities is also due to changes in our operating assets and liabilities totaling
+approximately $10.3 million between December 31, 2010 and December 31, 2011. Our accounts payable and accrued liabilities increased to approximately $44.3 million at December 31, 2011 from approximately $27.0 million at
+December 31, 2010 due to our increased operating activity in south Texas. Our accounts receivable increased to $13.2 million at December 31, 2011 as compared to $11.6 million at December 31, 2010 due primarily to the increase in our
+oil and natural gas production and associated revenues. 
+Net cash provided by operating activities increased by $25.5 million
+to $27.3 million for the year ended December 31, 2010 as compared to net cash provided by operating activities of $1.8 million for the year ended December 31, 2009. The increase in cash flows provided by operations reflects an increase in
+our production to 8.6 Bcfe from 5.0 Bcfe and an increase in the average prices we received for oil and natural gas production for the year ended December 31, 2010 as compared to the year ended December 31, 2009. Our accounts payable and
+accrued liabilities were approximately $26.8 million at December 31, 2010 as a result of operated horizontal wells that we were drilling and/or completing in the Haynesville and Eagle Ford shale plays and in the Cotton Valley formation during
+the fourth quarter of 2010. Our accounts payable and accrued liabilities were $7.3 million at December 31, 2009 as we were drilling and completing only one operated horizontal Haynesville shale well at that time. 
+Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural
+gas prices between reporting periods. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil
+76 
+Table of Contents 
+and natural gas. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Quantitative
+and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May
+Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+Cash Flows Used in Investing Activities 
+Net cash used in investing
+activities increased by $12.8 million to $160.1 million for the year ended December 31, 2011 from $147.3 million for the year ended December 31, 2010. This increase in net cash used in investing activities reflected a decrease of
+$2.6 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2011 as compared to the year ended December 31, 2010, offset almost exactly by an increase of approximately $3.0 million in
+expenditures for other property and equipment, which includes new pipeline infrastructure associated with our initial wells in the Eagle Ford shale. Although our capital expenditures were relatively flat year-over-year, approximately 75% of our
+capital expenditures were allocated to drilling and completion operations and 25% to the acquisition of additional acreage for the year ended December 31, 2011, as compared to approximately 43% allocated to drilling and completion operations
+and 57% allocated to acquisition of additional acreage for the year ended December 31, 2010. Our oil and natural gas properties capital expenditures for the year ended December 31, 2011 were primarily due to expenditures associated with
+our operated and non-operated drilling and completion activities in the Eagle Ford and Haynesville shale plays and our acreage acquisition in Karnes, DeWitt, Wilson and Gonzales Counties, Texas that we believe to be prospective for the Eagle Ford
+shale. 
+Net cash used in investing activities increased by $97.9 million to $147.3 million for the year ended
+December 31, 2010 from $49.4 million for the year ended December 31, 2009. This increase in net cash used in investing activities reflects primarily an increase of $104.8 million in our oil and natural gas properties capital expenditures
+for the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increased oil and natural gas properties capital expenditures for the year ended December 31, 2010 were due to the acquisition of leasehold
+acreage in the Eagle Ford shale play and the acquisition of additional leasehold acreage in the Haynesville shale play, as well as expenditures associated with our operated and non-operated drilling and completion activities in both plays as
+compared to the year ended December 31, 2009. 
+Expenditures for the acquisition, exploration and development of oil and
+natural gas properties are the primary use of our capital resources. We anticipate investing $313.0 million in capital for acquisition, exploration and development activities in 2012 as follows: 
+Amount 
+(in millions) 
+Exploration and development drilling and associated infrastructure 
+$ 
+284.5 
+Leasehold acquisition 
+24.0 
+Other capital expenditures, 2-D and 3-D seismic data and recompletions of existing wells 
+4.5 
+Total 
+$ 
+313.0 
+For further information regarding our anticipated capital expenditure budget in 2012, see
+“Business—General.” 
+Our 2012 capital expenditures may be adjusted as business conditions warrant. The amount,
+timing and allocation of capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until
+later periods to conserve cash or to focus on those projects that we believe have the 
+77 
+Table of Contents 
+highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing,
+drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations and other factors both
+within and outside our control. 
+Cash Flows Provided by Financing Activities 
+Net cash provided by financing activities was $87.4 million for the year ended December 31, 2011, as compared to net cash provided by
+financing activities of $36.9 million for the year ended December 31, 2010. The net cash provided by financing activities for the year ended December 31, 2011 was due almost entirely to additional borrowings of $88.0 million under our
+credit agreement to fund our working capital requirements as well as our acquisition of acreage prospective for the Eagle Ford shale play in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. In January 2011, we sold 53,772 shares of our
+Class A common stock in a private placement and received net proceeds of approximately $0.6 million. During 2011, we also received proceeds from the exercise of stock options totaling approximately $0.8 million. For the year ended
+December 31, 2011, we also incurred cash expenditures related to preparation for our initial public offering of approximately $1.7 million. 
+Net cash provided by financing activities was $36.9 million for the year ended December 31, 2010 as compared to net cash provided by financing activities of $1.1 million for the year ended
+December 31, 2009. For the year ended December 31, 2010, the most significant financing activities occurred in the fourth quarter of 2010. During that time, we sold approximately 1.9 million shares of our Class A common stock in
+a private placement and received net proceeds of approximately $21.0 million, and we borrowed $25.0 million under our credit agreement. In addition, in April 2010, we repurchased 1,000,000 shares of Class A common stock from five shareholders,
+all advised by Wellington Management Company, for a total of $9.0 million. We also received proceeds of approximately $2.0 million from the periodic exercise of stock options during the year ended December 31, 2010. For the year ended
+December 31, 2009, the most significant financing activities occurred in April 2009 when we repurchased approximately 5.4 million shares of Class A common stock from Gandhara Capital, one of our largest shareholders at the time, for a
+total of $27.1 million and in May through September 2009 when we sold approximately 5.0 million shares of Class A common stock in a private placement and received net proceeds of approximately $28.0 million. We also received proceeds of
+approximately $1.3 million from the periodic exercise of stock options for the year ended December 31, 2009. 
+Credit
+Agreement 
+In December 2011, we amended and restated our senior secured revolving credit agreement for which Comerica Bank
+serves as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company is the borrower under the new amended credit agreement. Borrowings are secured by
+mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly owned subsidiaries, which are also guarantors. In addition, all obligations under the credit agreement are
+guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with one of the lenders under the credit agreement (or an affiliate thereof) are also secured by the collateral and guaranteed by the subsidiaries
+of MRC Energy Company. 
+The amount of the borrowings under our amended and restated credit agreement is limited to the lesser
+of $400.0 million or the borrowing base, which is determined semi-annually as of May 1 and November 1 
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+Table of Contents 
+by the lenders based primarily on the estimated value of our existing and future acquired oil and gas reserves, but also on external factors, such as the lenders’ lending policies and the
+lenders’ estimates of future oil and natural gas prices, over which we have no control. At December 31, 2011, the borrowing base was $125.0 million and we had $113.0 million in outstanding borrowings under the credit agreement. In January
+2012, we borrowed an additional $10.0 million to finance a portion of our working capital requirements, bringing the then total outstanding indebtedness under the credit agreement to $123.0 million. Following the completion of our initial public
+offering, we used a portion of the net proceeds to repay the $123.0 million outstanding under our credit agreement in February 2012, at which time the borrowing base was reduced to $100.0 million. On February 28, 2012, the borrowing base was
+increased to $125.0 million pursuant to a special borrowing base redetermination made at our request. This borrowing base increase was determined by our lenders based upon, among other items, the increase in our oil and natural gas reserves at
+December 31, 2011. 
+In March 2012, we borrowed $15.0 million under the credit agreement to finance a portion of our
+working capital requirements and capital expenditures. At March 30, 2012, we had $15.0 million in borrowings outstanding under the credit agreement, approximately $1.3 million in outstanding letters of credit issued pursuant to the credit
+agreement and approximately $108.7 million available for additional borrowings. At March 30, 2012, our outstanding borrowings bore interest at approximately 2.0% per annum. We expect to access future borrowings under our credit agreement to
+fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows. During 2012, we also intend to seek additional redeterminations of our borrowing base as a result of, among other items, any increases to
+our proved oil and natural gas reserves during the year. 
+Both we and the lenders may each request an unscheduled
+redetermination of the borrowing base twice at any time during the first year of the credit agreement and once between scheduled redetermination dates thereafter. As noted above, we requested one such unscheduled redetermination in February 2012. In
+the event of a borrowing base increase, we are required to pay a fee to the lenders equal to a percentage of the amount of the increase, which will be determined based on market conditions at the time of the borrowing base increase. If the borrowing
+base were to be less than the outstanding borrowings under the credit agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient
+to cover such excess or to repay the deficit in equal installments over a period of six months. 
+If we borrow funds as a base
+rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the weighted average of rates used in overnight federal funds transactions with members of the Federal Reserve System plus 1.0% or (ii) the prime rate for
+Comerica Bank then in effect or (iii) a daily adjusted LIBOR rate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding loan depending on the level of borrowings under the agreement. If we borrow funds as a Eurodollar
+loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the interest rate appearing on Page BBAM of the Bloomberg Financial Markets Information Service by (B) a percentage equal to 100%
+minus the maximum rate during such interest calculation period at which Comerica Bank is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System), plus
+(ii) an amount from 1.375% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by us. A facility fee of
+0.375% to 0.50%, depending on the amounts borrowed, is also paid quarterly in arrears. We include the facility fee in our interest rate calculations and related disclosures. 
+79 
+Table of Contents 
+Key financial covenants under the credit agreement require us to maintain (1) a minimum
+current ratio, which is defined as consolidated total current assets plus the unused availability under the credit agreement divided by consolidated total current liabilities, of 1.0 for all reporting periods beginning March 31, 2012, and
+(2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 to 1.0 or less, beginning December 31, 2011. 
+Subject to certain exceptions, our credit agreement contains various covenants that limit our, along with our subsidiaries’,
+ability to take certain actions, including, but not limited to, the following: 
+• 
+incur indebtedness or grant liens on any of our assets; 
+• 
+enter into commodity hedging agreements; 
+• 
+declare or pay dividends, distributions or redemptions; 
+• 
+merge or consolidate; 
+• 
+make any loans or investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+engage in certain asset dispositions, including a sale of all or substantially all of our assets. 
+If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the borrowings and
+exercise other rights and remedies. Events of default include, but are not limited to, the following events: 
+• 
+failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount
+within certain grace periods; 
+• 
+failure to perform or otherwise comply with the covenants and obligations in the credit agreement or other loan documents, subject, in certain
+instances, to certain grace periods; 
+• 
+bankruptcy or insolvency events involving us or our subsidiaries; and 
+• 
+a change of control, as defined in the credit agreement. 
+In December 2010, the credit agreement was amended to increase the borrowing base to $55.0 million. At December 31, 2010, we had $25.0 million of outstanding borrowings and $50,000 in letters of
+credit issued pursuant to the credit agreement. At December 31, 2010, all borrowings under the credit agreement were Eurodollar loans, and the interest rate on the outstanding borrowings was approximately 1.6% per annum. We had an additional
+$325,000 in letters of credit secured by certificates of deposit at Comerica Bank at December 31, 2010. 
+At
+December 31, 2011, the borrowing base available for revolving borrowings was $125.0 million, and we had $113.0 million in revolving borrowings outstanding under the credit agreement, approximately $1.3 million in outstanding letters of
+credit issued pursuant to the credit agreement and approximately $10.7 million available for additional borrowings. At December 31, 2011, our outstanding revolving borrowings bore interest at the rate of approximately 5.3% per annum. Prior to
+the December 2011 amendment, the outstanding revolving borrowings under our credit agreement were scheduled to mature in March 2013. 
+In addition to our revolving borrowings under our credit agreement, in May 2011, we borrowed $25.0 million in a term loan pursuant to the credit agreement to help finance the acquisition of the Eagle
+Ford shale acreage from Orca ICI Development, JV in Karnes, DeWitt, Wilson and Gonzales Counties, Texas. The term loan was due and payable on December 31, 2011, and there was no penalty for prepayment. The term loan was refinanced by borrowings
+under the amended and restated credit agreement in December 2011. 
+80 
+Table of Contents 
+We believe that we were in compliance with the terms of our credit agreement and with all
+our bank covenants at December 31, 2011. We obtained a written extension until May 1, 2012 to comply with a covenant under the credit agreement requiring the submission of certain year-end 2011 operating information for the lenders’ use on
+or before March 1, 2012. 
+Off-Balance Sheet Arrangements 
+At December 31, 2011, we did not have any off-balance sheet arrangements. 
+Obligations
+and Commitments 
+We had the following material contractual obligations and commitments at December 31, 2011:
+Payments Due by Period 
+Total 
+Less Than 
+1 Year 
+1-3 Years 
+3-5 Years 
+More Than 
+5 Years 
+(in thousands) 
+Contractual Obligations: 
+Revolving credit borrowings and term loan, including letters of credit (1) 
+$ 
+114,300 
+$ 
+26,300 
+$ 
+– 
+$ 
+88,000 
+$ 
+– 
+Office lease 
+6,243 
+287 
+1,150 
+1,193 
+3,613 
+Non-operated drilling commitments (2) 
+5,100 
+5,100 
+– 
+– 
+– 
+Drilling rig contracts (3) 
+2,667 
+2,667 
+– 
+– 
+– 
+Employee bonuses 
+1,240 
+– 
+1,240 
+– 
+– 
+Asset retirement obligations 
+4,270 
+263 
+413 
+993 
+2,601 
+Total contractual cash obligations 
+$ 
+133,820 
+$ 
+34,617 
+$ 
+2,803 
+$ 
+90,186 
+$ 
+6,214 
+(1) 
+At December 31, 2011, we had $113.0 million in revolving borrowings outstanding under our amended and restated credit agreement and approximately $1.3 million in
+outstanding letters of credit issued pursuant to the credit agreement. A total of $25.0 million of these borrowings was scheduled to mature on December 31, 2012, and the remaining borrowings were scheduled to mature in December 2016. These amounts
+do not include estimated interest on the obligations, because our revolving borrowings had short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods. 
+(2) 
+At December 31, 2011, we had outstanding commitments to participate in the drilling and completion of various non-operated wells in the Haynesville shale. Our
+working interests in these wells are small, and most of these wells were in progress at December 31, 2011. If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these
+wells of approximately $5.1 million at December 31, 2011, which we expect to incur within the next 12 months. 
+(3) 
+At December 31, 2011, we had entered into two drilling rig contracts to explore and develop our Eagle Ford acreage in south Texas. The two rigs began drilling on
+our acreage in September 2011 and October 2011, respectively. Both contracts are for a term of six months. Should we elect to terminate one or both contracts and if the drilling contractor were unable to secure work for one or both rigs or if the
+drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate
+termination obligations under these contracts were approximately $2.7 million at December 31, 2011. 
+General Outlook and
+Trends 
+For the year ended December 31, 2011, oil prices ranged from a high of approximately $114.00 per Bbl in April to a
+low of approximately $76.00 per Bbl in October, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. Generally, oil prices remained above $90.00 per Bbl for much of the year. We realized an average
+oil price of $93.80 per Bbl for our oil production for the year ended December 31, 2011 as compared to $76.39 per Bbl for the year ended December 31, 2010. At March 30, 2012, the NYMEX West Texas Intermediate oil futures contract for the earliest
+delivery date closed at $103.02 per Bbl as compared to $104.27 per Bbl at March 30, 2011. 
+For the year ended December 31,
+2011, natural gas prices ranged from a high of approximately $4.80 per MMBtu in January and June to a low of approximately $3.00 per MMBtu in December, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date.
+Natural gas prices 
+81 
+Table of Contents 
+remained relatively flat during the first six months of 2011 trading between approximately $3.80 per MMBtu and $4.80 per MMBtu. Beginning in mid-July 2011, natural gas prices began a steady
+decline of more than 50% to their lowest levels in many years. We realized a natural gas price of $3.62 per Mcf ($4.11 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2011
+as compared to $3.75 per Mcf ($4.38 per Mcf including realized gains from natural gas derivatives) for the year ended December 31, 2010. At March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at
+$2.13 per MMBtu as compared to $4.36 per MMBtu at March 30, 2011. 
+The prices we receive for oil and natural gas heavily
+influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to
+relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and these markets will likely continue to be volatile in the future. Declines in oil or natural gas prices not only reduce our
+revenue, but could also reduce the amount of oil and natural gas we can produce economically. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil and natural gas prices.
+Even so, decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil and natural gas prices, and we may not always employ the optimal hedging strategy.
+Should oil or natural gas prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, or to cease exploration or
+development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. This, in
+turn, may affect the liquidity that can be accessed through our borrowing base under our credit agreement and through the capital markets. 
+Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our wells in the Eagle Ford shale and the Haynesville shale will experience
+rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil and
+natural gas price declines, however, we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact
+our production volumes, revenues, reserves and cash flows. 
+We must focus our efforts on increasing oil and gas reserves and
+production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future
+finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. 
+Critical accounting
+policies and estimates 
+We have outlined below certain accounting policies that are of particular importance to the
+presentation of our financial condition and results of operations and require the application of significant judgment or estimates by our management. 
+The preparation of financial statements requires us to make other estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting
+period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the ultimate actual 
+82 
+Table of Contents 
+results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risk and uncertainties could cause
+the actual results to differ materially from our estimates. 
+Property and Equipment 
+We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all
+costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing
+our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive
+wells, capitalized interest on qualifying projects and general and administrative expenses directly related to exploration and development activities, but do not include any costs related to production, selling or general corporate administrative
+activities. 
+The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less
+related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value discounted
+at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties
+included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of developing these
+reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. 
+The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the
+commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are
+estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. 
+Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property
+costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes
+consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and
+unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. 
+Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless
+such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant
+workovers that increase the properties’ reserves are capitalized. 
+83 
+Table of Contents 
+Other property and equipment are stated at cost. Computer equipment, furniture, software and
+other equipment are depreciated over their useful life (five to seven years) using the straight-line method. Support equipment and facilities include the pipelines and salt water disposal systems owned by Longwood Gathering and Disposal Systems, LP
+and are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful life or the term of the lease. 
+Derivative Financial Instruments 
+From time to time, we use derivative financial instruments to hedge our exposure to commodity price risk associated with oil and natural gas prices. These instruments consist of put and call options in
+the form of costless (or zero-cost) collars. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call proceeds are used to offset the cost
+of the put option, this arrangement is initially “costless” to us. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge
+accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statement of operations. The fair value of our derivative
+financial instruments is determined using purchase and sale information available for similarly traded securities. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses
+from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in our consolidated statement of operations. 
+Revenue Recognition 
+We follow the sales method of accounting for our oil
+and natural gas revenue, whereby we recognize revenue, net of royalties, on all oil or natural gas sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the
+time the oil and natural gas are produced and sold, and we accrue for revenue earned but not yet received. 
+Stock-based
+Compensation 
+Non-qualified stock option expense is typically recognized in our consolidated statement of operations on the
+date of grant. Incentive stock options vest over four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. We account for stock based compensation in accordance with ASC 718. At December 31,
+2011, we used the fair value method to measure and recognize the liability associated with our outstanding stock options. As our shares were not publicly traded prior to February 2, 2012, we estimate the future volatility of our stock using the
+historical volatility of the common stock of a group of companies we consider to be a representative peer group. Management believes that these average historical volatility rates are currently the best available indicator of future volatility.
+We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the
+expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. 
+Assumptions are reviewed each time there is a new grant and may be impacted by actual fluctuations in our stock price, movements in
+market interest rates and options terms. The use of different assumptions produces a different fair value for the options granted or outstanding, when accounted for as a liability 
+84 
+Table of Contents 
+award, and impacts the amount of stock compensation expense recognized in our consolidated statement of operations. The fair value of restricted stock awards are recognized based upon the fair
+value of our stock on the date of the grant. 
+Prior to November 22, 2010, all of our outstanding stock options were classified
+as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, we changed our method of accounting for outstanding stock options, reclassifying all
+outstanding stock options from equity to liability instruments. This change was made as a result of purchasing shares from certain of our employees to assist them in the exercise of outstanding options of our Class A common stock. As a result, at
+December 31, 2010, we measured and recognized the fair value of the liability associated with our outstanding stock options using the intrinsic value method. 
+Income Taxes 
+We account for income taxes using the asset and liability
+approach for financial accounting and reporting. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing
+an income tax benefit in the future does not meet the more likely than not criteria for recognition. 
+We account for
+uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the
+more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. 
+We have evaluated all tax positions for which the statute of limitations remained open, and we believe that the material positions taken
+would more likely than not be sustained by examination. Therefore, at December 31, 2011, we had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, we include
+interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on our consolidated statement of operations. 
+Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue 
+Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC
+has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this report. The SEC’s revised rules define proved reserves as the quantities of oil and natural
+gas, 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 economic 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our engineers and technical staff must make many subjective
+assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated at least annually and consider recent production levels and other technical information about each well. Estimating oil and natural gas
+reserves is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and
+reliability of both the data and the associated interpretations can vary. The process also 
+85 
+Table of Contents 
+requires certain economic assumptions, including, but not limited to, oil and natural gas prices, revenues, development expenditures, operating expenses, capital expenditures and taxes. Actual
+future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally
+different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial position, results of operations and cash flows. We cannot
+predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. 
+Recent Accounting Pronouncements 
+Balance Sheet. In December 2011, the FASB issued Accounting Standards Update, or ASU, 2011-11, Balance Sheet . The requirements amend the disclosure requirements to offsetting in Accounting
+Standards Codification, or ASC, 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either
+ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting agreement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The adoption of
+ASU 2011-11 is not expected to have a material effect on our consolidated financial statements, but may require certain additional disclosures. The amendments in ASU 2011-11 are to be applied for annual reporting periods beginning on or after
+January 1, 2013 and are to be applied retrospectively for all reporting periods presented. 
+Fair Value. In
+May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS . ASU 2011-04 amends ASC 820, Fair Value Measurements , providing a consistent definition and
+measurement of fair value, as well as similar disclosure requirements between GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value
+measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. The adoption of ASU 2011-04 is not expected to have a material impact on our consolidated financial statements, but may require certain
+additional disclosures. The amendments in ASU 2011-04 are to be applied prospectively. For public entities, the amendments are effective during interim and annual periods beginning after December 15, 2011. 
+In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure
+requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2
+measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and non-recurring fair value measurements, and are effective the first interim or annual
+reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting
+periods within those years. We adopted the first portion of this guidance beginning January 1, 2010 and the remaining portions beginning January 1, 2011. The adoption of this new guidance did not have a significant impact on our financial
+position, results of operations or cash flows. 
+Oil and Natural Gas Reserves Reporting Requirements . In January 2009,
+the SEC issued The Modernization of Oil and Gas Reporting, Final Rule . In January 2010, the Financial Accounting Standards Board, or FASB, amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. The
+86 
+Table of Contents 
+changes are designed to modernize and update the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules made a number of
+important changes including the following: (i) expanded the definition of oil and natural gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coalbeds or other nonrenewable natural resources,
+(ii) amended the required price for estimating economic quantities for year-end reserves reporting to be the unweighted, arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period, rather than the
+year-end price and (iii) permitted proved reserves to be claimed beyond those development spacing areas that are immediately adjacent to developed spacing areas if it can be established with reasonable certainty that these reserves are
+economically producible. At December 31, 2009, we adopted the provisions of this new rule, and we have applied this new guidance for the reserves estimates shown for December 31, 2011, 2010 and 2009 included herein. 
+Item 7A. 
+Quantitative and Qualitative Disclosures about Market Risk. 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the
+use of derivative financial instruments. 
+Commodity price exposure. We are exposed to market risk as the prices of
+oil and natural gas fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter
+into derivative financial instruments in the future to cover a significant portion of our future production. 
+We use costless
+(or zero-cost) collars to manage risks related to changes in oil and natural gas prices. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option.
+Because the call option proceeds are used to offset the cost of the put option, this arrangement is initially “costless” to us. 
+We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded
+securities. Comerica Bank is the single counterparty for all of our derivative instruments. We have evaluated the credit standing of Comerica Bank in determining the fair value of our derivative financial instruments. 
+At December 31, 2011, 2010 and 2009, we used costless collar options to reduce the volatility of natural gas prices on a significant
+portion of our future expected natural gas production. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas
+futures contract for the delivery month corresponding to the calculation period’s calendar month for the last day of that contract period. When the settlement price is below the price floor established by these collars, we receive from Comerica
+Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by these collars, we pay to
+Comerica, as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. 
+87 
+Table of Contents 
+The following is a summary of our open natural gas costless collar contracts at
+February 29, 2012. 
+Commodity 
+Calculation Period 
+Notional Quantity 
+Price Floor 
+Price 
+Ceiling 
+Fair Value 
+of Asset 
+(MMBtu/month) 
+($/MMBtu) 
+($/MMBtu) 
+(thousands) 
+Natural Gas 
+07/01/2011 — 12/31/2012 
+300,000 
+4.50 
+5.60 
+$ 
+4,948 
+Natural Gas 
+07/01/2011 — 07/31/2013 
+150,000 
+4.50 
+5.75 
+3,584 
+Natural Gas 
+01/01/2012 — 12/31/2012 
+150,000 
+4.25 
+6.17 
+2,120 
+Total 
+$ 
+10,652 
+All of our existing natural gas derivative contracts will expire at varying times during 2012 and 2013.
+Between November 2011 and February 2012, we entered into various costless collar transactions to mitigate our exposure to oil
+price volatility for the first time. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these oil hedging transactions is the arithmetic average of the settlement prices for the NYMEX
+West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by these collars, we receive from Comerica Bank, as
+counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume hedged. When the settlement price is above the price ceiling established by these collars, we pay Comerica Bank,
+as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume hedged. 
+The following table is a summary of our open oil costless collar contracts at February 29, 2012. 
+Commodity 
+Calculation Period 
+Notional Quantity 
+Price Floor 
+Price 
+Ceiling 
+Fair Value 
+of Liability 
+(Bbls/month) 
+($/Bbl) 
+($/Bbl) 
+(thousands) 
+Oil 
+12/01/2011 — 12/31/2012 
+20,000 
+90.00 
+104.20 
+$ 
+(1,475 
+) 
+Oil 
+01/01/2012 — 12/31/2012 
+10,000 
+90.00 
+108.00 
+(526 
+) 
+Oil 
+01/01/2012 — 12/31/2012 
+10,000 
+90.00 
+109.50 
+(455 
+) 
+Oil 
+02/01/2012 — 06/30/2012 
+20,000 
+90.00 
+113.75 
+(150 
+) 
+Oil 
+04/01/2012 — 12/31/2012 
+20,000 
+90.00 
+111.00 
+(762 
+) 
+Oil 
+04/01/2012 — 03/31/2013 
+20,000 
+90.00 
+110.00 
+(1,117 
+) 
+Oil 
+07/01/2012 — 12/31/2012 
+20,000 
+90.00 
+111.90 
+(509 
+) 
+Oil 
+07/01/2012 — 12/31/2012 
+20,000 
+95.00 
+116.00 
+(165 
+) 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+85.00 
+102.25 
+(2,056 
+) 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+90.00 
+115.00 
+(330 
+) 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+85.00 
+110.40 
+(1,102 
+) 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+85.00 
+108.80 
+(1,231 
+) 
+Oil 
+01/01/2013 — 06/30/2014 
+8,000 
+90.00 
+114.00 
+(121 
+) 
+Oil 
+01/01/2013 — 06/30/2014 
+12,000 
+90.00 
+115.50 
+(71 
+) 
+Total 
+$ 
+(10,070 
+) 
+All of our existing oil derivative contracts will expire at varying times during 2012, 2013 and 2014.
+Effect of Recent Derivatives Legislation 
+On July 21, 2010, President Obama signed into law the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things,
+sets forth the new framework for regulating certain derivative products including the commodity hedges of the type used by us, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result, it is
+difficult to anticipate the overall impact of the Dodd-Frank Act on our ability 
+88 
+Table of Contents 
+or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act,
+there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits
+and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost
+of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” 
+Interest rate risk. We do not use interest rate derivatives to alter interest rate exposure in an attempt to reduce interest
+rate expense on existing debt since we borrowed under our existing credit agreement for the first time in December 2010 and had $113.0 million in revolving borrowings outstanding at December 31, 2011 under our amended and restated credit
+agreement at an interest rate of approximately 5.3% per annum. In addition to our revolving borrowings, in May 2011, we borrowed $25.0 million in a term loan pursuant to the credit agreement. The term loan was refinanced through revolving
+borrowings in December 2011 under our amended and restated credit agreement. At March 30, 2012, we had $15.0 million in revolving debt outstanding under our credit agreement at an interest rate of 2.0% per annum. If we incur additional
+indebtedness in the future and at higher interest rates, we may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. 
+Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in
+the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to
+concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial
+position, results of operations and cash flows. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. 
+While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit
+standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation
+may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record, the financial ability of the customer’s parent company to make
+payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparty on our derivative instruments currently in place is Comerica Bank and we are likely to enter into any future
+derivative instruments with Comerica Bank or one of the other lenders party to the credit agreement. 
+Impact of
+Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2011, 2010 and 2009. Although the impact of inflation has
+been generally insignificant in recent years, it is still a factor in the United States economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices
+and with increases in drilling activity in our areas of operations, including the Eagle Ford shale and Haynesville shale plays. See “Business — General.” See also “Risk Factors — The Unavailability or High Cost of Drilling
+Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, 
+89 
+Table of Contents 
+Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial
+Condition, Results of Operations and Cash Flows.” 
+Item 8. 
+Financial Statements and Supplementary Data. 
+Our financial statements appear at the end of this Form 10-K. Please see the index to the financial statements in Item 15. 
+Item 9. 
+Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. 
+Not applicable. 
+Item 9A. 
+Controls and Procedures. 
+This Annual Report does not include a report of management’s assessment regarding internal control over financial reporting or an
+attestation report of the company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies. 
+Prior to the completion of our initial public offering, we maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal
+control over financial reporting. In connection with our audit for the year ended December 31, 2011, our independent registered public accountants identified and communicated a material weakness related to accounting for stock compensation expense.
+A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial
+statements will not be prevented or detected and corrected on a timely basis. 
+We have begun the process of evaluating our
+internal control over financial reporting and expect to put into place new accounting processes and control procedures to address the weakness described above, including the hiring of outside consultants to review significant or complex accounting
+issues and calculations, the implementation of a more formalized closing process, the formation of a disclosure committee and the hiring of additional personnel. We cannot predict the outcome of this process at this time. We will be required to make
+our first assessment of our internal control over financial reporting at December 31, 2012. 
+We became a public company
+on February 1, 2012 in connection with the completion of our initial public offering. Prior to that date, we were a private company and were not required to file or submit reports under the Securities Exchange Act of 1934, as amended (the
+“Exchange Act”) and maintained disclosure controls and procedures in accordance with being a private company. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our
+disclosure controls and procedures (as defined in Rule 13a-15(e)) under the Exchange Act was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon
+this evaluation, as of the end of the period covered by this report, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective because we were not yet a public company and,
+therefore, had not yet established formal disclosure controls and procedures and because the material weakness described above relating to our internal control over financial reporting was identified. 
+Item 9B. 
+Other Information. 
+None.
+90 
+Table of Contents 
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance. 
+The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report. 
+Item 11. 
+Executive Compensation. 
+The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be
+filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption
+“Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by reference to our
+definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence. 
+The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. 
+Item 14. 
+Principal Accounting Fees and Services. 
+The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report. 
+91 
+Table of Contents 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules. 
+The following documents are filed as part of this report: 
+1. Index to
+Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2011 and 2010, Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and
+2009, Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2011, 2010 and 2009 and Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009. 
+2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this report.
+92 
+Table of Contents 
+EXHIBIT INDEX 
+Exhibit 
+Number 
+Description 
+1.1 
+Underwriting Agreement (incorporated by reference to Exhibit 1.1 to the Current Report on 
+Form 8-K filed on February 7, 2012). 
+2.1 
+Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador
+Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011). 
+3.1 
+Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.1
+to our Registration Statement on Form S-1 filed on 
+August 12, 2011). 
+3.2 
+Certificate of Amendment to Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.2 to our
+Registration Statement on Form S-1 filed on August 12, 2011). 
+3.3 
+Certificate of Amendment to Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.3 to our
+Registration Statement on Form S-1 filed on August 12, 2011). 
+3.4 
+Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration
+Statement on Form S-1 filed on August 12, 2011). 
+3.5 
+Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.5 to our Registration Statement on Form S-1 filed on August 12,
+2011). 
+3.6 
+Amendment to the Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.6 to our Registration Statement on Form S-1
+filed on August 12, 2011). 
+3.7 
+Amended and Restated Certificate of Formation of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.1 to the Current Report
+on Form 8-K filed on February 13, 2012). 
+3.8 
+Amended and Restated Bylaws of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed
+on February 13, 2012). 
+4.1 
+Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012). 
+10.1 
+Amended and Restated Credit Agreement, dated at May 19, 2011, by and among Matador Resources Company (now known as MRC Energy Company), Comerica Bank and the Lenders signatory
+thereto (incorporated by reference to Exhibit 10.1 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.2 
+Pledge and Security Agreement, by and between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Comerica Bank, dated at August 9, 2011 (incorporated by
+reference to Exhibit 10.2 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.3† 
+Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to
+our Registration Statement on Form S-1 filed on November 14, 2011). 
+Table of Contents 
+10.4† 
+Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1
+to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.5† 
+Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to
+our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.6† 
+Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1
+to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.7† 
+Independent Contractor Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and David F. Nicklin (incorporated by reference to Exhibit 10.7 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.8† 
+First Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Joseph Wm. Foran (incorporated by reference to Exhibit
+10.8 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.9† 
+First Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and David E. Lancaster (incorporated by reference to Exhibit
+10.9 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.10† 
+First Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Matthew Hairford (incorporated by reference to Exhibit
+10.10 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.11† 
+First Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Bradley M. Robinson (incorporated by reference to Exhibit
+10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.12† 
+Second Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Joseph Wm. Foran (incorporated by reference to Exhibit
+10.12 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.13† 
+Second Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and David E. Lancaster (incorporated by reference to Exhibit
+10.13 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.14† 
+Second Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Matthew Hairford (incorporated by reference to Exhibit
+10.14 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.15† 
+Second Amendment to the Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Bradley M. Robinson (incorporated by reference to Exhibit
+10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.16† 
+First Amendment to the Independent Contractor Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and David F. Nicklin (incorporated by reference to
+Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.17† 
+2012 Long-Term Incentive Plan of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our
+Registration Statement on Form S-1 filed on December 30, 2011). 
+10.18† 
+Matador Resources Company (formerly known as Matador Holdco, Inc.) Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.18 to Amendment
+No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+Table of Contents 
+10.19† 
+Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to
+our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.20† 
+First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.21† 
+Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 incorporated by reference to Exhibit 10.17 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.22† 
+Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18
+to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.23† 
+Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.24† 
+Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.25† 
+Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.26† 
+Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26
+to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.27† 
+Form of Indemnification Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and each of the directors and executive officers thereof (incorporated
+by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.28 
+Participation Agreement, by and among MRC Rockies Company, Matador Resources Company (now known as MRC Energy Company), Matador Production Company, Roxanna Rocky Mountains, LLC,
+Roxanna Oil, Inc., Alliance Capital Real Estate, Inc. and AllianceBernstein L.P., dated at May 14, 2010 (incorporated by reference to Exhibit 10.23 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14,
+2011). 
+10.29 
+Assignment, Bill of Sale and Conveyance, by and among Winn Exploration Co., Inc., Pinion Exploration, LLP, McDay Oil & Gas, Inc. and Matador Resources Company (now known as MRC
+Energy Company), dated effective at December 1, 2010 (incorporated by reference to Exhibit 10.24 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.30 
+Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011
+(incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.31 
+Second Amended and Restated Credit Agreement dated as of December 30, 2011, by and among MRC Energy Company, Comerica Bank and the Lenders party thereto from time to time
+(incorporated by reference to Exhibit 10.31 to Amendment No. 3 to our Registration Statement on Form S-1 filed on January 13, 2012). 
+Table of Contents 
+10.32 
+Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Comerica Bank, dated as of December 30,
+2011 (incorporated by reference to Exhibit 10.32 to Amendment No. 3 to our Registration Statement on Form S-1 filed on January 13, 2012). 
+10.33 
+Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems
+GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company (formerly known as Matador Holdco, Inc.) and Comerica Bank, dated at December 30, 2011 (incorporated by reference to Exhibit 10.33 to Amendment No. 3 to our
+Registration Statement on Form S-1 filed on January 13, 2012). 
+10.34† 
+Employment Agreement between Matador Resources Company (formerly known as Matador Holdco, Inc.) and Wade Massad (incorporated by reference to Exhibit 10.34 to Amendment No. 3 to our
+Registration Statement on Form S-1 filed on January 13, 2012). 
+10.35† 
+Nonqualified Stock Option Agreement, dated February 1, 2012, by and between Matador Resources Company and Wade Massad (incorporated by reference to Exhibit 10.1 to the Current
+Report on Form 8-K filed on February 7, 2012). 
+10.36† 
+Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (filed
+herewith). 
+10.37† 
+Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (filed
+herewith). 
+10.38† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company (formerly known as Matador Holdco, Inc.) 2012 Long-Term Incentive Plan (filed
+herewith). 
+10.39† 
+Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company (formerly known as Matador Holdco, Inc.) 2012 Long-Term Incentive Plan (filed
+herewith). 
+10.40† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company (formerly known as Matador Holdco, Inc.) 2012 Long-Term Incentive Plan (filed
+herewith). 
+21.1 
+List of Subsidiaries of Matador Resources Company (formerly known as Matador Holdco, Inc.) (incorporated by reference to Exhibit 21.1 to our Registration Statement on Form S-1 filed
+on August 12, 2011). 
+23.1 
+Consent of Netherland, Sewell & Associates, Inc. (filed herewith). 
+31.1 
+Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+31.2 
+Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+32.1 
+Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed
+herewith). 
+32.2 
+Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed
+herewith). 
+99.1 
+Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). 
+† 
+Indicates a management contract or compensatory plan or arrangement. 
+Table of Contents 
+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. 
+MATADOR RESOURCES COMPANY 
+April 2, 2012 
+By: 
+/s/ Joseph Wm. Foran 
+Joseph Wm. Foran 
+Chairman, President and Chief Executive Officer 
+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/ Joseph Wm.
+Foran 
+Joseph Wm. Foran 
+Chairman, President and Chief 
+Executive Officer (Principal 
+Executive
+Officer) 
+April 2, 2012 
+/s/ David E.
+Lancaster 
+David E. Lancaster 
+Executive Vice President, Chief 
+Operating Officer and Chief 
+Financial
+Officer 
+(Principal Financial Officer) 
+April 2, 2012 
+/s/ Kathryn L.
+Wayne 
+Kathryn L. Wayne 
+Controller and Treasurer 
+(Principal Accounting Officer) 
+April 2, 2012 
+/s/ Charles L.
+Gummer 
+Charles L. Gummer 
+Director 
+April 2, 2012 
+/s/ Stephen A.
+Holditch 
+Stephen A. Holditch 
+Director 
+April 2, 2012 
+/s/ David M.
+Laney 
+David M. Laney 
+Director 
+April 2, 2012 
+/s/ Gregory E.
+Mitchell 
+Gregory E. Mitchell 
+Director 
+April 2, 2012 
+/s/ Steven W.
+Ohnimus 
+Steven W. Ohnimus 
+Director 
+April 2, 2012 
+/s/ Michael C.
+Ryan 
+Michael C. Ryan 
+Director 
+April 2, 2012 
+/s/ Margaret B.
+Shannon 
+Margaret B. Shannon 
+Director 
+April 2, 2012 
+Table of Contents 
+GLOSSARY OF OIL AND NATURAL GAS TERMS 
+The following is a description of the meanings of some of the oil and natural gas industry terms used in this report. 
+Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid
+hydrocarbons. 
+Bcf . One billion cubic feet. 
+Bcfe . One billion cubic feet of natural gas equivalents, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. 
+BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids, to six Mcf
+of natural gas. 
+Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of
+water by one degree Fahrenheit. 
+Completion . The operations required to establish production of oil or natural gas from
+a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reserve. 
+Conventional resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and
+fluid characteristics permit the natural gas or oil to readily flow to the wellbore. 
+Coring . The act of taking a core.
+A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the
+drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. 
+Developed acreage . The number of acres that are allocated or assignable to productive wells. 
+Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be
+productive. 
+Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that
+proceeds from the sale of such production exceed production-related expenses and taxes. 
+Exploratory well . A well
+drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. 
+Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working
+interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a
+royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” 
+Table of Contents 
+FERC . Federal Energy Regulatory Commission. 
+Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological
+structural feature and/or stratigraphic condition. 
+Fracture stimulation technology . The technique of improving a
+well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the
+channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as hydraulic fracturing. 
+Gross acres or gross wells . The total acres or wells in which a working interest is owned. 
+Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term
+of the lease in accordance with its terms as a result of production from the property. 
+Horizontal drilling or well . A
+drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well
+drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. 
+Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane and pentane resulting
+from the further processing of liquefiable hydrocarbons separated from raw natural gas by a gas processing facility. 
+MBbl . One thousand barrels of crude oil or other liquid hydrocarbons. 
+Mcf . One thousand cubic feet of natural gas. 
+Mcfe . One thousand cubic feet of natural gas equivalents, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. 
+MMBtu . One million British thermal units. 
+MMcf . One million cubic feet of natural gas. 
+MMcf/d . MMcf per day.
+MMcfe . One million cubic feet of natural gas equivalents, determined using the ratio of six Mcf of natural gas to one
+Bbl of crude oil, condensate or natural gas liquids. 
+MMcfe/day . MMcfe per day. 
+Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. 
+Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil,
+gas and/or natural gas liquids that are produced from the well. 
+NYMEX . New York Mercantile Exchange. 
+Table of Contents 
+Overriding royalty interest . A fractional interest in the gross production of oil and
+natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced
+from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. 
+Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. 
+Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are
+retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. 
+Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping
+mechanism and hydrocarbon type. 
+Possible reserves . Additional reserves that are less certain to be recognized than
+probable reserves. 
+Probable reserves . Additional reserves that are less certain to be recognized than proved reserves
+but which, in sum with proved reserves, are as likely as not to be recovered. 
+Producing well, production well or
+productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. 
+Properties . Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee,
+leasehold and related interests. 
+Prospect . A specific geographic area which, based on supporting geological,
+geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. 
+Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which
+has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved but non-producing reserves.
+Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities
+and by existing operating methods. 
+Proved reserves . Reserves of oil and natural gas that have been proved to a high
+degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. 
+Proved undeveloped reserves . 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. 
+Recompletion . Completing in the same wellbore to reach a new reservoir after production from the
+original reservoir has been abandoned. 
+Table of Contents 
+Repeatability . The potential ability to drill multiple wells within a prospect or
+trend. 
+Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil
+and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Royalty interest . An interest in an oil and natural gas 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.
+2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation
+of reflecting seismic data collected along a single source profile. 
+3-D seismic . The method by which a
+three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic
+surveys and contribute significantly to field appraisal, exploitation and production. 
+Spud. The act of beginning to
+drill an oil or natural gas well. 
+Trend . A region of oil and/or natural gas production, the geographic limits of which
+have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of
+formations. 
+Unconventional resource play . A set of known or postulated oil and or gas resources or reserves warranting
+further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. 
+Undeveloped acreage . Lease 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. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. 
+Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such property
+to be classified as proved. 
+Vertical well . A hole drilled vertically into the earth from which oil, natural gas or
+water flows or is pumped. 
+Visualization . An exploration technique in which the size and shape of subsurface features
+are mapped and analyzed based upon information derived from well logs, seismic data and other well information. 
+Volumetric
+reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for the rock porosity, hydrocarbon saturation, formation volume factor
+and recovery factor. 
+Wellbore . The hole made by a well. 
+Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the
+property and receive a share of production. 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED FINANCIAL STATEMENTS 
+December 31, 2011, 2010 and 2009 
+Contents
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Audited Consolidated Financial Statements 
+Consolidated Balance Sheets as of December 31, 2011 and 2010 
+F-3 
+Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and
+2009 
+F-4 
+Consolidated Statements of Shareholders’ Equity for the years ended December 
+31, 2011, 2010 and 2009 
+F-5 
+Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and
+2009 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 
+F-1
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+Board of Directors and Shareholders 
+Matador Resources Company 
+We have audited the accompanying consolidated balance sheets of
+Matador Resources Company (a Texas corporation) and subsidiaries (collectively, the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity, 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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over
+financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
+effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes 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, 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 Matador
+Resources Company 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 2 to the financial statements, the Company adopted new oil and gas reserves
+estimation and disclosure requirements as of December 31, 2009. In addition, as discussed in Note 8, the Company changed its method of valuation of stock options for recording stock option expense in 2011. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas
+April 2, 2012 
+F-2
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED BALANCE SHEETS 
+December 31, 
+2011 
+2010 
+ASSETS 
+Current assets 
+Cash and cash equivalents 
+$ 
+10,284,180 
+$ 
+21,059,519 
+Certificates of deposit 
+1,335,000 
+2,349,313 
+Accounts receivable 
+Oil and natural gas revenues 
+9,237,322 
+6,514,122 
+Joint interest billings 
+2,488,070 
+2,042,999 
+Other 
+1,446,113 
+3,091,372 
+Derivative instruments 
+8,988,767 
+4,144,411 
+Lease and well equipment inventory 
+1,343,416 
+1,423,197 
+Prepaid expenses 
+1,153,214 
+1,802,807 
+Total current assets 
+36,276,082 
+42,427,740 
+Property and equipment, at cost 
+Oil and natural gas properties, full-cost method 
+Evaluated 
+423,944,476 
+255,408,993 
+Unproved and unevaluated 
+162,597,985 
+172,451,449 
+Other property and equipment 
+18,764,038 
+14,035,010 
+Less accumulated depletion, depreciation and amortization 
+(205,441,724 
+) 
+(138,014,986 
+) 
+Net property and equipment 
+399,864,775 
+303,880,466 
+Other assets 
+Derivative instruments 
+847,267 
+– 
+Deferred income taxes 
+1,593,331 
+– 
+Other assets 
+887,061 
+73,551 
+Total other assets 
+3,327,659 
+73,551 
+Total assets 
+$ 
+439,468,516 
+$ 
+346,381,757 
+LIABILITIES AND SHAREHOLDERS’ EQUITY 
+Current liabilities 
+Accounts payable 
+$ 
+18,841,295 
+$ 
+12,166,938 
+Accrued liabilities 
+25,438,893 
+14,789,712 
+Royalties payable 
+1,855,296 
+982,270 
+Borrowings under Credit Agreement 
+25,000,000 
+– 
+Derivative instruments 
+171,252 
+– 
+Advances from joint interest owners 
+– 
+722,843 
+Deferred income taxes 
+3,023,760 
+1,473,619 
+Dividends payable — Class B 
+68,713 
+68,713 
+Other current liabilities 
+176,868 
+23,577 
+Total current liabilities 
+74,576,077 
+30,227,672 
+Long-term liabilities 
+Borrowings under Credit Agreement 
+88,000,000 
+25,000,000 
+Asset retirement obligations 
+3,935,084 
+3,563,851 
+Derivative instruments 
+382,848 
+– 
+Deferred income taxes 
+– 
+5,432,638 
+Other long-term liabilities 
+1,059,314 
+280,453 
+Total long-term liabilities 
+93,377,246 
+34,276,942 
+Commitments and contingencies (Note 12) 
+Shareholders’ equity 
+Common stock — Class A, $0.01 par value, 80,000,000 shares authorized; 42,916,668 and 42,749,820 shares issued; and
+41,737,493 and 41,570,645 shares outstanding, respectively 
+429,166 
+427,498 
+Common stock — Class B, $0.01 par value, 2,000,000 shares authorized; 1,030,700 shares issued and
+outstanding 
+10,307 
+10,307 
+Additional paid-in capital 
+263,561,890 
+263,341,642 
+Retained earnings 
+18,278,652 
+28,862,518 
+Treasury stock, at cost, 1,179,175 shares 
+(10,764,822 
+) 
+(10,764,822 
+) 
+Total shareholders’ equity 
+271,515,193 
+281,877,143 
+Total liabilities and shareholders’ equity 
+$ 
+439,468,516 
+$ 
+346,381,757 
+The accompanying notes are an integral part of these financial statements. 
+F-3
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+For the years ended December 31, 
+2011 
+2010 
+2009 
+Revenues 
+Oil and natural gas revenues 
+$ 
+66,999,826 
+$ 
+34,041,607 
+$ 
+19,038,514 
+Realized gain on derivatives 
+7,106,260 
+5,299,380 
+7,625,120 
+Unrealized gain (loss) on derivatives 
+5,137,522 
+3,138,726 
+(2,374,638 
+) 
+Total revenues 
+79,243,608 
+42,479,713 
+24,288,996 
+Expenses 
+Production taxes and marketing 
+6,277,860 
+1,981,550 
+1,077,145 
+Lease operating 
+7,244,339 
+5,284,362 
+4,725,022 
+Depletion, depreciation and amortization 
+31,753,640 
+15,596,470 
+10,742,873 
+Accretion of asset retirement obligations 
+208,547 
+154,756 
+137,347 
+Full-cost ceiling impairment 
+35,673,098 
+– 
+25,243,738 
+General and administrative 
+13,394,390 
+9,701,850 
+7,115,118 
+Total expenses 
+94,551,874 
+32,718,988 
+49,041,243 
+Operating (loss) income 
+(15,308,266 
+) 
+9,760,725 
+(24,752,247 
+) 
+Other (expense) income 
+Net loss on asset sales and inventory impairment 
+(153,533 
+) 
+(223,690 
+) 
+(379,316 
+) 
+Interest expense 
+(682,754 
+) 
+(3,235 
+) 
+– 
+Interest and other income 
+314,136 
+364,338 
+781,072 
+Total other (expense) income 
+(522,151 
+) 
+137,413 
+401,756 
+(Loss) income before income taxes 
+(15,830,417 
+) 
+9,898,138 
+(24,350,491 
+) 
+Income tax (benefit) provision 
+Current 
+(45,576 
+) 
+(1,410,608 
+) 
+(2,324,338 
+) 
+Deferred 
+(5,475,828 
+) 
+4,931,783 
+(7,600,811 
+) 
+Total income tax (benefit) provision 
+(5,521,404 
+) 
+3,521,175 
+(9,925,149 
+) 
+Net (loss) income 
+$ 
+(10,309,013 
+) 
+$ 
+6,376,963 
+$ 
+(14,425,342 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Class B 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+Diluted 
+Class A 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Class B 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+Weighted average common shares outstanding 
+Basic 
+Class A 
+41,686,807 
+40,006,787 
+39,092,567 
+Class B 
+1,030,700 
+1,030,700 
+1,030,700 
+Total 
+42,717,507 
+41,037,487 
+40,123,267 
+Diluted 
+Class A 
+41,686,807 
+40,102,927 
+39,092,567 
+Class B 
+1,030,700 
+1,030,700 
+1,030,700 
+Total 
+42,717,507 
+41,133,627 
+40,123,267 
+The accompanying notes are an integral part of these financial statements. 
+F-4
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY 
+For the years ended December 31, 2011, 2010 and 2009 
+Common stock 
+Additional 
+paid-in 
+capital 
+Retained 
+earnings 
+(deficit) 
+Total 
+Class A 
+Class B 
+Treasury stock 
+Shares 
+Amount 
+Shares 
+Amount 
+Shares 
+Amount 
+Balance at January 1, 2009 
+40,548,037 
+$ 
+405,480 
+1,030,700 
+$ 
+10,307 
+$ 
+238,413,969 
+$ 
+38,526,701 
+(39,873 
+) 
+$ 
+(351,545 
+) 
+$ 
+277,004,912 
+Issuance of Class A common stock 
+4,974,194 
+49,742 
+– 
+– 
+28,201,626 
+– 
+– 
+– 
+28,251,368 
+Cost to issue equity 
+– 
+– 
+– 
+– 
+(92,549 
+) 
+– 
+– 
+– 
+(92,549 
+) 
+Repurchase and retirement of Class A common stock 
+(5,422,713 
+) 
+(54,227 
+) 
+– 
+– 
+(26,686,133 
+) 
+(373,205 
+) 
+– 
+– 
+(27,113,565 
+) 
+Stock options granted 
+– 
+– 
+– 
+– 
+592,962 
+– 
+– 
+– 
+592,962 
+Stock options exercised 
+343,500 
+3,435 
+– 
+– 
+1,278,065 
+– 
+– 
+– 
+1,281,500 
+Restricted stock vested 
+– 
+– 
+– 
+– 
+33,750 
+– 
+– 
+– 
+33,750 
+Class B dividends declared 
+– 
+– 
+– 
+– 
+– 
+(274,853 
+) 
+– 
+– 
+(274,853 
+) 
+Current period net loss 
+– 
+– 
+– 
+– 
+– 
+(14,425,342 
+) 
+– 
+– 
+(14,425,342 
+) 
+Issuance of treasury stock 
+– 
+– 
+– 
+– 
+(78,178 
+) 
+(692,893 
+) 
+652,126 
+4,787,678 
+4,016,607 
+Purchase of treasury stock 
+– 
+– 
+– 
+– 
+– 
+– 
+(679,923 
+) 
+(4,953,400 
+) 
+(4,953,400 
+) 
+Balance at December 31, 2009 
+40,443,018 
+404,430 
+1,030,700 
+10,307 
+241,663,512 
+22,760,408 
+(67,670 
+) 
+(517,267 
+) 
+264,321,390 
+Issuance of Class A common stock 
+1,879,427 
+18,794 
+– 
+– 
+20,632,903 
+– 
+– 
+– 
+20,651,697 
+Cost to issue equity 
+– 
+– 
+– 
+– 
+(531,152 
+) 
+– 
+– 
+– 
+(531,152 
+) 
+Issuance of Class A common stock to Board members and advisors 
+20,000 
+200 
+– 
+– 
+197,800 
+– 
+– 
+– 
+198,000 
+Stock options granted 
+– 
+– 
+– 
+– 
+414,610 
+– 
+– 
+– 
+414,610 
+Stock options exercised 
+392,375 
+3,924 
+– 
+– 
+1,974,451 
+– 
+– 
+– 
+1,978,375 
+Stock options modified 
+– 
+– 
+– 
+– 
+(1,086,271 
+) 
+– 
+– 
+– 
+(1,086,271 
+) 
+Restricted stock issued 
+15,000 
+150 
+– 
+– 
+(150 
+) 
+– 
+– 
+– 
+– 
+Restricted stock vested 
+– 
+– 
+– 
+– 
+73,689 
+– 
+– 
+– 
+73,689 
+Class B dividends declared 
+– 
+– 
+– 
+– 
+– 
+(274,853 
+) 
+– 
+– 
+(274,853 
+) 
+Current period net income 
+– 
+– 
+– 
+– 
+– 
+6,376,963 
+– 
+– 
+6,376,963 
+Issuance of treasury stock 
+– 
+– 
+– 
+– 
+2,250 
+– 
+6,000 
+45,000 
+47,250 
+Purchase of treasury stock 
+– 
+– 
+– 
+– 
+– 
+– 
+(1,117,505 
+) 
+(10,292,555 
+) 
+(10,292,555 
+) 
+Balance at December 31, 2010 
+42,749,820 
+427,498 
+1,030,700 
+10,307 
+263,341,642 
+28,862,518 
+(1,179,175 
+) 
+(10,764,822 
+) 
+281,877,143 
+Issuance of Class A common stock 
+53,772 
+538 
+– 
+– 
+590,954 
+– 
+– 
+– 
+591,492 
+Cost to issue equity 
+– 
+– 
+– 
+– 
+(1,667,013 
+) 
+– 
+– 
+– 
+(1,667,013 
+) 
+Issuance of Class A common stock to Board members and advisors 
+20,075 
+201 
+– 
+– 
+230,199 
+– 
+– 
+– 
+230,400 
+Stock options exercised 
+93,001 
+929 
+– 
+– 
+1,022,082 
+– 
+– 
+– 
+1,023,011 
+Restricted stock vested 
+– 
+– 
+– 
+– 
+44,026 
+– 
+– 
+– 
+44,026 
+Class B dividends declared 
+– 
+– 
+– 
+– 
+– 
+(274,853 
+) 
+– 
+– 
+(274,853 
+) 
+Current period net loss 
+– 
+– 
+– 
+– 
+– 
+(10,309,013 
+) 
+– 
+– 
+(10,309,013 
+) 
+Balance at December 31, 2011 
+42,916,668 
+$ 
+429,166 
+1,030,700 
+$ 
+10,307 
+$ 
+263,561,890 
+$ 
+18,278,652 
+(1,179,175 
+) 
+$ 
+(10,764,822 
+) 
+$ 
+271,515,193 
+The accompanying notes are an integral part of these financial statements. 
+F-5
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+For the years ended December 31, 
+2011 
+2010 
+2009 
+Operating activities 
+Net (loss) income 
+$ 
+(10,309,013 
+) 
+$ 
+6,376,963 
+$ 
+(14,425,342 
+) 
+Adjustments to reconcile net (loss) income to net cash provided by operating activities 
+Unrealized (gain) loss on derivatives 
+(5,137,522 
+) 
+(3,138,726 
+) 
+2,374,638 
+Depletion, depreciation and amortization 
+31,753,640 
+15,596,470 
+10,742,873 
+Accretion of asset retirement obligations 
+208,547 
+154,756 
+137,347 
+Full-cost ceiling impairment 
+35,673,098 
+– 
+25,243,738 
+Stock option and grant expense 
+2,361,799 
+824,048 
+622,337 
+Restricted stock grants 
+44,026 
+73,689 
+33,750 
+Deferred income tax (benefit) provision 
+(5,475,828 
+) 
+4,931,783 
+(7,600,811 
+) 
+Loss on asset sales and inventory impairment 
+153,533 
+223,690 
+379,316 
+Changes in operating assets and liabilities 
+Accounts receivable 
+(1,523,011 
+) 
+(385,671 
+) 
+408,710 
+Lease and well equipment inventory 
+22,412 
+(8,078 
+) 
+(799,844 
+) 
+Prepaid expenses 
+649,593 
+(579,964 
+) 
+(186,371 
+) 
+Other assets 
+(813,510 
+) 
+33,165 
+33,165 
+Accounts payable, accrued liabilities and other current liabilities 
+13,497,251 
+2,487,643 
+(15,463,066 
+) 
+Royalties payable 
+873,026 
+309,005 
+35,763 
+Advances from joint interest owners 
+(722,843 
+) 
+272,843 
+450,000 
+State income tax payable 
+– 
+– 
+(48,000 
+) 
+Other long-term liabilities 
+613,108 
+101,423 
+(147,155 
+) 
+Net cash provided by operating activities 
+61,868,306 
+27,273,039 
+1,791,048 
+Investing activities 
+Proceeds from sale of oil and natural gas properties 
+– 
+– 
+28,732 
+Oil and natural gas properties capital expenditures 
+(156,431,123 
+) 
+(159,050,066 
+) 
+(54,243,838 
+) 
+Expenditures for other property and equipment 
+(4,670,981 
+) 
+(1,609,882 
+) 
+(306,642 
+) 
+Purchases of certificates of deposit 
+(4,298,000 
+) 
+(3,739,000 
+) 
+(15,500,424 
+) 
+Sales of certificates of deposit 
+5,312,313 
+17,065,033 
+20,607,012 
+Net cash used in investing activities 
+(160,087,791 
+) 
+(147,333,915 
+) 
+(49,415,160 
+) 
+Financing activities 
+Repayments of borrowings under Credit Agreement 
+(103,000,000 
+) 
+– 
+– 
+Borrowings under Credit Agreement 
+191,000,000 
+25,000,000 
+– 
+Proceeds from issuance of common stock 
+591,492 
+20,651,697 
+28,251,368 
+Cost to issue equity 
+(1,709,502 
+) 
+(171,978 
+) 
+(92,549 
+) 
+Proceeds from stock options exercised 
+837,009 
+1,978,375 
+1,281,500 
+Payment of dividends — Class B 
+(274,853 
+) 
+(274,853 
+) 
+(274,853 
+) 
+Repurchase and retirement of Class A common stock 
+– 
+– 
+(27,113,565 
+) 
+Issuance of treasury stock 
+– 
+– 
+3,987,231 
+Purchase of treasury stock 
+– 
+(10,292,555 
+) 
+(4,953,400 
+) 
+Net cash provided by financing activities 
+87,444,146 
+36,890,686 
+1,085,732 
+Decrease in cash and cash equivalents 
+(10,775,339 
+) 
+(83,170,190 
+) 
+(46,538,380 
+) 
+Cash and cash equivalents at beginning of year 
+21,059,519 
+104,229,709 
+150,768,089 
+Cash and cash equivalents at end of year 
+$ 
+10,284,180 
+$ 
+21,059,519 
+$ 
+104,229,709 
+Supplemental disclosures of cash flow information (Note 14) 
+The accompanying notes are an integral part of these financial statements. 
+F-6
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+December 31, 2011, 2010 and 2009 
+NOTE 1 — NATURE OF OPERATIONS 
+Matador Resources Company (“Matador” or the “Company”) is an independent energy company engaged in the exploration,
+development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Matador’s current operations are located
+primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. In addition to these primary operating areas, Matador has acreage positions in southeast New Mexico and west Texas and in
+southwest Wyoming and adjacent areas in Utah and Idaho where the Company continues to identify new oil and natural gas prospects. 
+On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of
+a corporate reorganization that was completed on August 9, 2011, the former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its
+corporate name to Matador Resources Company. 
+MRC Energy Company holds the primary assets of the Company and has four wholly
+owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts
+oil and natural gas exploration and development activities in southeast New Mexico. MRC Rockies Company conducts oil and natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and
+Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal Systems, LP which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations
+and also transports limited quantities of third-party natural gas. 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
+Basis of Presentation 
+The consolidated financial statements include the accounts of Matador Resources Company and its wholly owned subsidiary, MRC Energy Company, as well as the accounts of MRC Energy Company’s four
+wholly owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems, GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts of Longwood Gathering and Disposal Systems, LP. These consolidated financial
+statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The Company’s operations are conducted in the one segment generally referred to as the oil and
+natural gas exploration and production industry. All significant intercompany balances and transactions have been eliminated in consolidation. 
+Reclassifications 
+Certain reclassifications have been made to the
+prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. 
+F-7
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the
+amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and
+expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
+The Company’s consolidated financial statements are based on a number of significant estimates, including oil and
+natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and
+future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves
+estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by
+the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of thirty (30) days or less as cash equivalents, and cash equivalents are recorded at market. Except for small cash
+balances held in the Company’s operating accounts to conduct its ongoing business, the remainder of the Company’s cash equivalents as of December 31, 2010 was held in money market accounts composed of United States Treasury securities
+offering daily liquidity. The Company had no cash equivalents as of December 31, 2011. 
+Certificates of Deposit
+Certificates of deposit (“CD’s”) are highly liquid, short-term investments with an original maturity of
+more than 30 days but not more than one year. Each CD is recorded at market and is fully insured by the Federal Deposit Insurance Corporation. 
+Accounts Receivable 
+The Company sells its operated oil and natural
+gas production to various purchasers (see Note 13). Due to the nature of the markets for oil and natural gas, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may
+participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil and natural gas or participants in oil and
+natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 
+F-8
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+to 45 days of the production or billing date and are stated at amounts due from purchasers and industry partners. 
+The Company reviews its need for an allowance for doubtful accounts on a periodic basis, and determines the allowance, if any, by considering the length of time past due, previous loss history, future net
+revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its
+accounts receivable for any reporting period presented. 
+The Company wrote off receivables of $24,229 in 2011; there were no
+receivables written off in 2010 or 2009. When necessary, the Company accounts for a write off by recording the loss as a reduction of accounts receivable once the specific account has been determined to be uncollectible. 
+Lease and Well Equipment Inventory 
+Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future well operations or equipment held for sale. 
+Property and Equipment 
+The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and
+development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken
+exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on
+qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The
+Company capitalized $2,020,486, $1,604,682 and $1,642,868 of its general and administrative costs in 2011, 2010 and 2009, respectively. The Company capitalized $1,278,383 of its interest expense for the year ended December 31, 2011. The Company
+recorded only $3,235 in interest expense for the year ended December 31, 2010 and had no outstanding borrowings in 2009. As a result, the Company capitalized no interest expense for the years ended December 31, 2010 and 2009. 
+The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income
+taxes or the cost ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. Beginning January 1, 2011, the need for a full-cost ceiling impairment is assessed on a quarterly basis. The cost
+center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the
+lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved
+undeveloped reserves are reduced by the estimated costs for developing these reserves. The fair value of the 
+F-9
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. 
+The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the
+commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are
+estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. In January 2009, the SEC issued The Modernization of Oil and Gas Reporting,
+Final Rule and in January 2010, the Financial Accounting Standards Board (“FASB”) amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. As a result, beginning December 31, 2009, the commodity
+prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period January through December 31, 2011, these
+average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu (million British thermal units), respectively. For the period January through December 2010, these average oil and natural gas prices were $75.96 per barrel and $4.376
+per MMBtu, respectively. For the period January through December 2009, these average oil and natural gas prices were $57.65 per barrel and $3.866 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved
+oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content,
+transportation fees and regional price differentials. 
+During the first quarter ended March 31, 2011, the Company’s
+net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $22,989,866. The Company recorded an impairment charge of $35,673,098 to its net capitalized costs and a deferred income tax credit of $12,683,232 related to
+the full-cost ceiling limitation. These charges are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2011. Using the average commodity prices, as adjusted, to determine the Company’s
+estimated proved oil and natural gas reserves at December 31, 2011, the Company’s net capitalized costs did not exceed the cost center ceiling. Changes in oil and natural gas production rates, reserves estimates, future development costs
+and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. 
+Using the average commodity prices, as adjusted, for 2010 to determine the Company’s estimated proved oil and natural gas reserves
+at December 31, 2010, the Company’s net capitalized costs less related deferred income taxes did not exceed the full-cost ceiling. As a result, the Company recorded no impairment to its net capitalized costs and no corresponding charge to
+its consolidated statement of operations for 2010. 
+Using the average commodity prices, as adjusted, for 2009 to determine the
+Company’s estimated proved oil and natural gas reserves at December 31, 2009, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $16,267,822. The Company recorded an impairment
+charge of $25,243,738 to its net capitalized costs and a deferred income tax credit of $8,975,916 related to the full-cost ceiling limitation for 2009. Corresponding charges were also recorded to the Company’s consolidated statement of
+operations for 2009. 
+F-10
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion
+and the net carrying value of the Company’s assets on its balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. 
+Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates
+of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon
+changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term, and
+drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that
+the well is not productive. 
+Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs
+with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are
+expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. 
+Other property and
+equipment are stated at cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life (5 to 7 years) using the straight-line method. Support equipment and facilities include the pipelines and salt water
+disposal systems owned by Longwood Gathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful life or
+the term of the lease. 
+Asset Retirement Obligations 
+The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of
+fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet.
+Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statement of operations. In general, the Company’s future asset retirement obligations relate to future costs associated with
+plugging and abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including
+future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in its estimate or if federal or state
+regulators enact new plugging and abandonment requirements. At the time of actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent
+that the actual costs are different from the estimated liability. 
+F-11
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Derivative Financial Instruments 
+From time to time, the Company uses derivative financial instruments to hedge its exposure to commodity price risk associated with oil and
+natural gas prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars. A costless collar provides the Company with downside price protection through the purchase of a put option which is financed
+through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is initially “costless” to the Company. The Company’s derivative financial instruments are recorded on
+the balance sheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative
+fair value between reporting periods currently in its consolidated statement of operations (see Note 10). The fair value of the Company’s derivative financial instruments is determined using purchase and sale information available for similarly
+traded securities. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and losses from valuation changes in the remaining unsettled derivative financial instruments are reported under
+“Revenues” in our consolidated statement of operations. 
+Revenue Recognition 
+The Company follows the sales method of accounting for its oil and natural gas revenue, whereby it recognizes revenue, net of royalties,
+on all oil or natural gas sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil and natural gas are produced and sold, and the Company accrues
+for revenue earned but not yet received. 
+Stock-Based Compensation 
+Non-qualified stock option expense is typically recognized in the Company’s consolidated statement of operations on the date of
+grant. Incentive stock options vest over four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. At December 31, 2011, the Company used the fair value method to measure and recognize
+the liability associated with its outstanding stock options. 
+Prior to November 22, 2010, all of the Company’s
+outstanding stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, the Company changed its method of
+accounting for outstanding stock options, reclassifying all outstanding stock options from equity to liability instruments. This change was made as a result of the Company purchasing shares from certain of its employees to assist them in the
+exercise of outstanding options of the Company’s Class A common stock. At December 31, 2010, the Company measured and recognized the liability associated with its outstanding stock options using the intrinsic value method. 
+F-12
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+The Company’s consolidated statements of operations for the years ended
+December 31, 2011, 2010 and 2009 include a stock-based compensation (non-cash) expense of $2,405,825, $897,737, and $656,087, respectively. This stock-based compensation expense includes common stock and treasury stock issuances totaling
+$230,400, $245,250, and $29,375 in 2011, 2010 and 2009, respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company. 
+Income Taxes 
+The Company accounts for income taxes using the asset
+and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and provides a valuation allowance for the portion of any deferred tax assets where the
+likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. 
+The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be
+sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the benefit that has a greater
+than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. Management believes that the material positions taken by the Company would more likely than not be sustained by examination. At December 31,
+2011 and 2010, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. 
+When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated
+statements of operations. The Company did not record any interest or penalties related to income tax for the years ended December 31, 2011, 2010 and 2009. 
+Earnings Per Common Share 
+The Company reports basic earnings per
+common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. 
+Prior to consummation of the Company’s Initial Public Offering in February 2012, the Company had issued two classes of common stock,
+Class A and Class B. The holders of the Class B shares are entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid
+quarterly. Dividends declared during 2011, 2010 and 2009 totaled $274,853 in each year. The holders of the Class B shares were also entitled to share on an equivalent basis in any dividends paid to holders of the Class A shares when and as
+declared by the Board of Directors. As of December 31, 2011, the Company has not paid any dividends to holders of the Class A shares. 
+F-13
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+The following are reconciliations of the numerators and denominators used to compute the
+Company’s basic and diluted distributed and undistributed earnings per common share as reported for the years ended December 31, 2011, 2010 and 2009. 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Net income (loss) — numerator 
+Net (loss) income 
+$ 
+(10,309,013 
+) 
+$ 
+6,376,963 
+$ 
+(14,425,342 
+) 
+Less dividends to Class B shareholders — distributed earnings 
+(274,853 
+) 
+(274,853 
+) 
+(274,853 
+) 
+Undistributed (loss) earnings 
+$ 
+(10,583,866 
+) 
+$ 
+6,102,110 
+$ 
+(14,700,195 
+) 
+Weighted average common shares outstanding — denominator 
+Basic 
+Class A 
+41,686,807 
+40,006,787 
+39,092,567 
+Class B 
+1,030,700 
+1,030,700 
+1,030,700 
+Total 
+42,717,507 
+41,037,487 
+40,123,267 
+Diluted 
+Class A 
+Weighted average common shares outstanding for basic earnings (loss) per share 
+41,686,807 
+40,006,787 
+39,092,567 
+Dilutive effect of options 
+– 
+96,140 
+– 
+Class A weighted average common shares outstanding — diluted 
+41,686,807 
+40,102,927 
+39,092,567 
+Class B 
+Weighted average common shares outstanding — no associated dilutive shares 
+1,030,700 
+1,030,700 
+1,030,700 
+Total diluted weighted average common shares outstanding 
+42,717,507 
+41,133,627 
+40,123,267 
+F-14
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Earnings (loss) per common share 
+Basic 
+Class A 
+Distributed earnings 
+$ 
+– 
+$ 
+– 
+$ 
+– 
+Undistributed (loss) earnings 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Total 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Class B 
+Distributed earnings 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+Undistributed (loss) earnings 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Total 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+Diluted 
+Class A 
+Distributed earnings 
+$ 
+– 
+$ 
+– 
+$ 
+– 
+Undistributed (loss) earnings 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Total 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Class B 
+Distributed earnings 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+Undistributed (loss) earnings 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Total 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+A total of 1,024,500 and 1,551,750 options to purchase shares of the Company’s Class A common
+stock were excluded from the calculations above for the years ended December 31, 2011 and 2009, respectively, because their effects were anti-dilutive. 
+Subsequent to December 31, 2011, all Class B shares were converted to Class A shares (see Note 17). 
+Fair Value Measurements 
+The Company measures and reports certain
+assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company
+follows FASB guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. 
+The carrying amounts reported on the balance sheet for cash and cash equivalents, certificates of deposit, accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable,
+advances from joint interest owners, dividends payable and other current liabilities approximate their fair values, due to the short-term maturity of these instruments. 
+F-15
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+At December 31, 2011 and 2010, the carrying values of $113,000,000 and $25,000,000,
+respectively, for the Company’s borrowings under its senior secured revolving Credit Agreement on the consolidated balance sheets approximate fair value as they are subject to short-term floating interest rates that approximate the rates
+available to the Company at the time. 
+Credit Risk 
+The Company uses derivative financial instruments to hedge its exposure to oil and natural gas price volatility. These transactions expose
+the Company to potential credit risk from its single counterparty. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company believes that any credit risk posed is insignificant
+and is offset by the credit worthiness of its customer base and industry partners. 
+Risks and Uncertainties
+As an oil and natural gas exploration and production company focused on finding and developing its own prospects and
+reserves, the Company’s success is highly dependent on the results of its exploration program. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reserves will be discovered. In
+addition, there are uncertainties as to the future costs or timing of drilling, completing and producing wells. Poor results from the Company’s exploration activities could limit the Company’s ability to replace and grow reserves and
+materially and adversely affect the Company’s financial position, results of operations and cash flows. 
+The Company does
+not operate properties constituting a significant portion of its oil and natural gas reserves. As a result of the Company’s sale of certain assets to Chesapeake Louisiana, L.P. (“Chesapeake”) in 2008, the Company does not operate its
+most significant natural gas asset, that being the deep rights to explore for and develop the Haynesville shale formation (underlying its existing Cotton Valley Davis production) on the Company’s Elm Grove/Caspiana leasehold in northwest
+Louisiana. Although the Company has reserved the right to participate for a proportionately reduced 25% working interest in all wells that Chesapeake drills or participates in to develop the Haynesville on this acreage, and although the Company has
+the right to propose the drilling of Haynesville wells on these properties, the Company may have limited influence on when, how and at what pace these properties are developed. This could impact the Company’s ability to replace and grow
+reserves and materially and adversely affect the Company’s financial position, results of operations and cash flows. In addition, in 2011, 2010 and 2009, the Company acquired other non-operated acreage positions in northwest Louisiana that it
+believes to be prospective for the Haynesville shale. The Company has, or will have, small, non-operated working interests in the Haynesville units including these properties, and as a result, the Company will have limited influence on when, how and
+at what pace these properties are developed. 
+Estimating oil and natural gas reserves is complex and is not exact because of
+the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated
+interpretations of that data can vary. The process also requires certain economic 
+F-16
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+assumptions, including, but not limited to, oil and natural gas prices, drilling and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices,
+revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. Any significant variance could materially and adversely affect the
+Company’s future reserves estimates, financial position, results of operations and cash flows. 
+Historically, the market
+for oil and natural gas has experienced significant price fluctuations, and this has been particularly evident in recent years. Oil and natural gas prices are impacted by supply and demand, both domestic and international, seasonal variations caused
+by changing weather conditions, political conditions, governmental regulations, the availability, proximity and capacity of gathering systems for natural gas and numerous other factors. Increases or decreases in prices received could have a
+significant and material impact on the Company’s future reserves estimates, financial position, results of operations and cash flows. 
+To mitigate its exposure to fluctuations in oil and natural gas prices, the Company, from time to time, enters into hedging arrangements, typically using put and call options in the form of costless
+collars, with respect to a portion of its oil and natural gas production. Decisions as to whether and at what production volumes to hedge are difficult and depend on market conditions and the Company’s forecast of future production and
+commodity prices, and the Company may not always employ the optimal hedging strategy. 
+The federal, state and local
+governments in the areas in which the Company operates or has assets impose taxes on the oil and gas products sold, and sales and use taxes are charged on significant portions of the Company’s drilling, completion and operating costs.
+Historically, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes in federal laws on the income taxation of oil
+and gas exploration and production companies. President Obama has proposed to eliminate allowing U.S. oil and gas companies to deduct intangible well costs as incurred and percentage depletion, among other proposals. Many states have raised state
+taxes on energy sources, and additional increases may occur. Changes to tax laws could materially and adversely affect the Company’s future financial position, results of operations and cash flows. 
+Recent Accounting Pronouncements 
+Balance Sheet. In December 2011, the FASB issued Accounting Standards Update, or ASU, 2011-11 , Balance Sheet. The requirements amend the disclosure requirements related to offsetting in
+Accounting Standards Codification, or ASC, 210-20-50 . The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with
+either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The
+adoption of ASU 2011-11 is not expected to have a material effect on the Company’s consolidated financial statements, but may require certain additional disclosures. The amendments in ASU 2011-11 are to be applied for annual reporting periods
+beginning on or after January 1, 2013 and are to be applied retrospectively for all periods presented. 
+F-17
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve
+Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (“ASU 2011-04”). ASU 2011-04 amends ASC 820 Fair Value Measurements , providing a consistent definition and measurement of fair value, as well as
+similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the ASC 820
+disclosure requirements, particularly for Level 3 fair value measurements. The adoption of ASU 2011-04 is not expected to have a material effect on the Company’s consolidated financial statements, but may require certain additional disclosures.
+The amendments in ASU 2011-04 are to be applied prospectively. The amendments are effective during interim and annual periods beginning after December 15, 2011. 
+In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure requirements to fair value measurements. The guidance requires a gross
+presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all
+companies that are required to provide disclosures about recurring and non-recurring fair value measurements and are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation
+of Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The Company adopted the first portion of this guidance beginning
+January 1, 2010, and the remaining provisions beginning January 1, 2011. The adoption of this guidance did not have a significant impact on the Company’s financial position, results of operations or cash flows. 
+Oil and Natural Gas Reserves Reporting Requirements. In January 2009, the SEC issued The Modernization of Oil and Gas
+Reporting, Final Rule . In January 2010, the FASB amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. The changes are designed to modernize and update the oil and gas disclosure requirements to align them
+with current practices and changes in technology. The new rules made a number of important changes including the following: (1) expanded the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from
+oil sands, shale coalbeds or other nonrenewable natural resources, (ii) amended the required price for estimating economic quantities for year-end reserves reporting to be the unweighted, arithmetic average of the first-day-of-the-month price
+for each month within the previous 12-month period, rather than the year-end price, and (iii) permitted proved reserves to be claimed beyond those development spacing areas that are immediately adjacent to developed spacing areas if it can be
+established with reasonable certainty that these reserves are economically producible. At December 31, 2009, the Company adopted the provisions of this new rule, and the Company has applied this new guidance for the reserves estimates at
+December 31, 2011, 2010 and 2009 included herein. 
+F-18
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 3 — PROPERTY AND EQUIPMENT 
+The following table presents a summary of the Company’s property and equipment balances as of December 31, 2011 and 2010.
+December 31, 
+2011 
+2010 
+Oil and natural gas properties 
+Evaluated (subject to amortization) 
+$ 
+423,944,476 
+$ 
+255,408,993 
+Unproved and unevaluated (not subject to amortization) 
+Incurred in 2011 
+60,934,015 
+– 
+Incurred in 2010 
+80,592,790 
+121,950,288 
+Incurred in 2009 
+8,206,954 
+14,267,810 
+Incurred in 2008 and prior 
+12,864,226 
+36,233,351 
+Total unproved and unevaluated 
+162,597,985 
+172,451,449 
+Total oil and natural gas properties 
+586,542,461 
+427,860,442 
+Accumulated depletion 
+(201,542,468 
+) 
+(134,700,857 
+) 
+Net oil and natural gas properties 
+384,999,993 
+293,159,585 
+Other property and equipment 
+Computer equipment 
+786,540 
+685,493 
+Furniture 
+458,347 
+416,095 
+Software 
+1,110,890 
+1,000,558 
+Other equipment 
+194,215 
+111,450 
+Leasehold improvements 
+626,583 
+65,899 
+Support equipment and facilities 
+15,587,463 
+11,755,515 
+Total other property and equipment 
+18,764,038 
+14,035,010 
+Accumulated depreciation 
+(3,899,256 
+) 
+(3,314,129 
+) 
+Net other property and equipment 
+14,864,782 
+10,720,881 
+Net property and equipment 
+$ 
+399,864,775 
+$ 
+303,880,466 
+The following table provides a breakdown of the Company’s unproved and unevaluated property costs
+not subject to amortization as of December 31, 2011 and the year in which these costs were incurred. 
+Description 
+2011 
+2010 
+2009 
+2008 and 
+prior 
+Total 
+Costs incurred for 
+Property acquisition 
+$ 
+40,435,891 
+$ 
+80,592,790 
+$ 
+8,206,954 
+$ 
+12,864,226 
+$ 
+142,099,861 
+Exploration wells 
+16,682,802 
+– 
+– 
+– 
+16,682,802 
+Development wells 
+2,812,615 
+– 
+– 
+– 
+2,812,615 
+Capitalized interest 
+1,002,707 
+– 
+– 
+– 
+1,002,707 
+Total 
+$ 
+60,934,015 
+$ 
+80,592,790 
+$ 
+8,206,954 
+$ 
+12,864,226 
+$ 
+162,597,985 
+F-19
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 3 — PROPERTY AND EQUIPMENT — Continued 
+Property acquisition costs primarily include leasehold costs paid to secure oil and gas
+mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are
+transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic
+basis based upon changes in operating or economic conditions. 
+Property acquisition costs incurred in 2011 were primarily
+related to the Company’s leasing and acquisition activities in the Eagle Ford shale play in south Texas. Between March and July 2011, the Company acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes,
+Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. The Company paid approximately $31.5 million to acquire this acreage, and only one well has been drilled and completed on these properties at
+December 31, 2011. The remaining property acquisition costs incurred in 2011 were related to the Company’s leasing activities in the Haynesville shale play in northwest Louisiana. Portions of these costs will be transferred to the
+amortization base periodically as the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves. The Company estimates that evaluation of most
+of these properties and the inclusion of their costs in the amortization base is expected to be completed within three to five years. 
+The 2010 and 2009 property acquisition costs were also related primarily to the Company’s leasing activities in the Eagle Ford and Haynesville shale plays. These costs are associated with acreage for
+which proved reserves have yet to be assigned. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are
+transferred to the amortization base. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within three to five years. 
+Property acquisition costs incurred in 2008 and prior years were related primarily to the Company’s leasing activities in the
+Haynesville shale play in northwest Louisiana and in southwest Wyoming, northeast Utah and southeast Idaho. During 2011, the Company drilled its first exploration well on its acreage in southwest Wyoming. The Company estimates that evaluation of
+most of these properties and the inclusion of their costs in the amortization base is expected to be completed within two to five years. 
+Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the
+amortization base on an ongoing basis, as these wells are completed and proved reserves are established or confirmed. These costs totaled $19,495,417 at December 31, 2011. Of this total, $16,682,802 was associated with exploration wells and
+$2,812,615 was associated with development wells. The Company anticipates that the entire $19,495,417 associated with these wells in progress at December 31, 2011 will be transferred to the amortization base during 2012. At December 31,
+2011, there were no well costs excluded from amortization that were incurred in years prior to 2011. 
+F-20
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 4 — ASSET RETIREMENT OBLIGATIONS 
+The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2011
+and 2010. 
+Year ended December 31, 
+2011 
+2010 
+Beginning asset retirement obligations 
+$ 
+3,695,017 
+$ 
+2,551,637 
+Liabilities incurred during period 
+186,873 
+847,845 
+Revisions in estimated cash flows 
+312,187 
+140,779 
+Liabilities settled during period 
+(133,040 
+) 
+– 
+Accretion expense 
+208,547 
+154,756 
+Ending asset retirement obligations 
+$ 
+4,269,584 
+$ 
+3,695,017 
+At December 31, 2011 and 2010, $334,500 and $131,166, respectively, of the Company’s asset
+retirement obligations were reclassified as current liabilities and included in “accrued liabilities” in the Company’s consolidated balance sheets. 
+NOTE 5 — ASSET SALES AND IMPAIRMENT 
+In December 2011, the Company
+recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the inventory was
+reduced by $17,500 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In December 2011, the Company also recorded an impairment to some of its equipment held in inventory following a
+determination that the current market value of the equipment, consisting primarily of pipe and other equipment, was less than the cost. The carrying value of the inventory was reduced by $22,276 on the balance sheet, and a corresponding charge was
+recorded to the consolidated statement of operations. In addition, the Company recorded a loss of $113,757 on certain other equipment that was sold during 2011. 
+In December 2010, the Company wrote off the Boise South Pipeline asset in Orange County, Texas from its Longwood Gathering and Disposal Systems, LP subsidiary and recorded a net loss of $173,690. The
+decision to write off this asset resulted from the fact that natural gas was no longer being put through this pipeline, nor was natural gas expected to be put through this pipeline in the future. In December 2010, the Company also recorded an
+impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the inventory was reduced by
+$50,000 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. 
+In
+December 2009, the Company recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying
+value of the inventory was reduced by $323,500 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In addition, the Company recorded a loss of $55,816 on certain other equipment that was sold
+during 2009. 
+F-21
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 6 — REVOLVING CREDIT AGREEMENT 
+In December 2011, the Company amended and restated its senior secured revolving credit agreement (“Credit Agreement”) for which
+Comerica Bank serves as administrative agent. This amendment increased the maximum facility amount from $150,000,000 to $400,000,000. Borrowings under the Credit Agreement are limited to the lesser of $400,000,000 or the borrowing base. At
+December 31, 2011, the borrowing base was $125,000,000, and the Company had $113,000,000 of outstanding borrowings plus an additional $1,262,934 in letters of credit issued pursuant to the Credit Agreement. At December 31, 2011, all
+borrowings under the Credit Agreement bore interest at approximately 5.3% per annum. The Credit Agreement matures in December 2016. In February 2012, the Company repaid all then outstanding borrowings under its Credit Agreement, and in March
+2012, the Company borrowed $15,000,000 under the Credit Agreement (see Note 17). 
+MRC Energy Company is the borrower under the
+Credit Agreement and borrowings are secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly owned subsidiaries, which are also guarantors.
+In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with Comerica Bank (or an affiliate thereof) are also secured by the collateral and
+guaranteed by the subsidiaries of MRC Energy Company. 
+The Company incurred $722,821 of additional deferred loan costs in
+connection with the amendment and restatement of the Credit Agreement in December 2011. These costs were included with the remaining unamortized portion of the deferred loan fees of $164,240 incurred when the Company entered into the Credit
+Agreement in March 2008. As a result, total deferred loan costs are $887,061 at December 31, 2011, and these costs are being amortized over the term of the agreement, which approximates the amortization of these costs using the effective
+interest method. 
+The Company previously entered into the Credit Agreement in March 2008, with a maturity date of March 2013.
+The Company amended and restated the Credit Agreement for the first time in May 2011, increasing the borrowing base at that time from $55,000,000 to $80,000,000. In addition to the Company’s revolving borrowings under the Credit Agreement, in
+May 2011, the Company also borrowed $25,000,000 under a term loan pursuant to the Credit Agreement. The term loan was due and payable on December 31, 2011 and there was no penalty for prepayment. This term loan was refinanced by revolving
+borrowings under the amended and restated Credit Agreement in December 2011. 
+The borrowing base under the Credit Agreement is
+determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s existing and future acquired oil and gas reserves, but also on external factors, such as the lenders’
+lending policies and the lenders’ estimates of future oil and natural gas prices, over which the Company has no control. At December 31, 2011, the borrowing base was $125,000,000, and the Company was required to repay $25,000,000 prior to
+December 31, 2012. Upon repayment of the $25,000,000 or any additional amounts above $25,000,000, the borrowing base would then be reduced to $100,000,000 until any subsequent redetermination of the borrowing base under the agreement.
+F-22
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+Both the Company and the lenders may each request an unscheduled redetermination of the
+borrowing base twice at any time during the first year of the Credit Agreement and once between scheduled redetermination dates thereafter. We requested one such unscheduled redetermination in February 2012 (see Note 17). In the event of a borrowing
+base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which will be determined based on market conditions at the time of the borrowing base increase. If the borrowing base were to be
+less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to
+cover such excess or to repay the deficit in equal installments over a period of six months. 
+If the Company borrows funds as
+a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the weighted average of rates used in overnight federal funds transactions with members of the Federal Reserve System plus 1.0% or (ii) the prime
+rate for Comerica Bank then in effect or (iii) a daily adjusted LIBOR rate plus 1.0% plus, in each case, an amount from 0.375% to 1.75% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrows
+funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the interest rate appearing on Page BBAM of the Bloomberg Financial Markets Information Service by (B) a
+percentage equal to 100% minus the maximum rate during such interest calculation period at which Comerica Bank is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve
+System), plus (ii) an amount from 1.375% to 2.75% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the
+Company. A facility fee of 0.375% to 0.50%, depending on the amounts borrowed, is also paid quarterly in arrears. The Company includes this facility fee in its interest rate calculations and related disclosures. 
+Key financial covenants under the Credit Agreement require us to maintain (1) a minimum current ratio, which is defined as
+consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at the end of each fiscal quarter beginning March 31, 2012, and (2) a
+debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 to 1.0 or less beginning on December 31, 2011. 
+Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s, along with its subsidiaries’, ability to take certain actions, including, but not limited
+to, the following: 
+• 
+incur indebtedness or grant liens on any of its assets; 
+• 
+enter into commodity hedging agreements; 
+• 
+declare or pay dividends, distributions or redemptions; 
+• 
+merge or consolidate; 
+F-23
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+• 
+make any loans or investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. 
+If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and
+exercise other rights and remedies. Events of default include, but are not limited to, the following events: 
+• 
+failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount
+within certain grace periods; 
+• 
+failure to perform or otherwise comply with the covenants and obligations in the credit agreement or other loan documents, subject, in certain
+instances, to certain grace periods; 
+• 
+bankruptcy or insolvency events involving the Company or its subsidiaries; and 
+• 
+a change of control, as defined in the Credit Agreement. 
+The Company believes that it was in compliance with the terms of the Credit Agreement and with all its bank covenants at December 31, 2011. We obtained a written extension until May 1, 2012 to comply with
+a covenant under the Credit Agreement requiring the submission of certain year-end 2011 operating information on or before March 1, 2012. 
+The following table presents the approximate maturities of amounts outstanding under the Credit Agreement as of December 31, 2011. 
+Year ending December 31, 
+Amount 
+2012 
+$ 
+25,000,000 
+2013 
+– 
+2014 
+– 
+2015 
+– 
+2016 
+88,000,000 
+Total 
+$ 
+113,000,000 
+In December 2010, the Credit Agreement was amended to increase the borrowing base to $55,000,000. At
+December 31, 2010, the Company had $25,000,000 of outstanding borrowings and $50,000 in letters of credit issued pursuant to the Credit Agreement. At December 31, 2010, all borrowings under the Credit Agreement were Eurocurrency loans, and
+the interest rate on the outstanding borrowings was approximately 1.6%. The Company had an additional $325,000 in letters of credit secured by certificates of deposit at Comerica Bank at December 31, 2010. 
+F-24
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 7 — INCOME TAXES 
+Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax
+bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2011 and 2010, respectively, is as follows. 
+December 31, 
+2011 
+2010 
+Deferred tax assets 
+Net operating loss — federal and state 
+$ 
+24,047,022 
+$ 
+21,768,007 
+Federal alternative minimum tax 
+6,659,528 
+6,659,528 
+Total deferred tax assets 
+30,706,550 
+28,427,535 
+Deferred tax liabilities 
+Property and equipment 
+(26,956,869 
+) 
+(33,800,718 
+) 
+Unrealized gain on derivatives 
+(3,322,255 
+) 
+(1,473,619 
+) 
+Other 
+(1,857,855 
+) 
+(59,455 
+) 
+Total deferred tax liabilities 
+(32,136,979 
+) 
+(35,333,792 
+) 
+Total net deferred tax liabilities 
+$ 
+(1,430,429 
+) 
+$ 
+(6,906,257 
+) 
+At December 31, 2011 and 2010, the Company recorded $3,023,760 and $1,473,619 of its deferred tax
+liabilities as current; these liabilities were attributable to the current portion of its unrealized derivative fair value. 
+At December 31, 2011, the Company had net operating loss carryforwards of $64,207,377 for federal income tax purposes and
+$58,477,725 for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The
+state net operating loss carryforwards expire at various dates beginning December 31, 2012 for the state of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.
+As noted previously, the Company recorded an impairment charge of $22,989,866 to its net capitalized costs, net of a deferred
+income tax credit of $12,683,232 related to the full-cost ceiling limitation during the first quarter ended March 31, 2011. This deferred income tax credit exceeded the Company’s deferred tax liabilities at March 31, 2011. As a
+result, the Company established a valuation allowance at March 31, 2011 and retained a valuation allowance until the fourth quarter of the year ended December 31, 2011 due to uncertainties regarding the future realization of its deferred
+tax assets. At December 31, 2011, the Company assessed the valuation allowance and determined that an allowance was no longer required as the remaining deferred tax assets are expected to be realized in future periods. 
+F-25
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 7 — INCOME TAXES — Continued 
+The income tax expense reconciled to the tax computed at the statutory federal rate for
+the years ended December 31, 2011, 2010 and 2009, respectively, is as follows. 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Current income tax (benefit) provision 
+State income tax 
+$ 
+(45,576 
+) 
+$ 
+30 
+$ 
+(994,504 
+) 
+Federal alternative minimum tax 
+– 
+(1,410,638 
+) 
+(1,329,834 
+) 
+Net current income tax benefit 
+(45,576 
+) 
+(1,410,608 
+) 
+(2,324,338 
+) 
+Deferred income tax provision (benefit) 
+Federal tax expense at statutory rate (34%) 
+(5,319,101 
+) 
+3,365,367 
+(7,941,036 
+) 
+Statutory depletion carryforward 
+230,707 
+(157,278 
+) 
+(610,013 
+) 
+State income tax 
+(435,379 
+) 
+– 
+– 
+Change in state rate applied 
+– 
+275,030 
+(158,638 
+) 
+Nondeductible expense 
+47,945 
+38,026 
+41,857 
+Dividends received deduction 
+– 
+– 
+(262,815 
+) 
+Federal alternative minimum tax 
+– 
+1,410,638 
+1,329,834 
+Net deferred income tax (benefit)provision 
+(5,475,828 
+) 
+4,931,783 
+(7,600,811 
+) 
+Total income tax (benefit) provision 
+$ 
+(5,521,404 
+) 
+$ 
+3,521,175 
+$ 
+(9,925,149 
+) 
+The Company files a United States federal income tax return and several state tax returns, a number of
+which remain open for examination. The tax years open for examination for the federal tax return are 2007, 2008, 2009, 2010 and 2011. The tax years open for examination by the state of Texas are 2007, 2008, 2009, 2010 and 2011. The tax years open
+for examination by the state of New Mexico are 2008, 2009, 2010 and 2011. The tax years open for examination by the state of Louisiana are 2007, 2008, 2009, 2010 and 2011. As of December 31, 2011, the Company’s 2007, 2008 and 2009 income
+and franchise tax returns are under examination by the state of Louisiana. As a result of preliminary findings received by the Company from the state of Louisiana, the Company has recorded an income tax refund of approximately $46,000 for the year
+ended December 31, 2011. 
+NOTE 8 — EMPLOYEE BENEFIT PLANS 
+Stock Options, Restricted Stock Grants and Performance Awards 
+In
+2003 the Company’s Board of Directors and shareholders approved the Matador Resources Company 2003 Stock and Incentive Plan (“Stock and Incentive Plan”). The Stock and Incentive Plan, as amended, provides that a maximum of 3,481,569
+shares of Class A common stock in the aggregate may be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the Stock and Incentive Plan include employees, directors, officers, consultants or
+advisors of the Company. 
+F-26
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 8 — EMPLOYEE BENEFIT PLANS — Continued 
+The Stock and Incentive Plan is administered by the Board of Directors, which determines
+the number of options or restricted shares to be granted, the effective dates and terms of the grants, the option or restricted share price, and the vesting period. Incentive stock options become exercisable in one to four years from the grant date
+and expire five years or ten years after the grant date. Non-qualified options become exercisable immediately upon grant and expire five years after the grant date. In the absence of an established market for shares of the Company’s common
+stock, the Board of Directors determines the fair market value of the Company’s common stock for purposes of awards under the Stock and Incentive Plan. The Company typically uses newly issued shares of common stock to satisfy option exercises
+or restricted share grants. 
+Non-qualified stock option expense is typically recognized in the Company’s consolidated
+statement of operations on the date of grant. Incentive stock option expense is recognized on a straight-line basis over the vesting period. Prior to November 22, 2010, all of the Company’s outstanding stock options were classified as
+equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. 
+Prior to November 22, 2010, the fair value of stock options granted under the Stock and Incentive Plan was estimated using the following weighted average assumptions for 2010 and 2009, respectively.
+Year ended December 31, 
+2010 
+2009 
+Stock option pricing model 
+Binomial Lattice 
+Binomial Lattice 
+Expected option life 
+5.41 years 
+3.73 years 
+Risk-free interest rate 
+2.58% 
+2.43% 
+Volatility 
+46.17% 
+52.55% 
+Dividend yield 
+0.0% 
+0.0% 
+Estimated forfeiture rate 
+11.15% 
+3.39% 
+Weighted average fair value of options granted during the year 
+$3.02 
+$1.82 
+On November 22, 2010, the Company changed its method of accounting for its outstanding stock
+options, reclassifying all outstanding stock options from equity to liability instruments (see Note 2). At December 31, 2010, the Company measured and recognized the liability associated with its outstanding stock options using the intrinsic
+value method and an estimated fair value of $11.00 per share for the Company’s Class A common stock 
+Effective upon
+filing our initial Registration Statement with the SEC in August 2011, the Company adopted the fair value method and used an estimated fair value of $12.00 per share to measure and recognize the liability associated with its outstanding stock
+options. The Company recorded $1,129,336 in additional general and administrative expenses during 2011 due to this change in the valuation method from the intrinsic value method to the fair value method. 
+F-27
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 8 — EMPLOYEE BENEFIT PLANS — Continued 
+The Company granted no stock options during the year ended December 31, 2011. The
+fair value of stock options outstanding under the Stock and Incentive Plan was estimated using the following weighted average assumptions at December 31, 2011. 
+Stock option pricing model 
+Black Scholes Merton 
+Expected option life 
+1.04 years 
+Risk-free interest rate 
+0.37% 
+Volatility 
+61.41% 
+Dividend yield 
+0.00% 
+Estimated forfeiture rate 
+1.04% 
+The Company estimated the future volatility of its Class A common stock using the historical value
+of its peer group for a period of time commensurate with the expected term of the stock option due to the lack of historical trading data available for its common stock. The expected term was estimated using the simplified method outlined in Staff
+Accounting Bulletin Topic 14. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. 
+Summarized information about stock options outstanding under the Company’s Stock and Incentive Plan is as follows. 
+Number of 
+options 
+Price 
+per share 
+Aggregate 
+option price 
+Weighted 
+average 
+exercise price 
+Options outstanding at January 1, 2009 
+1,887,750 
+$ 
+14,432,500 
+$ 
+7.65 
+Options granted 
+45,000 
+$ 
+7.50 
+337,500 
+7.50 
+Options exercised 
+(343,500 
+) 
+3.33-5.00 
+(1,281,500 
+) 
+3.73 
+Options forfeited 
+(37,500 
+) 
+3.33-13.33 
+(360,500 
+) 
+9.61 
+Options outstanding at December 31, 2009 
+1,551,750 
+$ 
+13,128,000 
+$ 
+8.46 
+Options granted 
+158,000 
+$ 
+9.00-11.00 
+1,468,000 
+9.29 
+Options exercised 
+(392,375 
+) 
+5.00-10.00 
+(1,978,375 
+) 
+5.04 
+Options forfeited or expired 
+(99,875 
+) 
+5.00-13.33 
+(773,875 
+) 
+7.75 
+Options outstanding at December 31, 2010 
+1,217,500 
+$ 
+11,843,750 
+$ 
+9.73 
+Options exercised 
+(93,001 
+) 
+$ 
+9.00 
+(837,009 
+) 
+9.00 
+Options forfeited or expired 
+(99,999 
+) 
+9.00-13.33 
+(1,015,991 
+) 
+10.16 
+Options outstanding at December 31, 2011 
+1,024,500 
+$ 
+9,990,750 
+$ 
+9.75 
+F-28
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 8 — EMPLOYEE BENEFIT PLANS — Continued 
+December 31, 2011 
+Options outstanding 
+Options exercisable 
+Range of exercise prices 
+Shares 
+outstanding 
+Weighted 
+average 
+remaining 
+contractual 
+life 
+Weighted 
+average 
+exercise 
+price 
+Shares 
+exercisable 
+Weighted 
+average 
+exercise 
+price 
+$7.50-$9.00 
+436,750 
+2.56 years 
+$ 
+8.95 
+337,375 
+$ 
+8.97 
+$10.00-$13.33 
+587,750 
+1.39 years 
+$ 
+10.35 
+460,625 
+$ 
+10.33 
+At December 31, 2011, the aggregate intrinsic value for the options outstanding was $2,303,435, of
+which $1,792,273 was exercisable at December 31, 2011 with a weighted average contractual term of 1.60 years. 
+The total
+intrinsic value of options exercised during the years ended December 31, 2011, 2010 and 2009 was $186,002, $2,180,125 and $2,153,500, respectively. The tax related benefit realized from the exercise of stock options totaled $16,220, $779,907
+and $572,191 for the years ended December 31, 2011, 2010 and 2009, respectively. 
+During the year ended December 31,
+2011, the Company recognized $2,405,825 in stock compensation expense. At December 31, 2010, the Company recognized a total stock-based liability of $1,250,467 resulting from the reclassification of its outstanding stock options from equity to
+liability instruments, including a charge to shareholders’ equity of $1,086,271 and an additional (non-cash) compensation expense of $164,196. The Company recorded $1,095,014 of this stock-based liability as a current liability and $155,453 as
+a long-term liability. During the year ended December 31, 2009, the Company recorded $656,087 in stock-based compensation costs. 
+The total tax benefit recognized for stock based compensation was $861,045, $319,208 and $233,355 for the years ended December 31, 2011, 2010 and 2009, respectively. 
+At December 31, 2011, 2010 and 2009, the total remaining unrecognized compensation expense related to unvested stock options was
+approximately $642,519, $376,986 and $807,324, respectively, and the weighted average remaining requisite service period (vesting period) of all unvested stock options was approximately 1.18, 1.65 and 1.93 years, respectively. 
+A summary of the non-vested stock options as of December 31, 2011 is presented below. 
+Non-vested stock options 
+Shares 
+Weighted 
+average 
+fair 
+value 
+Non-vested at January 1, 2011 
+517,750 
+$ 
+4.52 
+Vested 
+(247,500 
+) 
+3.86 
+Forfeited 
+(43,750 
+) 
+4.21 
+Non-vested at December 31, 2011 
+226,500 
+$ 
+5.30 
+The fair value of option shares vested during 2011, 2010 and 2009 was $954,558, $2,413,250 and
+$2,830,592, respectively. 
+F-29
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 8 — EMPLOYEE BENEFIT PLANS — Continued 
+On October 28, 2010, the Company made a restricted stock grant of 15,000 shares of
+Class A common stock to an employee. These shares vest according to the following schedule: 3,000 shares were fully vested upon grant, an incremental 4,000 shares vested on October 28, 2011 and an incremental 4,000 shares will vest on each
+of October 28, 2012 and 2013. Should the employee cease to remain in service with the Company other than by death or disability, all unvested shares will be forfeited. 
+In October 2008, the Company’s Board of Directors approved the adoption of the Employee Share Repurchase Program (“Repurchase Program”) authorizing the Company to repurchase shares of its
+Class A common stock from its employees, directors and officers, subject to certain conditions and restrictions. In 2010, the Company repurchased 117,505 shares of Class A common stock at $11.00 per share from thirteen employees (including
+the Executive Vice President, Chief Financial Officer and Chief Operating Officer, the Executive Vice President — Operations and the Vice President — Reservoir Engineering). In 2009, the Company repurchased 114,000 shares of Class A
+common stock at $7.33-$7.50 per share from ten employees (including the Vice President — Reservoir Engineering and the Vice President — Geophysics and New Ventures). No director nor the Company’s Chairman and Chief Executive Officer
+has ever participated in the Repurchase Program. The Company’s Board of Directors terminated the Repurchase Program in April 2011, and the Company is no longer authorized to repurchase shares of Class A common stock from its employees,
+directors and officers. No shares were repurchased in 2011 prior to the termination of the Repurchase Program by the Board of Directors. 
+In October 2008, the Company’s Board of Directors approved the adoption of the Employee Option Exercise Loan Program (“Loan Program”), authorizing the Company to establish a loan program
+with a financial institution to assist its employees, directors and officers in the exercise of their outstanding options to purchase shares of Class A common stock, subject to certain conditions and restrictions outlined in the Loan Program.
+As part of the Loan Program, the Company provides the financial institution with a guaranty of repayment of the loan and makes deposits of funds in certificates of deposit to secure its guaranty. Notwithstanding the guaranty, these loans are fully
+recourse obligations of each loan recipient, and each loan recipient agrees to indemnify and reimburse the Company in full for all liabilities incurred by the Company in the event of the recipient’s default on the loan. Each loan recipient also
+pledges all shares purchased from the Company with the loan proceeds to further secure his or her obligations to the Company in return for its guaranty. No director nor the Company’s Chairman and Chief Executive Officer has ever participated in
+the Loan Program. 
+As of December 31, 2011, the Company had secured the loans of eight employees (including the Executive
+Vice President, Chief Financial Officer and Chief Operating Officer, the Executive Vice President — Operations and the Vice President — Reservoir Engineering) pursuant to this Loan Program in the aggregate amount of $1,326,000. The Company
+considers the fair value of this aggregate guaranty to be minimal and has recorded no liability provision associated with this guaranty on its consolidated balance sheets in any reporting period presented. The Company’s Board of Directors
+terminated the Loan Program in April 2011, and the Company is no longer authorized to provide financial guaranties for additional loans. No new loans were guaranteed in 2011 prior to the termination of the Loan Program by the Board of Directors.
+Subsequent to December 31, 2011, the Company terminated its guaranties of the loans for the 
+F-30
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 8 — EMPLOYEE BENEFIT PLANS — Continued 
+three officers of the Company noted above (see Note 17). The Company continues to secure the loans of the other five employees in the aggregate amount of $266,000. 
+401(k) Plan 
+Effective July 3, 2003, the Company established a defined contribution retirement plan. All full-time Company employees are eligible to join the plan the first day of the calendar month immediately
+following their date of employment. Each Participant may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation,
+referred to as the Employer’s Safe Harbor Non-Elective Contribution. The Company’s Safe Harbor match was $166,204, $159,995, and $140,543 in 2011, 2010 and 2009, respectively. In addition, each year, the Company may determine and make a
+discretionary matching contribution as well as additional contributions. The Company’s discretionary matching contributions totaled $207,735, $197,504, and $167,456 in 2011, 2010 and 2009, respectively. The Company made no additional
+discretionary contributions in any reporting period presented. 
+NOTE 9 — COMMON STOCK 
+Dividends 
+At December 31, 2011 and 2010, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares are entitled to be paid cumulative dividends at a per
+share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during 2011, 2010 and 2009 totaled $274,853 in each year. Dividends for the fourth
+quarter of 2011 were accrued and paid in January 2012. Dividends for the fourth quarter of 2010 and 2009 were accrued and paid in January 2011 and 2010, respectively. As of December 31, 2011, the Company has not paid any dividends to holders of
+the Class A shares. In February 2012, upon the consummation of the Company’s Initial Public Offering, the Class B shares were converted to Class A shares, which are now referred to as common stock (see Note 17). 
+Stock Offerings, Retirement and Issuances 
+Subsequent to December 31, 2011, the Company issued 12,209,167 shares of its common stock at $12.00 per share pursuant to its Initial Public Offering (see Note 17). In connection with this offering,
+the Company incurred $1,660,439 in legal, accounting and other fees during the year ended December 31, 2011, which were recorded as cost to issue equity in the Consolidated Statements of Shareholders’ Equity. 
+In October 2010, the Board of Directors approved and authorized the private offering and sale of additional shares of the Company’s
+Class A common stock at $11.00 per share in the period from October 2010 through January 2011. As of December 31, 2010, the Company sold 1,868,427 shares and received net proceeds of $20,536,167. In January 2011, the Company sold an
+additional 53,772 shares as part of this offering and received net proceeds of $584,918. The Company also sold 11,000 shares of Class A common stock at $9.00 per share to an accredited investor and received gross and net proceeds of $99,000 in
+May 2010. 
+F-31
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 9 — COMMON STOCK — Continued 
+In February 2009, one of the Company’s largest shareholders at the time, Gandhara
+Capital (Gandhara), a large international hedge fund, notified the Company of its need to sell its entire holdings of the Company’s Class A common stock totaling 5,422,713 shares due to its plan for liquidation. The Board of Directors
+unanimously authorized the repurchase of all of Gandhara’s outstanding shares at $5.00 per share, and Gandhara accepted this offer. In April 2009, the Company repurchased 5,422,713 shares of its Class A common stock from Gandhara for
+$27,113,565. These shares were effectively retired by the Company; however, this share repurchase and effective retirement did not reduce the 80,000,000 total shares of Class A common stock authorized for issue by the Company. 
+Following the repurchase of these shares from Gandhara, the Board of Directors approved and authorized the Company’s May 2009
+private offering in which the Company sold 4,950,694 shares of Class A common stock and received net proceeds of $27,982,569. In addition to this offering, the Company sold 23,500 shares of Class A common stock to two accredited
+shareholders and received net proceeds of $176,250 during 2009. 
+Treasury Stock 
+During 2010, the Company issued 6,000 shares of Class A common stock valued at $7.50-$9.00 per share from treasury stock. The Company
+also purchased 1,117,505 shares of Class A common stock for $9.00-$11.00 per share. These purchases included 1,000,000 shares of Class A common stock purchased from five shareholders, all advised by Wellington Management Company, in April
+2010 at $9.00 per share, for a total of $9,000,000. 
+During 2009, the Company issued 652,126 shares of Class A common
+stock valued at $5.00-$7.50 per share from treasury stock. The Company also purchased 679,923 shares of Class A common stock from certain shareholders at $5.00-$7.50 per share. 
+NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS 
+From time to time, the
+Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil and natural gas prices. These instruments consist of put and call options in the form of costless collars. The Company records
+derivative financial instruments on its balance sheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company
+recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using
+purchase and sale information available for similarly traded securities. The Company has evaluated the credit standing of its single counterparty, Comerica Bank, in determining the fair value of these derivative financial instruments. 
+In November and December 2011, the Company entered into various costless collar contracts to mitigate its exposure to fluctuations in oil
+prices for the first time, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to 
+F-32
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+any of these transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation
+period’s calendar month. When the settlement price is below the price floor established by these collars, the Company receives from Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price
+floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by these collars, the Company pays to Comerica, as counterparty, an amount equal to the difference between the settlement price and the
+price ceiling multiplied by the contract oil volume. 
+During 2011, 2010 and 2009, the Company entered into various costless
+collar transactions for natural gas, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to the Company pursuant to any of these transactions is the settlement
+price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the last day of that contract period. When the settlement price is below the price floor established
+by these collars, the Company receives from Comerica Bank, as counterparty, an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the
+price ceiling established by these collars, the Company pays to Comerica, as counterparty, an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. 
+At December 31, 2011, the Company had three costless collar contracts open and in place to mitigate its exposure to natural gas
+price volatility and three costless collar contracts open and in place to mitigate its exposure to oil price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is
+set to expire at varying times during 2012 and 2013. 
+The following is a summary of the Company’s open costless collar
+contracts for oil and natural gas at December 31, 2011. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Bbls/month) 
+Price 
+Floor 
+($/Bbl) 
+Price 
+Ceiling 
+($/Bbl) 
+Fair Value 
+of Asset 
+(Liability) 
+Oil 
+12/01/2011 - 12/31/2012 
+20,000 
+90.00 
+104.20 
+$ 
+(219,283 
+) 
+Oil 
+01/01/2012 - 12/31/2012 
+10,000 
+90.00 
+108.00 
+48,031 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+85.00 
+102.25 
+(382,848 
+) 
+Total Oil 
+(554,100 
+) 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(MMBtu/month) 
+Price 
+Floor 
+($/MMBtu) 
+Price 
+Ceiling 
+($/MMBtu) 
+Fair Value 
+of Asset 
+Natural Gas 
+07/01/2011 - 12/31/2012 
+300,000 
+4.50 
+5.60 
+4,690,238 
+Natural Gas 
+07/01/2011 - 07/31/2013 
+150,000 
+4.50 
+5.75 
+3,196,466 
+Natural Gas 
+01/01/2012 - 12/31/2012 
+150,000 
+4.25 
+6.17 
+1,949,330 
+Total Natural Gas 
+9,836,034 
+Total open costless collar contracts 
+$ 
+9,281,934 
+F-33
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following table summarizes the location and aggregate fair value of all derivative
+financial instruments recorded in the consolidated balance sheets for the periods presented. These derivative financial instruments are not designated as hedging instruments. 
+December 31, 
+Type of Instrument 
+Location in Balance Sheet 
+2011 
+2010 
+Derivative Instrument 
+Oil 
+Current liabilities: Derivative instruments 
+$ 
+171,252 
+$ 
+– 
+Oil 
+Long-term liabilities: Derivative instruments 
+382,848 
+– 
+Natural Gas 
+Current assets: Derivative instruments 
+8,988,767 
+4,144,411 
+Natural Gas 
+Other assets: Derivative instruments 
+847,267 
+– 
+Total 
+$ 
+9,281,934 
+$ 
+4,144,411 
+The following table summarizes the location and aggregate fair value of all derivative financial
+instruments recorded in the consolidated statements of operations for the periods presented. These derivative financial instruments are not designated as hedging instruments. 
+Type of Instrument 
+Location in 
+Statement of
+Operations 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Derivative Instrument 
+Natural Gas 
+Revenues: Realized gain 
+on derivatives 
+$ 
+7,106,260 
+$ 
+5,299,380 
+$ 
+7,625,120 
+Realized gain on derivatives 
+7,106,260 
+5,299,380 
+7,625,120 
+Oil 
+Revenues: Unrealized 
+loss on derivatives 
+(554,100 
+) 
+– 
+– 
+Natural Gas 
+Revenues: Unrealized 
+gain (loss) on derivatives 
+5,691,622 
+3,138,726 
+(2,374,638 
+) 
+Unrealized gain (loss) on derivatives 
+5,137,522 
+3,138,726 
+(2,374,638 
+) 
+Total 
+$ 
+12,243,782 
+$ 
+8,438,106 
+$ 
+5,250,482 
+F-34
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 11 — FAIR VALUE MEASUREMENTS 
+The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price
+that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following
+categories. 
+Level 1 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those
+in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. 
+Level 2 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This
+category includes those derivative instruments that are valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable
+data or supported by observable levels at which transactions are executed in the marketplace. 
+Level 3 
+Unobservable inputs that are not corroborated by market data. This category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based
+on internally developed models or methodologies using significant inputs that are generally less readily observable from objective sources. 
+Financial and non-financial assets and liabilities are classified based on the lowest level of input that
+is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement
+within the fair value hierarchy levels. 
+The following tables summarize the valuation of the Company’s financial assets
+and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2011 and 2010. 
+Description 
+Fair Value Measurements
+at 
+December 31, 2011 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Certificates of deposit 
+$ 
+– 
+$ 
+1,335,000 
+$ 
+– 
+$ 
+1,335,000 
+Oil and natural gas derivatives 
+– 
+9,836,034 
+– 
+9,836,034 
+Liabilities 
+Oil and natural gas derivatives 
+– 
+(554,100 
+) 
+– 
+(554,100 
+) 
+Total 
+$ 
+– 
+$ 
+10,616,934 
+$ 
+– 
+$ 
+10,616,934 
+Description 
+Fair Value Measurements at 
+December 31,
+2010 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets 
+Certificates of deposit 
+$ 
+– 
+$ 
+2,349,313 
+$ 
+– 
+$ 
+2,349,313 
+Natural gas derivatives 
+– 
+4,144,411 
+– 
+4,144,411 
+Total 
+$ 
+– 
+$ 
+6,493,724 
+$ 
+– 
+$ 
+6,493,724 
+F-35
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 11 — FAIR VALUE MEASUREMENTS — Continued 
+The Company’s accounting policies for certificates of deposit and derivative
+financial instruments are discussed in Note 2; additional disclosures related to derivative financial instruments are provided in Note 10. For purposes of fair value measurement, the Company determined that certificates of deposit and derivative
+financial instruments (e.g., oil and natural gas derivatives) should be classified as Level 2. 
+The Company accounts for
+additions to asset retirement obligations and lease and well equipment inventory at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value
+on a non-recurring basis as of December 31, 2011 and 2010. 
+Description 
+Fair Value Measurements
+at 
+December 31, 2011 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Asset retirement obligations 
+$ 
+– 
+$ 
+– 
+$ 
+(186,873 
+) 
+$ 
+(186,873 
+) 
+Lease and well equipment inventory 
+– 
+– 
+1,343,416 
+1,343,416 
+Total 
+$ 
+– 
+$ 
+– 
+$ 
+1,156,543 
+$ 
+1,156,543 
+Description 
+Fair Value Measurements
+at 
+December 31, 2010 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Asset retirement obligations 
+$ 
+– 
+$ 
+– 
+$ 
+(847,845 
+) 
+$ 
+(847,845 
+) 
+Lease and well equipment inventory 
+– 
+– 
+442,500 
+442,500 
+Total 
+$ 
+– 
+$ 
+– 
+$ 
+(405,345 
+) 
+$ 
+(405,345 
+) 
+The Company’s accounting policies for asset retirement obligations are discussed in Note 2;
+reconciliations of the Company’s asset retirement obligations are provided in Note 4 for the periods presented. For purposes of fair value measurement, the Company determined that the additions to asset retirement obligations should be
+classified as Level 3. The Company recorded additions to asset retirement obligations of $186,873 and $847,845 in 2011 and 2010, respectively. 
+The Company’s accounting policies for lease and well equipment inventory are discussed in Note 2. For purposes of fair value measurement, the Company determined that lease and well equipment
+inventory should be classified as Level 3. The Company recorded an impairment to some of its equipment held in inventory, consisting primarily of drilling rig parts, of $17,500 and $50,000 in 2011 and 2010, respectively. The Company recorded an
+impairment to some of its equipment held in inventory, consisting primarily of pipe and other equipment, of $22,276 in 2011; no impairment to this equipment was recorded in 2010. The Company periodically obtains estimates of the market value of its
+equipment held in inventory from an independent third-party contractor or seller of similar equipment and uses these estimates as a basis for its measurement of the fair value of this equipment. 
+F-36
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 12 — COMMITMENTS AND CONTINGENCIES 
+Office Lease 
+The Company’s corporate headquarters are located in 28,743 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The office lease commencement date was
+September 25, 2003 with an expiration date of June 30, 2011. In April 2011, the Company agreed to a restated third amendment to its office lease agreement, in which the office space was increased to 28,743 square feet and the term of the
+lease was extended from July 1, 2011 to June 30, 2022. The effective base rent over the term of the new lease extension is $19.75 per square foot per year. The base rate escalates several times during the course of the lease, specifically
+in July 2015, July 2017, July 2019 and July 2020. 
+The following is a schedule of future minimum lease payments
+required under the office lease agreement as of December 31, 2011. 
+Year ending December 31, 
+Amount 
+2012 
+$ 
+287,430 
+2013 
+574,860 
+2014 
+574,860 
+2015 
+589,232 
+2016 
+603,603 
+Thereafter 
+3,612,995 
+Total 
+$ 
+6,242,980 
+Rent expense, including fees for operating expenses and consumption of electricity, was $474,923,
+$386,092 and $417,371 for 2011, 2010 and 2009, respectively. 
+Other Commitments 
+At December 31, 2011, the Company had entered into two drilling rig contracts to explore and develop its Eagle Ford acreage in south
+Texas. The two rigs began drilling on the Company’s acreage in September and October 2011, respectively. Both contracts are for a term of six months. Should the Company elect to terminate one or both contracts and if the drilling contractor
+were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms, the Company would
+incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under these contracts were approximately $2.7 million at December 31, 2011. 
+At December 31, 2011, the Company had outstanding commitments to participate in the drilling and completion of various non-operated
+wells in the Haynesville shale. The Company’s working interests in these wells are small, and most of these wells were in progress at December 31, 2011. If all of these wells are drilled and completed, the Company’s minimum
+outstanding aggregate commitments at December 31, 2011 for its participation in these non-operated Haynesville wells were approximately $5.1 million, and the Company expects these costs to be incurred in the next 12 months. 
+F-37
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 12 — COMMITMENTS AND CONTINGENCIES — Continued 
+In June 2011, the Company awarded bonuses to certain of its current employees, but not
+including any of its executive officers, in the aggregate amount of $1,240,000. These bonuses will be payable in a lump sum to each of the employees in June 2014, provided each continues to remain an employee in good standing with Company at that
+time. 
+Legal Proceedings 
+The Company is a defendant in several lawsuits encountered in the ordinary course of its business, none of which, in the opinion of management, will have a material adverse impact on the Company’s
+financial position, results of operations or cash flows. 
+General Federal and State Regulations 
+Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations.
+Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is
+in compliance with currently applicable state and federal regulations. Because these rules and regulations are frequently amended or reinterpreted, however, the Company is unable to predict the future cost or impact of complying with these
+regulations. 
+Environmental Regulations 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws
+and regulations. These laws and regulations can increase the costs of planning, designing, installing, and operating oil and natural gas wells. The Company’s activities are subject to a variety of environmental laws and regulations, including
+but not limited to the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or
+CAA, the Safe Drinking Water Act, or SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. The Company is also subject to regulations governing the handling, transportation, storage and
+disposal of waste generated by its activities and of naturally occurring radioactive materials, or NORM, that may result from its oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these
+environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected
+wetlands, areas or species, and require investigation and cleanup of pollution. The Company has no outstanding material environmental remediation liabilities and believes that it is in compliance with currently applicable environmental laws and
+regulations and that these laws and regulations will not have a material adverse impact on the financial position, results of operations or cash flows of the Company. 
+Changes in environmental laws and regulations occur frequently, however, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements
+could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations 
+F-38
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 12 — COMMITMENTS AND CONTINGENCIES — Continued 
+and cash flows, as well as those of the oil and natural gas industry in general. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the
+future cost or impact of complying with these regulations. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be
+contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal or state laws or implementing
+regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require the Company to incur increased operating costs adversely affecting its financial position, results of operations and cash flows.
+The Company’s activities involve the use of hydraulic fracturing. Recently, there has been increasing regulatory
+scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection at the federal level. At the federal level and in some states, there have been efforts to place additional regulatory burdens on hydraulic
+fracturing activities. In addition, certain bills have been introduced in the Senate and the House of Representatives that, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level
+that could lead to operational delays or increased operating costs and could, and in all likelihood, would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing the
+Company’s costs of compliance. At the state level, Wyoming and Texas, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed into law a
+mandate for public disclosure of the chemicals that operators use during hydraulic fracturing in Texas. The law went into effect September 1, 2011. State regulators have until 2013 to complete implementing rules. In addition, at least a few
+local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens on hydraulic
+fracturing, such as reporting requirements or permitting requirements for hydraulic fracturing activities, could, and in all likelihood would, result in additional expense and delay the Company’s operations adversely affecting its financial
+position, results of operations and cash flows. 
+Oil and natural gas exploration and production, operations and other
+activities have been conducted at some of the Company’s properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, the Company
+occasionally must agree to indemnify sellers of producing properties the Company acquires against some or all of the liability for environmental claims associated with these properties. While the Company does not believe that the costs it incurs for
+compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, the Company cannot provide assurances that these costs will not result in material expenditures that adversely affect
+its financial position, results of operations and cash flows. 
+The Company maintains insurance against some, but not all,
+potential risks and losses associated with the oil and natural gas industry and operations. The Company does not carry business interruption insurance. For some risks, the Company may not obtain insurance if it believes the cost of available
+insurance is excessive relative to the risks presented. In addition, pollution and environmental risks 
+F-39
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 12 — COMMITMENTS AND CONTINGENCIES — Continued 
+generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could, and in all likelihood would, materially adversely affect the
+Company’s financial position, results of operations and cash flows. 
+NOTE 13 — MAJOR CUSTOMERS 
+For the year ended December 31, 2011, the Company had three significant purchasers that each accounted for more than 10% of its total
+oil and natural gas revenues: Sequent Energy Management (24%), Chesapeake Operating, Inc. (21%) and Eastex Crude Company (15%). For the year ended December 31, 2010, the Company had three significant purchasers that each accounted for more
+than 10% of its total oil and natural gas revenues: Chesapeake Operating, Inc. (42%), Regency Gas Services LP (17%) and Petrohawk Energy Corporation (11%). For the year ended December 31, 2009, the Company had three significant purchasers
+that each accounted for more than 10% of its total oil and natural gas revenues: Chesapeake Operating, Inc. (32%), Regency Gas Services LP (25%) and J-W Operating Company (17%). Due to the nature of the markets for oil and natural gas, the
+Company does not believe that the loss of any one purchaser would have a material adverse impact on the Company’s financial position, results of operations or cash flows for any significant period of time. 
+At December 31, 2011, the Company had two industry partners, Goodrich Petroleum Corporation, LLC and Alliance Capital Real Estate,
+Inc. that accounted for 77% and 17% of its accounts receivable, respectively. At December 31, 2010, the Company had one industry partner, Goodrich Petroleum Corporation, LLC, that accounted for approximately 93%, of its accounts receivable.
+NOTE 14 — SUPPLEMENTAL DISCLOSURES 
+Accrued Liabilities 
+The following table summarizes the
+Company’s current accrued liabilities at December 31, 2011 and 2010. 
+December 31, 
+2011 
+2010 
+Accrued evaluated and unproved and unevaluated property costs 
+$ 
+18,184,818 
+$ 
+12,119,475 
+Accrued support equipment and facilities costs 
+215,517 
+40,145 
+Accrued cost to issue equity 
+331,818 
+359,175 
+Accrued stock-based compensation 
+2,859,527 
+1,095,014 
+Accrued lease operating expenses 
+575,318 
+428,481 
+Accrued asset retirement obligations 
+334,500 
+131,166 
+Other 
+2,937,395 
+616,256 
+Total accrued liabilities 
+$ 
+25,438,893 
+$ 
+14,789,712 
+F-40
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 14 — SUPPLEMENTAL DISCLOSURES — Continued 
+Supplemental Cash Flow Information 
+The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2011, 2010 and 2009.
+Year ended December 31, 
+2011 
+2010 
+2009 
+Cash paid (refunded) for income taxes 
+$ 
+60 
+$ 
+(2,155,517 
+) 
+$ 
+(1,235,672 
+) 
+Cash paid for interest expense, net of amounts capitalized 
+633,562 
+– 
+– 
+Asset retirement obligations related to mineral properties 
+487,529 
+862,238 
+642,836 
+Asset retirement obligations related to support equipment and facilities 
+11,531 
+126,386 
+8,155 
+Increase (decrease) in liabilities for oil and natural gas properties capital expenditures 
+1,863,715 
+15,530,871 
+(2,470,798 
+) 
+Increase in liabilities for support equipment and facilities 
+175,372 
+39,657 
+– 
+Issuance of treasury stock for Board and advisor services 
+– 
+47,250 
+29,375 
+Issuance of stock for Board and advisor services 
+230,400 
+– 
+– 
+(Decrease) increase in liabilities for accrued cost to issue equity 
+(27,357 
+) 
+359,174 
+– 
+Stock based compensation expense recognized as liability 
+2,102,271 
+164,188 
+– 
+Transfer of inventory to oil and natural gas properties 
+96,164 
+353,395 
+– 
+NOTE 15 — TRANSACTIONS WITH RELATED PARTIES 
+In January 2007, the Company entered into a joint venture with Marlan Downey and Julie Downey Garvin of Roxanna Oil Company
+(“Roxanna”) to assemble acreage for and to market a new gas shale prospect in southwest Wyoming, northeast Utah and southeast Idaho. Mr. Downey is a special advisor to the Company’s Board of Directors and a shareholder in the
+Company. Ms. Garvin is President of Roxanna, which is also a shareholder in Matador. Mr. Downey and Ms. Garvin developed the prospect concept independently and sought the Company’s expertise in assembling a large acreage position
+across the prospect. At December 31, 2011, the Company has assembled over 140,000 acres across the prospect at a total cost of approximately $9,700,000. The Company actively marketed this prospect in conjunction with Mr. Downey and
+Ms. Garvin. In May 2010, the Company, Roxanna and its subsidiary, Roxanna Rocky Mountains, LLC, entered into participation and joint operating agreements with an industry partner for the joint exploration and development of this opportunity.
+Under these agreements, Roxanna Rocky Mountains, LLC reserves a 2.5% overriding royalty interest in the leases and has the opportunity to earn up to a 10% working interest in all wells drilled. The industry partner has a 50% working interest in the
+project, and the Company retains a working interest equal to the difference between 50% and the working interest participation elected by Roxanna Rocky Mountains, LLC. The Company, as operator, drilled the initial test well for this prospect located
+in Lincoln County, Wyoming during 2011. This well was awaiting completion at December 31, 2011. 
+F-41
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) 
+Costs Incurred 
+The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration, and development of oil and natural gas properties for the years ended December 31, 2011,
+2010 and 2009. 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Property acquisition costs 
+Proved 
+$ 
+– 
+$ 
+– 
+$ 
+– 
+Unproved and unevaluated 
+41,496,929 
+100,730,019 
+24,803,480 
+Exploration costs 
+108,662,417 
+60,718,511 
+21,386,885 
+Development costs 
+12,511,018 
+14,348,040 
+6,225,511 
+Total costs incurred 
+$ 
+162,670,364 
+$ 
+175,796,570 
+$ 
+52,415,876 
+Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas
+properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2011, 2010 and 2009, respectively, essentially all of the Company’s property acquisition costs resulted from
+the acquisition of unproved and unevaluated leasehold positions. 
+Exploration costs are costs incurred in identifying areas of
+these oil and gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical
+costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. 
+Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering
+and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and
+installing production facilities. 
+Costs incurred also include new asset retirement obligations established, as well as
+changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were $499,060, $988,624 and $650,991 for the years ended December 31, 2011, 2010
+and 2009, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $2,020,486, $1,604,682, and
+$1,642,868 of these internal costs in 2011, 2010 and 2009, respectively. Capitalized interest expense for qualifying projects are also included in the table above. The Company capitalized $1,278,383 of its interest expense for the year ended
+December 31, 2011. The Company recorded only $3,235 in interest expense for the year ended December 31, 2010 and had no outstanding borrowings in 2009. As a result, the Company capitalized no interest expense for the years ended
+December 31, 2010 and 2009. 
+F-42
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+Oil and Natural Gas Operating Results 
+The following table provides the results of operations from oil and gas producing activities, excluding corporate overhead and interest
+costs, for the years ended December 31, 2011, 2010 and 2009. 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Oil and natural gas revenues 
+$ 
+66,999,826 
+$ 
+34,041,607 
+$ 
+19,038,514 
+Production taxes and marketing expenses 
+6,277,860 
+1,981,550 
+1,077,145 
+Lease operating expenses 
+7,244,339 
+5,284,362 
+4,725,022 
+Depletion, depreciation and amortization 
+31,619,443 
+15,423,044 
+10,510,769 
+Accretion of asset retirement obligations 
+208,547 
+154,756 
+137,347 
+Full-cost ceiling impairment 
+35,673,098 
+– 
+25,243,738 
+Net operating income (loss) 
+(14,023,461 
+) 
+11,197,895 
+(22,655,507 
+) 
+Income tax provision (benefit) 
+(5,018,997 
+) 
+3,982,834 
+(8,055,619 
+) 
+Results of oil and natural gas operations 
+$ 
+(9,004,464 
+) 
+$ 
+7,215,061 
+$ 
+(14,599,888 
+) 
+Depletion, depreciation and amortization per Mcfe 
+$ 
+2.05 
+$ 
+1.79 
+$ 
+2.10 
+Oil and Natural Gas Reserves 
+Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable
+certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is not exact because of the numerous uncertainties inherent in the process.
+The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process
+also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes,
+development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. 
+Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. In
+January 2009, the SEC issued The Modernization of Oil and Gas Reporting, Final Rule and in January 2010, the FASB amended Topic 932, Extractive Activities — Oil and Gas to align with this rule. As a result, beginning
+December 31, 2009, the commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period January
+through December 2011, these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu (million British thermal units), respectively. For the period January through December 2010, these average oil and natural gas prices were
+$75.96 per barrel and $4.376 per MMBtu, respectively. For the period January through December 2009, these average oil and natural gas prices were $57.65 per barrel and $3.866 per MMBtu, respectively. 
+F-43
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+The Company’s oil and natural gas reserves estimates are prepared by the
+Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers,
+for the years ended December 31, 2011, 2010 and 2009. 
+The Company’s net ownership in estimated quantities of proved oil
+and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for
+proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated
+acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, oil is converted to gas equivalent using the ratio of one barrel of oil, condensate or natural gas liquids to 6 Mcf (thousand
+standard cubic feet) of natural gas. 
+Net Proved Reserves 
+Oil 
+Gas 
+Gas 
+Equivalent 
+(MBbl) 
+(MMcf) 
+(MMcfe) 
+Proved Developed and Proved Undeveloped Reserves 
+Total at December 31, 2008 
+131 
+19,196 
+19,979 
+Revisions of prior estimates 
+(13 
+) 
+(811 
+) 
+(883 
+) 
+Extensions and discoveries 
+15 
+50,367 
+50,454 
+Production 
+(30 
+) 
+(4,823 
+) 
+(5,002 
+) 
+Total at December 31, 2009 
+103 
+63,929 
+64,548 
+Revisions of prior estimates 
+66 
+874 
+1,265 
+Extensions and discoveries 
+16 
+71,009 
+71,107 
+Production 
+(33 
+) 
+(8,400 
+) 
+(8,597 
+) 
+Total at December 31, 2010 
+152 
+127,412 
+128,323 
+Revisions of prior estimates 
+51 
+(646 
+) 
+(343 
+) 
+Extensions and discoveries 
+3,745 
+58,164 
+80,636 
+Production 
+(154 
+) 
+(14,512 
+) 
+(15,437 
+) 
+Total at December 31, 2011 
+3,794 
+170,418 
+193,179 
+Proved Developed Reserves 
+December 31, 2008 
+131 
+19,196 
+19,979 
+December 31, 2009 
+103 
+25,369 
+25,988 
+December 31, 2010 
+152 
+43,143 
+44,054 
+December 31, 2011 
+1,419 
+56,547 
+65,061 
+Proved Undeveloped Reserves 
+December 31, 2008 
+– 
+– 
+– 
+December 31, 2009 
+– 
+38,560 
+38,560 
+December 31, 2010 
+– 
+84,269 
+84,269 
+December 31, 2011 
+2,375 
+113,871 
+128,118 
+F-44
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+The following is a discussion of the changes in the Company’s proved oil and
+natural gas reserves estimates for the years ended December 31, 2011, 2010 and 2009. 
+The Company’s proved oil and
+natural gas reserves increased to 193.2 Bcfe at December 31, 2011 from 128.3 Bcfe at December 31, 2010. The Company increased its proved oil and natural gas reserves by 80.3 Bcfe and produced 15.4 Bcfe during the year ended
+December 31, 2011, resulting in a net gain of 64.9 Bcfe. A total of 80.6 Bcfe of the increase in proved oil and gas reserves was a result of extensions and discoveries during the year, all of which was attributable to drilling operations in the
+Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana. The Company’s oil and natural gas reserves decreased by 0.3 Bcfe during the year as a result of revisions to previous estimates, representing the net
+impact of small changes in prior estimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to 65.1 Bcfe at December 31, 2011 from 44.1 Bcfe at December 31, 2010,
+primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford and Haynesville shale plays. At December 31, 2011, the Company’s proved reserves were made up of approximately 88% natural gas and 12%
+oil. 
+The Company’s proved oil and natural gas reserves increased to 128.3 Bcfe at December 31, 2010 from 64.5 Bcfe
+at December 31, 2009. The Company increased its proved oil and natural gas reserves by 72.4 Bcfe and produced 8.6 Bcfe during the year ended December 31, 2010, resulting in a net gain of 63.8 Bcfe. A total of 71.1 Bcfe of the increase in
+proved oil and gas reserves was a result of extensions and discoveries during the year, almost all of which was attributable to drilling operations in the Haynesville shale play in northwest Louisiana. A total of 1.3 Bcfe of the increase in proved
+oil and natural gas reserves was attributable to revisions of previous estimates, representing the net impact of small changes in prior estimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas
+reserves increased to 44.1 Bcfe at December 31, 2010 from 26.0 Bcfe at December 31, 2009, primarily due to proved developed reserves added as a result of drilling operations in the Haynesville shale play. At December 31, 2010, the
+Company’s proved reserves were made up of approximately 99% natural gas and 1% oil. 
+The Company’s proved oil and
+natural gas reserves increased to 64.5 Bcfe at December 31, 2009 from 20.0 Bcfe at December 31, 2008. The Company increased its proved oil and natural gas reserves by 49.5 Bcfe and produced 5.0 Bcfe during the year ended December 31,
+2009, resulting in a net gain of 44.5 Bcfe. The Company added 50.4 Bcfe in proved oil and natural gas reserves as a result of extensions and discoveries during the year, almost all of which was attributable to drilling operations in the Haynesville
+shale play in northwest Louisiana. The Company’s oil and natural gas reserves decreased by 0.9 Bcfe during the year as a result of revisions to previous estimates, representing the net impact of small changes in prior estimates of proved
+reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to 26.0 Bcfe at December 31, 2009 from 20.0 Bcfe at December 31, 2008, primarily due to proved developed reserves added as a
+result of drilling operations in the Haynesville shale play. At December 31, 2009, the Company’s proved reserves were made up of approximately 99% natural gas and 1% oil. 
+F-45
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
+Relating to Proved Oil and Natural Gas Reserves 
+The standardized measure of discounted future net cash flows relating
+to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among
+other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps
+different discount rates. 
+As noted previously, for the period January through December 2011, average oil and natural gas
+prices were $92.71 per barrel and $4.118 per MMBtu (million British thermal units), respectively. For the period January through December 2010, average oil and natural gas prices were $75.96 per barrel and $4.376 per MMBtu, respectively. For the
+period January through December 2009, average oil and natural gas prices were $57.65 per barrel and $3.866 per MMBtu, respectively. 
+Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation costs, gravity and energy content, and regional price differentials, to
+year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. 
+Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and
+natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes
+were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. 
+The
+following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves (in thousands) for the years ended December 31, 2011, 2010 and 2009. 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Future cash inflows 
+$ 
+924,796 
+$ 
+470,386 
+$ 
+219,410 
+Future production costs 
+(194,538 
+) 
+(107,183 
+) 
+(55,513 
+) 
+Future development costs 
+(235,469 
+) 
+(107,277 
+) 
+(35,788 
+) 
+Future income tax expense 
+(83,840 
+) 
+(35,352 
+) 
+(15,805 
+) 
+Future net cash flows 
+410,949 
+220,574 
+112,304 
+10% annual discount for estimated timing of cash flows 
+(195,476 
+) 
+(109,497 
+) 
+(47,243 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+215,473 
+$ 
+111,077 
+$ 
+65,061 
+F-46
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 16 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+The following table summarizes the changes in the standardized measure of discounted
+future net cash flows relating to proved oil and natural gas reserves (in thousands) for the years ended December 31, 2011, 2010 and 2009. 
+Year ended December 31, 
+2011 
+2010 
+2009 
+Balance, beginning of period 
+$ 
+111,077 
+$ 
+65,061 
+$ 
+43,254 
+Net change in sales and transfer prices and in production (lifting) costs related to future production 
+53,903 
+7,632 
+(10,433 
+) 
+Changes in estimated future development costs 
+(64,958 
+) 
+(36,821 
+) 
+(17,502 
+) 
+Sales and transfers of oil and gas produced during the period 
+(53,478 
+) 
+(26,776 
+) 
+(13,236 
+) 
+Net change due to extensions and discoveries 
+182,282 
+94,265 
+70,361 
+Net change due to revisions in estimates of reserves quantities 
+(653 
+) 
+1,676 
+(1,232 
+) 
+Previously estimated development costs incurred during the period 
+1,023 
+7,125 
+(590 
+) 
+Accretion of discount 
+11,987 
+7,036 
+4,317 
+Other 
+(1,335 
+) 
+1,035 
+(3,068 
+) 
+Net change in income taxes 
+(24,375 
+) 
+(9,156 
+) 
+(6,810 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+215,473 
+$ 
+111,077 
+$ 
+65,061 
+NOTE 17 — SUBSEQUENT EVENTS 
+On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the initial public offering of its common stock (the “Initial Public
+Offering”). The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC;
+Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc.; and Comerica Securities, Inc. On
+February 2, 2012, shares of the Company’s common stock began trading on the New York Stock Exchange under the symbol “MTDR” at an initial offering price of $12.00 per share. 
+Pursuant to its Prospectus dated February 1, 2012, the Company and the selling shareholders offered 13,333,334 shares of the
+Company’s common stock for sale. The Company offered 11,666,667 shares of its common stock, and the selling shareholders offered 1,666,667 shares. On February 7, 2012, the Company closed the Initial Public Offering and issued 11,666,667
+shares of its common stock pursuant to the Initial Public Offering. 
+The Company and the selling shareholders granted the
+underwriters the right to purchase up to an additional 2,000,000 shares of the Company’s common stock at the initial offering price of $12.00 per share, less the underwriters’ discounts and commissions, for a period of 30 days following
+the Initial Public Offering to cover over-allotments, with the Company offering 700,000 shares and the selling shareholders offering 1,300,000. On March 2, 2012, the underwriters exercised their option to purchase an additional
+F-47
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 17 — SUBSEQUENT EVENTS — Continued 
+1,550,000 shares, including the purchase of 542,500 shares from the Company and the purchase of 1,007,500 shares from the selling shareholders. On March 7, 2012, the Company closed this
+transaction and issued 542,500 shares of its common stock pursuant to the underwriters’ exercise of the over-allotment. 
+Pursuant to the Initial Public Offering and the over-allotment, the Company issued a total of 12,209,167 shares of its common stock at
+$12.00 per share and received estimated net proceeds of approximately $133,600,000 after deducting the underwriters’ discounts and commissions and the estimated legal, accounting and other fees associated with the offering. The Company did not
+receive any proceeds from the sale of shares of its common stock by the selling shareholders. On February 8, 2012, the Company used the net proceeds of the offering to repay the $123,000,000 in borrowings then outstanding under its Credit Agreement
+in full. The Company used the remaining net proceeds of the offering to fund a portion of its 2012 capital expenditures. 
+Concurrent with the completion of the Initial Public Offering, all 1,030,700 shares of the Company’s Class B common stock were
+converted to Class A common stock on a one-for-one basis. In addition, in February 2012, the Company issued an additional 295,500 shares of its Class A common stock pursuant to the exercise of stock options and received net proceeds of
+$2,659,500. The Class A common stock is now referred to as the common stock. 
+Effective February 1, 2012, the
+Company granted an employee the option to purchase 150,000 shares of its common stock at an exercise price of $12.00 per share. These shares vest over approximately a three-year period, with 50,000 shares being fully vested on December 31, 2012
+and an incremental 50,000 shares being vested on each of December 31, 2013 and 2014. The option expires on January 31, 2022. 
+Following the repayment of the outstanding debt under its Credit Agreement, the Company’s borrowing base was reduced to $100,000,000. On February 28, 2012, the borrowing base under the
+Company’s Credit Agreement was increased to $125,000,000 pursuant to a special borrowing base redetermination made by the lenders at the Company’s request. 
+In January 2012, the Company borrowed $10,000,000 under its Credit Agreement, bringing its then-outstanding borrowings to a total of $123,000,000. These outstanding borrowings were repaid in full on
+February 8, 2012. On March 19, 2012, the Company borrowed $15,000,000 under its Credit Agreement. At March 30, 2012, the Company had $15,000,000 of outstanding borrowings under its Credit Agreement and $1,262,934 in letters of credit
+issued pursuant to the Credit Agreement. At March 30, 2012, all borrowings under the Credit Agreement bear interest at approximately 2.0% per annum. 
+Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan provides for a maximum of 4,000,000 shares
+of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the
+2012 Incentive Plan include employees, contractors and outside directors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors of the Company. With the adoption
+of the 2012 Incentive Plan, the 
+F-48
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 17 — SUBSEQUENT EVENTS — Continued 
+Company does not plan to make any future awards under the 2003 Stock and Incentive Plan, but the 2003 Stock and Incentive Plan will remain in place until all awards outstanding under that plan
+have been settled (see Note 8). 
+In January 2012, the Company terminated its guaranties and the associated pledge of
+certificates of deposit related to the loans of three officers of the Company under the Employee Option Exercise Loan Program (see Note 8). The Company continues to secure the loans of five employees in the aggregate amount of $266,000. 
+During the first quarter of 2012, the Company entered into several additional costless collar transactions to mitigate its risks
+associated with fluctuations in oil prices. The following table summarizes these contracts. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+Price 
+Floor 
+Price 
+Ceiling 
+(Bbls/month) 
+($/Bbl) 
+($/Bbl) 
+Oil 
+01/01/2012 - 12/31/2012 
+10,000 
+90.00 
+109.50 
+Oil 
+02/01/2012 - 06/30/2012 
+20,000 
+90.00 
+113.75 
+Oil 
+04/01/2012 - 12/31/2012 
+20,000 
+90.00 
+111.00 
+Oil 
+04/01/2012 - 03/31/2013 
+20,000 
+90.00 
+110.00 
+Oil 
+07/01/2012 - 12/31/2012 
+20,000 
+90.00 
+111.90 
+Oil 
+07/01/2012 - 12/31/2012 
+20,000 
+95.00 
+116.00 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+90.00 
+115.00 
+Oil 
+01/01/2013 - 12-31/2013 
+20,000 
+85.00 
+110.40 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+85.00 
+108.80 
+Oil 
+01/01/2013 - 06/30/2014 
+8,000 
+90.00 
+114.00 
+Oil 
+01/01/2013 - 06/30/2014 
+12,000 
+90.00 
+115.50 
+During the first quarter of 2012, the Company extended one of its drilling rig contracts in south Texas
+for an additional nine months. The Company terminated its second contract with no termination penalty and entered into a new contract for a higher performance rig with the same drilling rig contractor for a period of one year. Drilling operations
+under these two contracts began in early March 2012. Should the Company elect to terminate one or both contracts and if the drilling contractor were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work
+for one or both rigs at the same daily rate being charged to the Company prior to the end of their respective terms, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under
+these contracts were approximately $9.8 million at March 30, 2012. 
+F-49
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 18 — SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+The following table presents selected unaudited quarterly financial information for 2011. 
+December 31 
+September 30 
+June 30 
+March 31 
+2011 
+Oil and natural gas revenues 
+$ 
+14,991,038 
+$ 
+17,446,638 
+$ 
+20,863,572 
+$ 
+13,698,578 
+Realized gain on derivatives 
+2,868,720 
+1,435,340 
+952,450 
+1,849,750 
+Unrealized (loss) gain on derivatives 
+3,603,821 
+2,870,086 
+331,730 
+(1,668,115 
+) 
+Expenses 
+15,783,543 
+15,469,253 
+* 
+14,952,309 
+48,346,769 
+Other (expense) income 
+(308,999 
+) 
+(88,930 
+) 
+(88,856 
+) 
+(35,366 
+) 
+Income (loss) before income taxes 
+5,371,037 
+6,193,881 
+* 
+7,106,587 
+(34,501,922 
+) 
+Income tax provision (benefit) 
+1,430,429 
+60 
+(45,636 
+) 
+(6,906,257 
+) 
+Net income (loss) 
+$ 
+3,940,608 
+$ 
+6,193,821 
+* 
+$ 
+7,152,223 
+(27,595,665 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+0.09 
+$ 
+0.14 
+* 
+$ 
+0.17 
+$ 
+(0.65 
+) 
+Class B 
+$ 
+0.16 
+$ 
+0.21 
+* 
+$ 
+0.23 
+$ 
+(0.58 
+) 
+Diluted 
+Class A 
+$ 
+0.09 
+$ 
+0.14 
+* 
+$ 
+0.17 
+$ 
+(0.65 
+) 
+Class B 
+$ 
+0.16 
+$ 
+0.21 
+* 
+$ 
+0.23 
+$ 
+(0.58 
+) 
+* 
+Revised 
+The financial
+information presented above for the quarter ended September 30, 2011 presents an increase in the previously reported general and administrative expenses from $3,682,920 to $4,207,301, an increase in total expenses from $14,944,872 to $15,469,253, a
+decrease in operating income from $6,807,192 to $6,282,811, a decrease in income before income taxes from $6,718,262 to $6,193,881, a decrease in net income from $6,718,202 to $6,193,821 and a decrease in basic and diluted earnings per share from
+$0.15 to $0.14 and from $0.22 to $0.21 for Class A common shares and Class B common shares, respectively, to reflect an additional $524,381 in non-cash, stock-based compensation expense recorded during the quarter ended September 30, 2011. This
+adjustment resulted from the change in the accounting method used to determine the fair value of the Company’s outstanding stock options from the intrinsic value method to the fair value method. During the audit of its December 31, 2011
+financial statements, the Company discovered the need for this adjustment to effect the change in accounting method during the quarter ended September 30, 2011. This change in accounting method was previously applied in the quarter ended December
+31, 2011. The effect of this change on the previously reported financial statements for the nine months ended September 30, 2011 is an increase in general and administrative expenses from $9,394,964 to $9,919,345, an increase in total expenses from
+$78,243,950 to $78,768,331, an increase in operating loss from $20,463,921 to $20,988,302, an increase in loss before income taxes from $20,677,073 to $21,201,454, an increase in net loss from $13,725,240 to $14,249,621 and a decrease in basic and
+diluted earnings per share from $(0.33) to $(0.34) and from $(0.13) to $(0.14) for Class A common shares and Class B common shares, respectively. This adjustment to the September 30, 2011 quarterly financial information had no impact on the amounts
+reported for the full year ended December 31, 2011. 
+F-50
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009 
+NOTE 18 — SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) — Continued
+The following table presents selected unaudited quarterly financial information for
+2010. 
+December 31 
+September 30 
+June 30 
+March 31 
+2010 
+Oil and natural gas revenues 
+$ 
+8,859,464 
+$ 
+8,454,725 
+$ 
+7,537,345 
+$ 
+9,190,073 
+Realized gain on derivatives 
+2,311,380 
+1,172,040 
+1,514,400 
+301,560 
+Unrealized (loss) gain on derivatives 
+(2,673,837 
+) 
+2,540,813 
+(2,821,705 
+) 
+6,093,455 
+Expenses 
+9,852,439 
+7,980,371 
+7,855,459 
+7,030,719 
+Other (expense) income 
+(162,935 
+) 
+78,621 
+126,037 
+95,690 
+Income (loss) before income taxes 
+(1,518,367 
+) 
+4,265,828 
+(1,499,382 
+) 
+8,650,059 
+Income tax provision (benefit) 
+(522,125 
+) 
+1,584,375 
+(515,597 
+) 
+2,974,522 
+Net income (loss) 
+$ 
+(996,242 
+) 
+$ 
+2,681,453 
+$ 
+(983,785 
+) 
+$ 
+5,675,537 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.03 
+) 
+$ 
+0.07 
+$ 
+(0.03 
+) 
+$ 
+0.14 
+Class B 
+$ 
+0.04 
+$ 
+0.14 
+$ 
+0.03 
+$ 
+0.21 
+Diluted 
+Class A 
+$ 
+(0.03 
+) 
+$ 
+0.07 
+$ 
+(0.03 
+) 
+$ 
+0.14 
+Class B 
+$ 
+0.04 
+$ 
+0.14 
+$ 
+0.03 
+$ 
+0.21 
+F-51
\ No newline at end of file
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/filing_metadata.csv b/raw/filings/0001520006/2011/0001193125-12-145249/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..4cbee374673a478af289411c0128e922801f8460
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/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
+0001520006,MTDR,Matador Resources Co,10-K,2012-04-02,2011-12-31,2012-04-02T19:01:53.000Z,0001193125-12-145249,d325766d10k.htm,FORM 10-K,2456983,0,0,https://www.sec.gov/Archives/edgar/data/1520006/000119312512145249/d325766d10k.htm,https://www.sec.gov/Archives/edgar/data/1520006/000119312512145249/,2011,2011,1
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/item1.txt b/raw/filings/0001520006/2011/0001193125-12-145249/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..bfb20996716608368c856b0b977d9f940049ccce
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/item1.txt
@@ -0,0 +1,1610 @@
+Item 1. 
+Business. 
+In this
+Annual Report on Form 10-K, references to “we,” “our,” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador
+Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC Energy
+Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its
+corporate name to Matador Resources Company. 
+Unless the context otherwise requires, the term “common stock”
+refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only
+class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of
+our initial public offering. 
+For certain oil and natural gas terms used in this report, please see the “Glossary
+of Oil and Natural Gas Terms” included in this report. 
+General 
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources
+in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in
+northwest Louisiana and east Texas. We expect the majority of our near-term capital expenditures will focus primarily on increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the Eagle Ford shale play
+will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. In addition to these primary operating areas, we have acreage positions in southeast New Mexico and west Texas
+and in southwest Wyoming and adjacent areas in Utah and Idaho where we continue to identify new oil and natural gas prospects. 
+We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E. King, Co-Founder and Vice
+President, Geophysics and New Ventures. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was
+later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in
+an all cash transaction for an enterprise value of approximately $388.5 million. 
+Since our first well in 2004, we have
+drilled or participated in drilling 236 wells through December 31, 2011, including 106 Haynesville and nine Eagle Ford wells. From December 31, 2008 through December 31, 2011, we grew our estimated proved reserves from 20.0 Bcfe to
+193.2 Bcfe. At December 31, 2011, 34% of our estimated proved reserves were proved developed reserves, 12% of our estimated proved 
+3 
+Table of Contents 
+reserves were oil and 88% of our estimated proved reserves were natural gas. Our average daily production for the year ended December 31, 2011 was 42.3 MMcfe per day, including 39.8 MMcf of
+natural gas per day and 422 Bbl of oil per day as compared to an average daily production of 23.6 MMcfe per day, including 23.0 MMcf of natural gas per day and 91 Bbl of oil per day for the year ended December 31, 2010. We have achieved this
+growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses) from $1.16 per Mcfe for the year ended December 31, 2009, to $0.88 per Mcfe for the year ended
+December 31, 2011, or a decrease of approximately 24%. 
+The following table presents certain summary data for each of our
+operating areas as of and for the year ended December 31, 2011: 
+Producing 
+Wells 
+Total Identified 
+Drilling Locations (1) 
+Estimated Net Proved 
+Reserves 
+Avg. Daily 
+Production 
+(MMcfe) 
+Net Acreage 
+Gross 
+Net 
+Gross 
+Net 
+Bcfe (2) 
+% 
+Developed 
+South Texas: 
+Eagle Ford 
+28,673 
+9.0 
+7.3 
+193.0 
+153.1 
+27.9 
+37.9 
+3.3 
+Austin Chalk 
+14,849 
+– 
+– 
+16.0 
+16.0 
+– 
+– 
+– 
+Area Total (3) 
+28,673 
+9.0 
+7.3 
+209.0 
+169.1 
+27.9 
+37.9 
+3.3 
+NW Louisiana/E Texas: 
+Haynesville 
+14,527 
+106.0 
+11.6 
+524.0 
+102.9 
+150.4 
+26.4 
+32.3 
+Cotton Valley (4) 
+23,054 
+108.0 
+71.7 
+60.0 
+36.0 
+14.2 
+100.0 
+6.5 
+Area Total (5) 
+25,339 
+214.0 
+83.3 
+584.0 
+138.9 
+164.6 
+32.7 
+38.8 
+SW Wyoming, NE Utah, SE Idaho 
+135,862 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+6,658 
+13.0 
+5.7 
+– 
+– 
+0.7 
+100.0 
+0.2 
+Total 
+196,532 
+236.0 
+96.3 
+793.0 
+308.0 
+193.2 
+33.7 
+42.3 
+(1) 
+These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is
+calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At December 31, 2011, these identified drilling locations included 8 gross and 8 net locations to
+which we have assigned proved undeveloped reserves in the Eagle Ford and 102 gross and 17 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We have no proved undeveloped reserves assigned to identified drilling
+locations in the Austin Chalk or Cotton Valley at December 31, 2011. 
+(2) 
+These estimates were prepared by our engineering staff and audited by independent reservoir engineers, Netherland, Sewell & Associates, Inc.
+(3) 
+Some of the same leases cover the net acres shown for the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation.
+Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for south Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
+(4) 
+Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in
+Zavala County, Texas. 
+(5) 
+Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville formation.
+Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for northwest Louisiana/east Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
+At December 31, 2011, our properties included approximately 51,000 gross acres and 29,000 net acres in the
+Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In
+addition, portions of the acreage are also prospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to produce predominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by
+production or not burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Ford position and from November 2010 through December 2011, we completed our first seven operated wells in this area. 
+4 
+Table of Contents 
+At December 31, 2011, we have identified 193 gross locations and 153 net locations for
+potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from
+nearby wells based on available public data, drilling densities observed from other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among others. At
+December 31, 2011, we have identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additional locations
+for drilling. At December 31, 2011, these identified potential future drilling locations in the Eagle Ford shale play included 8 gross and 8 net locations to which we have assigned proved undeveloped reserves. 
+In addition, at December 31, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in
+northwest Louisiana and east Texas. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data and
+information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 5,500 of our net acres are located in what we believe is the core area of the play. We believe the core area of
+the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Over 90% of our Haynesville acreage is held by production from the
+Haynesville or other formations, and we believe much of it is also prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle
+Bossier shale play. 
+At December 31, 2011, we have identified 524 gross locations and 103 net locations for potential
+future drilling in our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from our producing
+Haynesville wells and other nearby wells based on available public data, drilling densities observed from other operators including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established
+by regulatory authorities and surface conditions, among others. Of the 524 gross locations identified for future drilling, 449 of these locations (52 net locations) have been identified within the 5,500 net acres that we believe are located in the
+core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2011, these identified potential future
+drilling locations included 102 gross and 17 net locations in the Haynesville shale play to which we have assigned proved undeveloped reserves. 
+We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utah and Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gas
+shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September
+2011 and completed drilling and coring operations on this well in November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the well logs and awaiting results from various core analysis tests. In
+addition, we have leasehold interests in the Delaware and Midland Basins in southeast New Mexico and west Texas where we are developing new oil and natural gas prospects. 
+We are active both as an operator and as a co-working interest owner with larger industry participants including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and
+others. Of the 236 gross wells we have drilled or participated in drilling, we drilled approximately 40% of 
+5 
+Table of Contents 
+these wells as the operator, although our working interest is small in many of the non-operated wells, particularly in the Haynesville shale. At December 31, 2011, we were the operator for
+approximately 85% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in that core area is operated by a
+subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in southwest Wyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in southeast New Mexico and west Texas. 
+We are a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal Dutch Shell plc and several
+other companies in the Haynesville shale and with EOG Resources, Inc. in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation governing the Haynesville operations underlying our
+Elm Grove/Caspiana properties in southern Caddo Parish, Louisiana and a joint operating agreement with EOG Resources, Inc. governing all operations on our joint acreage in Atascosa County, Texas. We have not entered into a joint operating agreement
+with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our working interest is small, we do not always enter into formal operating agreements with the
+operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices. 
+Where we do have joint operating agreements with affiliates of Chesapeake Energy Corporation and EOG Resources, Inc., these agreements call for significant penalties should we elect not to participate in
+the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s
+future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have
+the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose. 
+While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to
+maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations. We review
+these locations with Netherland, Sewell & Associates, Inc., our independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves.
+6 
+Table of Contents 
+The following table presents our 2012 anticipated capital expenditure budget of
+approximately $313.0 million segregated by target formation and by whether the wells are expected to be exploration or development wells. 
+2012 Anticipated Drilling 
+2012 Anticipated Capital 
+Expenditure Budget 
+Gross Wells (1) 
+Net Wells (1) 
+(in millions) (2) 
+Exploration 
+Development 
+Total 
+Exploration 
+Development 
+Total 
+Exploration 
+Development 
+Total 
+South Texas 
+Eagle Ford 
+13.0 
+15.0 
+28.0 
+11.8 
+13.8 
+25.6 
+$ 
+122.3 
+$ 
+134.9 
+$ 
+257.2 
+Austin Chalk 
+2.0 
+– 
+2.0 
+2.0 
+– 
+2.0 
+11.3 
+– 
+11.3 
+Area Total 
+15.0 
+15.0 
+30.0 
+13.8 
+13.8 
+27.6 
+133.6 
+134.9 
+268.5 
+NW Louisiana / E Texas 
+Haynesville 
+6.0 
+19.0 
+25.0 
+0.2 
+1.3 
+1.5 
+1.9 
+11.6 
+13.5 
+Cotton Valley 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+6.0 
+19.0 
+25.0 
+0.2 
+1.3 
+1.5 
+1.9 
+11.6 
+13.5 
+SW Wyoming, NE Utah, SE Idaho 
+1.0 
+– 
+1.0 
+0.4 
+– 
+0.4 
+2.5 
+– 
+2.5 
+(3) 
+SE New Mexico, West Texas 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Other 
+N/A 
+N/A 
+N/A 
+N/A 
+N/A 
+N/A 
+25.0 
+3.5 
+28.5 
+(4) 
+Total 
+22.0 
+34.0 
+56.0 
+14.4 
+15.1 
+29.5 
+$ 
+163.0 
+$ 
+150.0 
+$ 
+313.0 
+(1) 
+Includes wells we currently expect to drill and complete as operator, plus those wells in which we currently plan to participate as a non-operator in 2012.
+(2) 
+Our capital expenditure budget is based on our net working interests in the properties. 
+(3) 
+We have a carried interest for $5.0 million of the cost of this well presuming the election of our joint venture partner to participate in the drilling of this well.
+(4) 
+Includes $20.0 million to acquire additional leasehold interests primarily prospective for oil and liquids production in southeast New Mexico and west Texas.
+Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration,
+development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in
+the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale play, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production.
+While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results. Since at December 31, 2011, over 90% of our Haynesville acreage was
+held by production and approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013, we possess the financial flexibility to allocate our capital when we believe it is economical and
+justified. 
+Recent Developments 
+At March 30, 2012, we had drilled an aggregate of 15 Eagle Ford horizontal wells in south Texas as operator, including 10 wells in LaSalle County, one well in Dimmit County, three wells in Karnes
+County and one well in DeWitt County. Thirteen of these wells have been completed and are producing and two of these wells are awaiting completion. At March 30, 2012, we had two contracted drilling rigs operating in the Eagle Ford play in south
+Texas: one in LaSalle County and one in Karnes County. 
+7 
+Table of Contents 
+On February 7, 2012, we completed our initial public offering of 14,883,334 shares of
+common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold by us and the selling shareholders pursuant to the partial
+exercise of the underwriters’ over-allotment option on March 7, 2012. 
+Between November 2011 and February 2012, we
+entered into various costless collars to mitigate our exposure to oil price volatility and enhance predictability of our cash flows. As of March 30, 2012, we had hedged a total of 1,180,000 Bbls of oil for 2012, 1,260,000 Bbls of oil for 2013
+and 120,000 Bbls of oil for 2014. For 2012, these collars have a weighted average price floor of $90.51 per Bbl and a weighted average price ceiling of $109.84 per Bbl. For 2013, these collars have a weighted average price floor of $87.14 per Bbl
+and a weighted average price ceiling of $110.26 per Bbl. For 2014, these collars have a weighted average price floor of $90.00 per Bbl and a weighted average price ceiling of $114.90 per Bbl. 
+In December 2011, we amended and restated our senior secured revolving credit agreement. This amendment increased the maximum facility
+amount from $150.0 million to $400.0 million. Borrowings are limited to the lesser of $400.0 million or the borrowing base, which was $125.0 million as of March 30, 2012. 
+In November and December 2011, we completed three operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H in northeastern LaSalle County, Texas. During initial flow tests on these wells,
+the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at
+approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three wells were turned to sales in late December 2011. We are the operator and have a 100% working interest in these three wells. 
+Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson
+and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the Eagle Ford play. We believe that the acreage in Wilson and Gonzales Counties and
+a portion of DeWitt County will be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. We paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the acreage
+(approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the
+operator. 
+Principal Areas of Interest 
+Our focus since inception has been the exploration for oil and natural gas in unconventional resource plays with a particular focus over the last few years in the Haynesville shale play and more recently
+in the Eagle Ford shale play. Our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance
+the risk profile of our prospects, as well as to explore for more conventional targets in addition to the unconventional resource plays. 
+At December 2011, our principal areas of interest consisted of (1) the Eagle Ford shale play in south Texas, (2) the Haynesville shale play, including the Middle Bossier shale play, as well as
+the traditional Cotton Valley and Hosston (Travis Peak) formations in northwest Louisiana and east Texas, (3) the Meade Peak shale play in southwest Wyoming and the adjacent areas of Utah and Idaho and (4) southeast New Mexico and west
+Texas, including the Delaware and Midland Basins. 
+8 
+Table of Contents 
+South Texas 
+Eagle Ford Shale and Other Formations 
+About 8% of our daily production, or
+3.3 MMcfe per day, including 331 Bbls of oil per day and 1.3 MMcf of natural gas per day, was produced from the Eagle Ford shale in south Texas for the year ended December 31, 2011. The Eagle Ford contributed approximately 78% of our daily oil
+production and about 3% of our daily natural gas production for 2011. For the month of December 2011, about 13% of our daily production, or 5.6 MMcfe per day, including 706 Bbls of oil per day and 1.3 MMcf per day, was produced from the Eagle Ford.
+During December 2011, the Eagle Ford contributed 91% of our daily oil production and about 4% of our daily natural gas production. At December 31, 2011, approximately 14% of our proved reserves, or 27.9 Bcfe, was attributable to the Eagle Ford,
+including approximately 3.6 million Bbls of oil and 6.1 Bcf of natural gas. Our Eagle Ford proved reserves at December 31, 2011 comprised approximately 96% of our proved oil reserves and approximately 4% of our proved natural gas reserves.
+The present value discounted at 10% for our proved reserves in the Eagle Ford at December 31, 2011 was $130.2 million, or about 52% of the PV-10 for our total proved reserves of $248.7 million. We anticipate that the percentage of our daily
+production and reserves attributable to the Eagle Ford shale will grow in 2012 as we intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle
+Ford play in an effort to grow the oil and liquids component of our production and reserves. 
+The Eagle Ford shale extends
+across portions of south Texas from the Mexican border into east Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale, in places transitioning to an organic, argillaceous
+lime-mudstone. It lies between the deeper Buda limestone and the shallower Austin Chalk formation. Most, if not all, of the oil found in the Austin Chalk and Buda formations is generally believed to be sourced from the Eagle Ford shale. In the
+prospective areas for the Eagle Ford shale, the interval averages 200 feet thick, is found at depths ranging from as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the play is overpressured. The Eagle Ford
+shale has a total organic carbon content of 1% to 7% that is comparable to the Haynesville shale, and is generally porous, with core-measured porosities ranging between 4% and 14%. 
+Along the entire length of the Eagle Ford trend the structural dip of the formation is consistently down to the south with relatively
+few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the formation is shallow, it is less thermally mature and therefore more oil prone,
+and as it gets deeper and becomes more thermally mature, the Eagle Ford shale is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet gas with condensate. We
+believe that approximately 85% of our Eagle Ford acreage lies within those portions of the Eagle Ford shale that are prone to produce oil or wet gas with condensate. 
+Most of the current Eagle Ford shale activity is concentrated in Atascosa, Bee, DeWitt, Dimmit, Frio, Gonzales, Karnes, LaSalle, Lavaca, Live Oak, Maverick, McMullen, Webb, Wilson and Zavala Counties in
+south Texas. The first horizontal wells drilled specifically for the Eagle Ford shale were drilled in 2008, leading to a discovery in LaSalle County. Since then, the play has expanded significantly across a large portion of south Texas. 
+Publicly available information indicates that operators are typically drilling 3,500 to 7,000 feet horizontal laterals and applying
+hydraulic fracture stimulation in multiple stages along the full length of the horizontal laterals to complete the wells and establish production. Although production rates vary across the 
+9 
+Table of Contents 
+different areas of the play, initial production rates in the oil areas have been reported as high as 1,000 to 1,500 Bbls of oil per day with varying amounts of associated natural gas. In the
+natural gas areas of the Eagle Ford play, initial production rates as high as 5.0 to 15.0 MMcfe per day have been reported with varying amounts of associated oil and liquids. 
+At December 31, 2011, our aggregate leasehold interests consisted of approximately 51,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, LaSalle,
+Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe portions of this acreage are also prospective for the Austin Chalk, Buda, Olmos and other formations, from which we expect to produce predominantly oil and liquids. In particular,
+the Austin Chalk formation, which is a naturally fractured carbonate ranging in thickness from 200 to 400 feet, has produced from several fields on or nearby portions of our acreage. Our Zavala County acreage, for example, is located within the
+historic Pearsall (Austin Chalk) field. 
+We believe that approximately 85% of our Eagle Ford acreage is prospective
+predominantly for oil and liquids. At December 31, 2011, we owned a 100% working interest in approximately 26,000 gross acres and 23,000 net acres in Dimmit, Gonzales, Karnes, LaSalle, Webb, Wilson and Zavala Counties and a 50% working interest
+in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of this acreage. We also owned an approximate 21% working interest in approximately 22,000 gross acres in Atascosa County operated by EOG Resources, Inc. At
+December 31, 2011, approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013. 
+At December 31, 2011, we had drilled and completed seven Eagle Ford wells on our operated properties. All of these wells were producing to sales, although four of these wells were initially placed on
+production in late December. At December 31, 2011, we had also participated in two Eagle Ford wells with EOG Resources, Inc. as operator, on the Atascosa County acreage. Our first operated Eagle Ford horizontal well, the JCM Jr. Minerals #1H in
+southern LaSalle County along the Edwards Reef, was completed in November 2010. First sales of oil and natural gas began from this well in late January 2011, and during December 2011, the well produced at an average daily rate of approximately 0.5
+MMcf of natural gas and 9 Bbls of condensate per day, and through December 31, 2011, had produced a total of approximately 430 MMcf of natural gas and 11,200 Bbls of condensate. Our second operated Eagle Ford horizontal well, the Martin Ranch
+#1H in northeastern LaSalle County, was completed in January 2011 and tested approximately 1,200 Bbls of oil per day during an initial flow test. First sales of oil and natural gas from this well began in late March at approximately 700 Bbls of oil
+and 350 Mcf of natural gas per day. During December 2011, the well produced at an average daily rate of approximately 330 Bbls of oil and 0.6 MMcf of natural gas per day, and through December 31, 2011, had produced a total of 117,000 Bbls of
+oil and 144 MMcf of natural gas. 
+Our third operated Eagle Ford horizontal well, the Affleck #1H, was completed in February
+2011 in eastern Dimmit County, Texas, and tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per day during an initial flow test. During December 2011, the well produced at an average daily rate of 0.8 MMcf of natural gas and 38
+Bbls of oil per day. In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H in DeWitt County, Texas. This well tested at approximately 2.7 MMcf of natural gas and 1,040 Bbls of condensate per day during an
+initial flow test. The Lewton well began producing to sales in late December 2011. 
+In November and December 2011, we
+completed three additional operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H, in northeastern LaSalle County, Texas. During initial flow tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and
+1.8 MMcf of 
+10 
+Table of Contents 
+natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6
+MMcf of natural gas per day. All three wells were turned to sales in late December 2011. 
+Between March and July 2011, we
+acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We paid approximately $31.5 million to acquire this
+acreage. We currently own a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net
+acres) in Karnes, Wilson and Gonzales Counties and are the operator. At December 31, 2011, we had drilled and completed only one well on this acreage, the Lewton #1H in DeWitt County. 
+We will pay 100% of the costs to drill and complete the first six wells drilled on the acreage in DeWitt County. We will have an 85%
+working interest in these six wells until we have recovered all of our acquisition, drilling and completion costs from each well, at which time Orca’s working interest will increase to 50%. When the cumulative production from each of the first
+six wells reaches 500,000 BOE, on a well-by-well basis, then Orca’s working interest in that well increases to 55%. If the cumulative production from each of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s
+working interest in that well will increase to 70%. Both we and Orca will own a 50% working interest in all subsequent wells drilled after the first six wells on the acreage in DeWitt County. 
+We will have a 100% working interest in the first five wells drilled on the acreage in Karnes, Wilson and Gonzales Counties. When we have
+recovered all of our acquisition, drilling and completion costs from each of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in these wells. In addition, Orca retains a one-time election for a short
+period of time after we complete these first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchase price equal to 25% of our costs to acquire the acreage in Karnes, Wilson and
+Gonzales Counties. 
+At March 30, 2012, we had drilled an aggregate of 15 Eagle Ford horizontal wells in south Texas as
+operator, including 10 wells in LaSalle County, one well in Dimmit County, three wells in Karnes County and one well in DeWitt County. Thirteen of these wells have been completed and are producing and two of these wells are awaiting completion. At
+March 30, 2012 we had two contracted drilling rigs operating in the Eagle Ford play in south Texas: one in LaSalle County and one in Karnes County. We are not currently experiencing difficulties in securing completion, and particularly hydraulic
+fracturing services, for our newly drilled wells, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and
+completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors – The Unavailability or High Cost of Drilling Rigs, Completion
+Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could
+Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+We experienced
+temporary pipeline interruptions from time to time during 2011 associated with natural gas production from our Eagle Ford wells and have been required to either shut in wells for brief periods or to flare some of the natural gas we produce. At March
+30, 2012, we were experiencing pipeline capacity limitations at our Martin Ranch lease in LaSalle County and are currently flaring a portion of the natural gas we are producing there as a result. We believe that these pipeline interruptions and
+capacity 
+11 
+Table of Contents 
+constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days.
+If we were required to shut in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors
+– The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Transportation Agreements Would
+Have a Material Adverse Effect on Our Revenue.” 
+In addition to the Eagle Ford potential on our acreage, we believe that
+approximately 24,000 gross acres and 15,000 net acres in south Texas are prospective primarily for the Austin Chalk formation, which has historically been targeted by operators in south Texas. We have not yet drilled an Austin Chalk well, and
+although we believe that other prospective well locations exist on this acreage, we have only included 16 gross and net well locations in our total identified drilling locations at December 31, 2011. 
+Northwest Louisiana and East Texas 
+At December 31, 2011, most of our production and proved reserves was attributable to our acreage in northwest Louisiana and east Texas. For the year ended December 31, 2011, about 76% of our
+daily production, or 32.3 MMcfe per day, was produced from the Haynesville shale, with another 15%, or 6.5 MMcfe per day, produced from the Cotton Valley and other shallower formations in this area. At December 31, 2011, approximately
+78% of our proved reserves, or 150.4 Bcfe, were attributable to the Haynesville shale underlying this acreage with another 7% of our proved reserves, or 14.2 Bcfe, associated with the Cotton Valley and shallower formations. In addition, we are
+evaluating the Bossier shale play which is generally encountered above the Haynesville shale and below the Cotton Valley formation. 
+We operate all of our Cotton Valley and shallower production under this acreage, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the
+Haynesville play. Of the approximately 5,500 net acres that we consider to be in the core area of the Haynesville play, we operate about 22% of that acreage. 
+In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at
+$2.13 per MMBtu. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improved substantially from these levels or unless the costs to drill and complete these
+wells were also to decline substantially from their recent levels. See “Risk Factors – Our Identified Drilling Locations Are Scheduled Out Over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the
+Occurrence or Timing of Their Drilling.” 
+Haynesville and Middle Bossier Shales 
+The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above
+the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout northwest Louisiana and east Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and
+Shelby Counties in Texas. The Haynesville shale has a typical thickness ranging from 100 to 300 feet. Total organic carbon ranges from 0.5% to 5.0%, with core-measured porosities from 3% to 15%. The Haynesville shale produces primarily dry natural
+gas with almost no associated liquids. 
+12 
+Table of Contents 
+The oil and natural gas industry has focused significant attention on the Haynesville shale
+play over the last several years. Operators are typically drilling 4,500 to 5,000 feet horizontal laterals and applying hydraulic fracture stimulation in multiple stages along the entire length of the horizontal laterals to complete the wells and
+establish production. Although initial production rates vary widely across the play, initial production rates as high as 20.0 to 25.0 MMcf per day of natural gas have been reported by operators from horizontal wells drilled and completed in the
+Haynesville shale. 
+The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle
+Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics to the deeper
+Haynesville shale. Typically, the Middle Bossier shale is found at depths ranging from 500 to 800 feet shallower than the Haynesville shale, has a typical thickness ranging from 150 to 300 feet, has core-measured porosities ranging between 5% and
+14%, and total organic carbon values between 0.5% and 4%. Although there is some overlap between the Bossier and Haynesville shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation.
+At December 31, 2011, we had leasehold and mineral interests in approximately 23,000 gross and 15,000 net acres prospective
+for the Haynesville shale. Portions of our acreage are located in Caddo, DeSoto, Bossier and Red River Parishes, Louisiana and in Harrison County, Texas. This acreage includes approximately 5,500 net acres in what we believe is the core area of the
+play. Over 90% of our Haynesville acreage is held by production and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that
+approximately 1,700 net acres are prospective for the Middle Bossier play as well. We have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations exist on this acreage, we have not yet included any
+Middle Bossier locations in our identified drilling locations at December 31, 2011. 
+Within the 5,500 net acres that we
+believe to be in the core area of the Haynesville shale play, we are the operator in two sections where we have working interests of 95% and 100% in all wells to be drilled. In October 2010, as operator, we drilled and completed our L.A. Wildlife H
+#1 horizontal Haynesville well in the section in which we have a 95% working interest and on December 31, 2010 first sales of natural gas began from this well. During December 2011, the well produced at an average daily rate of approximately
+8.7 MMcf of natural gas per day, and through December 31, 2011, had produced a total of approximately 3.4 Bcf of natural gas. In March 2011, we completed our operated Williams 17 H #1 horizontal Haynesville well on the second section where we
+have a 100% working interest. During December 2011, this well produced at an average daily rate of 3.9 MMcf of natural gas per day and, through December 31, 2011, had produced approximately 1.8 Bcf of natural gas. We began producing both of
+these wells at a constrained rate of about 10.0 MMcf of natural gas per day. We have identified 12 gross and approximately 12 net potential additional Haynesville locations that we may drill and operate in the future in these two sections.
+The remainder of our acreage in the core area of the Haynesville shale play, about 4,300 net acres, is operated by other
+companies. Just over half of our non-operated Haynesville acreage in this area of the play results from a transaction with a subsidiary of Chesapeake in July 2008. The remainder of our non-operated Haynesville acreage is attributable to leasehold
+interests that we hold in approximately 87 sections in Caddo, DeSoto, Bossier and Red River Parishes. Our working interests in the Haynesville wells in these sections range from less than 1% to more than 30%. At December 31, 2011, our
+production from these non-operated Haynesville wells averaged approximately 22 MMcfe per day. 
+13 
+Table of Contents 
+We do not plan to drill any operated Haynesville wells in 2012, but we have budgeted capital
+expenditures of approximately $13 million for our anticipated participation in approximately 25 gross (1.5 net) non-operated wells that may be drilled in order to hold expiring acreage or that may be proposed in multi-well development programs to
+evaluate optimal well spacing. 
+Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations 
+Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in northwest
+Louisiana and east Texas were attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in northwest Louisiana and east
+Texas. 
+All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in northwest Louisiana,
+approximately 10,000 gross and net acres at December 31, 2011, is held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to
+discovery of the Haynesville shale. The Cotton Valley formation is a low permeability gas sand that ranges in thickness from 200 to 300 feet and has porosities ranging from 6% to 10%. 
+In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. in our Elm Grove/Caspiana properties,
+in DeSoto Parish and commenced sales of natural gas from this well. Prior to this time, we had only drilled and completed vertical Cotton Valley and Hosston wells on these properties. During December 2011, this well produced at an average daily rate
+of approximately 1.6 MMcf of natural gas per day and through December 31, 2011, had produced a total of approximately 950 MMcf of natural gas. We are the operator and have a 100% working interest in this well. We have identified 60 gross and 36
+net additional drilling locations for future Cotton Valley horizontal wells in our Elm Grove/Caspiana properties. We do not plan to drill any of these locations in 2012. As all of this acreage is held by existing production, we expect to allocate
+the majority of our near-term capital expenditures primarily to exploration and development of our Eagle Ford shale acreage in south Texas. 
+We also continue to hold the shallow rights by existing production or by leases that are still in their primary terms in our central and southwest Pine Island, Longwood, Woodlawn and other prospect areas
+in northwest Louisiana and east Texas. At December 31, 2011, we held an estimated 11,500 net leasehold and mineral acres by existing production in these areas. 
+Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale 
+The Meade Peak shale is an organic-rich source rock that has sourced much of the oil and natural gas in conventional reservoirs in the western Wyoming and eastern Utah area. The Meade Peak shale has an
+observed shale thickness of 70 to 350 feet, total organic carbon of 3% to 7% and vitrinite reflectance values ranging from 1.8% to 2.7%. The Meade Peak shale is encountered at drill depths of 3,000 to 14,000 feet, with the majority of our acreage in
+the depth range of 3,000 to 10,000 feet. The shale has been penetrated by over 100 wells in the area, most of which have natural gas shows. Seismic and subsurface data show distinct, stacked thrust plates with areas of sediment prospective for
+natural gas. 
+At December 31, 2011, we had assembled approximately 144,000 gross, or approximately 136,000 net, acres in
+southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploratory prospect targeting the Meade Peak shale. The majority of this acreage, with lease terms of five to ten years, has been acquired by us within the past
+four to five years, and we are the operator of this prospect. 
+14 
+Table of Contents 
+We believe there have been no previous attempts to drill horizontally or to hydraulically
+fracture the Meade Peak shale in this area. Our focus to date has been to confirm the structure of the Meade Peak shale, understand its characteristics and evaluate its potential. We have gathered well log data in the area and studied the
+petrophysical characteristics. In addition, we have purchased 2-D seismic data and have worked with a structural geologist that has experience in the immediate area to better understand the area’s tectonic history. 
+We have entered into a participation and joint operating agreement with other parties covering the initial exploration efforts and, if
+successful, the future development of this acreage. We began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feet above
+the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations on this well in
+November 2011. At December 31, 2011, this well had not been completed, as we were still evaluating the well logs and awaiting results from various core analysis tests. 
+Approximately 102,000 gross, or approximately 93,000 net, acres in this prospect are scheduled to expire at various times during 2012. Although we plan to seek extensions on some of this acreage, certain
+leases, particularly those taken on state lands, do not offer the opportunity for automatic extension, and we will be required to obtain new leases on these lands should we desire and be able to do so. We expect that a significant portion of the
+93,000 net acres will be allowed to expire during 2012, while we and our partners continue to evaluate the results from our initial test well and plan for its completion and further testing. We have no production and no proved reserves attributable
+to this acreage at December 31, 2011. 
+Southeast New Mexico and West Texas — Delaware and Midland Basins
+The Delaware and Midland Basins are mature exploration and production provinces with extensive developments in a wide
+variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in these basins has focused on relatively conventional reservoir targets, but we believe the combination of advanced
+formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of these basins. 
+One example of such an opportunity appears to be the so-called “Wolf-Bone” play of the Delaware Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp
+formations span several thousand feet of stacked shales, sandstones, limestones and dolomites representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural
+gas have been produced primarily from conventional sandstone and carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones
+have been recognized by a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a result, several large industry players are expanding positions and conducting drilling programs throughout Lea and
+Eddy Counties in southeast New Mexico and Loving, Reeves and Ward Counties in west Texas. 
+Although the Delaware and Midland
+Basins have not been a primary focus of our recent operations or exploration efforts, we were developing new oil and natural gas prospects in these basins at December 31, 2011. Most notably, we have identified potential drilling opportunities
+on our acreage, particularly in southeast New Mexico, near old vertical wells, some of which have produced up to 1,000,000 BOE from the Wolfcamp formation and up to 500,000 BOE from the Bone Spring formation. These wells suggest a hydrocarbon-rich
+environment in the area of our acreage, and after completing our internal geologic studies, we may determine to drill a Wolfcamp or Bone Spring vertical well or to drill a horizontal well to test these formations on our acreage.
+15 
+Table of Contents 
+At December 31, 2011, we had not included any potential drilling locations on our acreage in our total identified drilling locations, and we had not budgeted any capital expenditures to
+drill wells in southeast New Mexico or west Texas during 2012. We have budgeted $20.0 million of our anticipated 2012 capital expenditures to acquire additional leasehold interests primarily prospective for oil and liquids production in areas of
+southeast New Mexico and west Texas where we are developing new prospects. Although we do have existing leasehold interests in this area of approximately 11,000 gross and approximately 7,000 net acres at December 31, 2011, we believe
+approximately 8,000 gross and 4,000 net acres are no longer prospective, and we plan to let them expire without drilling. 
+Operating
+Summary 
+The following table sets forth certain unaudited production data for the years ended December 31, 2011, 2010
+and 2009: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Unaudited Production Data 
+Net Production Volumes: 
+Oil (MBbls) 
+154 
+33 
+30 
+Natural gas (Bcf) 
+14.5 
+8.4 
+4.8 
+Total natural gas equivalents
+(Bcfe) (1) 
+15.4 
+8.6 
+5.0 
+Average daily production (MMcfe/d) (1) 
+42.3 
+23.6 
+13.7 
+Average Sales Prices: 
+Oil (per Bbl) 
+$ 
+93.80 
+$ 
+76.39 
+$ 
+57.72 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+4.11 
+$ 
+4.38 
+$ 
+5.17 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+3.62 
+$ 
+3.75 
+$ 
+3.59 
+Operating Expenses (per Mcfe): 
+Production taxes and marketing 
+$ 
+0.41 
+$ 
+0.23 
+$ 
+0.22 
+Lease operating 
+$ 
+0.47 
+$ 
+0.61 
+$ 
+0.94 
+Depletion, depreciation and amortization 
+$ 
+2.06 
+$ 
+1.81 
+$ 
+2.15 
+General and administrative 
+$ 
+0.87 
+$ 
+1.13 
+$ 
+1.42 
+(1) 
+Estimated using a conversion ratio of one Bbl per six Mcf. 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2010 from our primary operating areas: 
+Average Net Daily Production 
+Total Net 
+Production 
+(MMcfe) 
+Percentage of 
+Total Net 
+Production 
+Gas 
+(Mcf/d) 
+Oil 
+(Bbls/d) 
+Gas 
+Equivalent 
+(Mcfe/d) 
+South Texas: 
+Eagle Ford 
+4 
+19 
+119 
+43 
+0.5 
+% 
+Austin Chalk (1) 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+4 
+19 
+119 
+43 
+0.5 
+NW Louisiana/E Texas: 
+Haynesville 
+17,127 
+1 
+17,132 
+6,253 
+72.7 
+Cotton Valley (2) 
+5,840 
+40 
+6,074 
+2,218 
+25.8 
+Area Total 
+22,967 
+41 
+23,206 
+8,471 
+98.5 
+SW Wyoming, NE Utah, SE Idaho (1) 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+43 
+31 
+228 
+83 
+1.0 
+Total 
+23,014 
+91 
+23,553 
+8,597 
+100.0 
+% 
+(1) 
+We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation
+in south Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing
+from the San Miguel formation in Zavala County, Texas. 
+16 
+Table of Contents 
+The following table sets forth information regarding our average net daily production and
+total production for the year ended December 31, 2011 from our primary operating areas: 
+Average Net Daily Production 
+Total Net 
+Production 
+(MMcfe) 
+Percentage of 
+Total Net 
+Production 
+Gas 
+(Mcf/d) 
+Oil 
+(Bbls/d) 
+Gas 
+Equivalent 
+(Mcfe/d) 
+South Texas: 
+Eagle Ford 
+1,298 
+331 
+3,286 
+1,200 
+7.8 
+% 
+Austin Chalk (1) 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+1,298 
+331 
+3,286 
+1,200 
+7.8 
+NW Louisiana/E Texas: 
+Haynesville 
+32,319 
+– 
+32,319 
+11,797 
+76.4 
+Cotton Valley (2) 
+6,084 
+64 
+6,465 
+2,360 
+15.3 
+Area Total 
+38,403 
+64 
+38,784 
+14,157 
+91.7 
+SW Wyoming, NE Utah, SE Idaho (1) 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+59 
+27 
+221 
+81 
+0.5 
+Total 
+39,760 
+422 
+42,291 
+15,438 
+100.0 
+% 
+(1) 
+We currently have no production from our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk formation
+in south Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing
+from the San Miguel formation in Zavala County, Texas. 
+Our total production of 15.4 Bcfe for the year ended
+December 31, 2011 was an increase of 79% over our total production of 8.6 Bcfe for the year ended December 31, 2010. This increased production was primarily due to drilling operations in the Haynesville shale, but a portion of the increase
+also reflects production due to our initial drilling operations in the Eagle Ford shale. Our total production of 8.6 Bcfe for the year ended December 31, 2010 was an increase of 72% over our total production of 5.0 Bcfe for the year ended
+December 31, 2009. Most of this increase was attributable to our drilling operations in the Haynesville shale play. In addition, as a result of production from new wells that were completed in 2011, our daily production for the year ended
+December 31, 2011 averaged approximately 42.3 MMcfe per day, as compared to 23.6 MMcfe per day for the year ended December 31, 2010. Our daily oil production for the year ended December 31, 2011 averaged 422 Bbls per day, an
+approximate five-fold increase from 91 Bbls per day for the year ended December 31, 2010. 
+17 
+Table of Contents 
+Producing Wells 
+The following table sets forth information relating to producing wells at December 31, 2011. Wells are classified as oil or natural gas according to their predominant production stream. We do not
+have any currently active dual completions. We have an approximate average working interest of 92% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 44%, and average
+approximately 9%. In the table below, gross wells are the total number of producing wells in which we own a working interest, and net wells represent the total of our fractional working interests owned in the gross wells. 
+Natural Gas Wells 
+Oil Wells 
+Total Wells 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+2.0 
+2.0 
+7.0 
+5.3 
+9.0 
+7.3 
+Austin Chalk (1) 
+– 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+2.0 
+2.0 
+7.0 
+5.3 
+9.0 
+7.3 
+NW Louisiana/E Texas: 
+Haynesville 
+106.0 
+11.6 
+– 
+– 
+106.0 
+11.6 
+Cotton Valley (2) 
+106.0 
+69.7 
+2.0 
+2.0 
+108.0 
+71.7 
+Area Total 
+212.0 
+81.3 
+2.0 
+2.0 
+214.0 
+83.3 
+SW Wyoming, NE Utah, SE Idaho (1) 
+– 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+1.0 
+0.6 
+12.0 
+5.1 
+13.0 
+5.7 
+Total 
+215.0 
+83.9 
+21.0 
+12.4 
+236.0 
+96.3 
+(1) 
+We currently have no producing wells on our acreage in southwest Wyoming and adjacent areas of Utah and Idaho and insignificant production from the Austin Chalk
+formation in south Texas. 
+(2) 
+Includes shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San Miguel formation in
+Zavala County, Texas. 
+18 
+Table of Contents 
+Estimated Proved Reserves 
+The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2011, 2010 and 2009. The reserves estimates were based on evaluations prepared by our engineering
+staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves
+reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be
+attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which
+geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total estimated proved reserves are estimated using a conversion
+ratio of one Bbl per six Mcf. 
+At
+December 31, (1) 
+2011 
+2010 
+2009 
+Estimated Proved Reserves
+Data: (2) 
+Estimated proved reserves: 
+Oil (MBbls) 
+3,794 
+152 
+103 
+Natural Gas (Bcf) 
+170.4 
+127.4 
+63.9 
+Total (Bcfe) 
+193.2 
+128.3 
+64.5 
+Estimated proved developed reserves: 
+Oil (MBbls) 
+1,419 
+152 
+103 
+Natural Gas (Bcf) 
+56.5 
+43.1 
+25.4 
+Total (Bcfe) 
+65.1 
+44.1 
+26.0 
+Percent developed 
+33.7 
+% 
+34.3 
+% 
+40.3 
+% 
+Estimated proved undeveloped reserves: 
+Oil (MBbls) 
+2,375 
+– 
+– 
+Natural Gas (Bcf) 
+113.9 
+84.3 
+38.6 
+Total (Bcfe) 
+128.1 
+84.3 
+38.6 
+PV-10 (3) (in millions) 
+$ 
+248.7 
+$ 
+119.9 
+$ 
+70.4 
+Standardized Measure (4) (in millions) 
+$ 
+215.5 
+$ 
+111.1 
+$ 
+65.1 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative
+transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2009 were $57.65 per Bbl for oil and $3.866 per MMBtu for
+natural gas, for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for natural gas, and for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas. These
+prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. 
+(3) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2009, 2010 and 2011 may be reconciled to our Standardized Measure
+of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2009, 2010 and 2011 were, in millions, $5.3, $8.8
+and $33.2, respectively. 
+(4) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+19 
+Table of Contents 
+Our total proved oil and natural gas reserves increased from 128.3 Bcfe at
+December 31, 2010 to 193.2 Bcfe at December 31, 2011. Most of this increase is attributable to proved reserves added due to our drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved oil
+reserves specifically from 152 MBbls at December 31, 2010 to 3,794 MBbls at December 31, 2011 is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved reserves at
+December 31, 2011 were made up of approximately 88% natural gas and 12% oil. Our proved developed reserves increased from 44.1 Bcfe at December 31, 2010 to 65.1 Bcfe at December 31, 2011 due primarily to proved developed reserves
+added as a result of drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in proved developed oil reserves specifically from 152 MBbls at December 31, 2010 to 1,419 MBbls at December 31, 2011 is attributable
+to proved developed oil reserves added due to our drilling operations in the Eagle Ford shale play. Our proved undeveloped reserves increased from 84.3 Bcfe at December 31, 2010 to 128.1 Bcfe at December 31, 2011 due primarily to our
+drilling operations in the Eagle Ford and Haynesville shale plays. The increase in our proved undeveloped oil reserves specifically from zero to 2,375 MBbls at December 31, 2011 is attributable to our drilling operations in the Eagle Ford shale
+play. The net increase of 43.8 Bcfe in our proved undeveloped reserves from December 31, 2010 to December 31, 2011 is composed of (1) additions of 49.0 Bcfe to proved undeveloped reserves identified through drilling operations, less
+(2) the conversion of 3.4 Bcfe of proved undeveloped reserves to proved developed reserves, less (3) the downward revisions of proved undeveloped reserves by 1.8 Bcfe in the period. During this period, we recorded no changes to proved
+undeveloped reserves as a result of the acquisition or divestment of reserves. At December 31, 2011, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking. 
+The following table sets forth additional summary information by operating area with respect to our estimated proved reserves at
+December 31, 2011: 
+Net Proved
+Reserves (1) 
+PV-10 (2) 
+Standardized 
+Measure (3) 
+Oil 
+Gas 
+Gas 
+Equivalent 
+(MBbls) 
+(Bcf) 
+(Bcfe) 
+(in millions) 
+(in millions) 
+South Texas: 
+Eagle Ford 
+3,636 
+6.1 
+27.9 
+$ 
+130.2 
+$ 
+112.8 
+Austin Chalk (4) 
+– 
+– 
+– 
+– 
+– 
+Area Total 
+3,636 
+6.1 
+27.9 
+130.2 
+112.8 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+150.4 
+150.4 
+96.6 
+83.7 
+Cotton Valley (5) 
+61 
+13.8 
+14.2 
+19.5 
+16.9 
+Area Total 
+61 
+164.2 
+164.6 
+116.1 
+100.6 
+SW Wyoming, NE Utah, SE Idaho (4) 
+– 
+– 
+– 
+– 
+– 
+SE New Mexico, West Texas 
+97 
+0.1 
+0.7 
+2.4 
+2.1 
+Total 
+3,794 
+170.4 
+193.2 
+$ 
+248.7 
+$ 
+215.5 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2011 may be reconciled to our Standardized Measure of discounted
+future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2011 were approximately $33.2 million. 
+(3) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+20 
+Table of Contents 
+(4) 
+At December 31, 2011, we had no proved reserves attributable to the Austin Chalk formation in south Texas or to our acreage in southwest Wyoming and adjacent areas
+of Utah and Idaho. 
+(5) 
+Includes Cotton Valley and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas and two wells producing from the San
+Miguel formation in Zavala County, Texas. 
+Technology Used to Establish Reserves 
+Under current SEC rules, proved reserves are those quantities of oil and natural gas, 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 economic conditions, operating methods and government regulations. The term “reasonable
+certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven 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 have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. 
+In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been
+demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and
+available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production
+history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods.
+Internal Control Over Reserves Estimation Process 
+We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the
+data used in our reserves estimation process. Our Reserves Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over 15 years of industry experience. Our Reserves Manager received his Ph.D. degree in
+Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a certificate of completion in a prescribed course of study in Reserves and Evaluation from Texas A&M University in May
+2009. Our Vice President – Reservoir Engineering is responsible for reviewing and approving our reserves estimates and has over 30 years of industry experience. Following the preparation of our reserves estimates, we had our reserves estimates
+audited for their reasonableness by Netherland, Sewell & Associates, Inc., our independent petroleum engineers. The Engineering Committee of our board of directors reviews the reserves report and our reserves estimation process, and the
+results of the reserves report and the independent audit of our reserves are reviewed by members of our board of directors, including members of our Audit Committee. 
+21 
+Table of Contents 
+Acreage Summary 
+The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2011. At that date, only about 12% of our total acreage had been
+developed, although these percentages are much higher in northwest Louisiana and east Texas. 
+Developed Acres 
+Undeveloped Acres 
+Total Acres 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+2,514 
+2,130 
+48,225 
+26,543 
+50,739 
+28,673 
+Austin Chalk 
+– 
+– 
+24,473 
+14,849 
+24,473 
+14,849 
+Area Total (1) 
+2,514 
+2,130 
+48,225 
+26,543 
+50,739 
+28,673 
+NW Louisiana/E Texas: 
+Haynesville 
+18,713 
+10,599 
+4,158 
+3,928 
+22,871 
+14,527 
+Cotton Valley (2) 
+20,942 
+17,846 
+5,327 
+5,208 
+26,269 
+23,054 
+Area Total (3) 
+23,033 
+19,691 
+5,866 
+5,648 
+28,899 
+25,339 
+SW Wyoming, NE Utah, SE Idaho 
+– 
+– 
+144,368 
+135,862 
+144,368 
+135,862 
+SE New Mexico, West Texas 
+1,160 
+1,038 
+9,554 
+5,620 
+10,714 
+6,658 
+Total 
+26,707 
+22,859 
+208,013 
+173,673 
+234,720 
+196,532 
+(1) 
+Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+(2) 
+Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas. 
+(3) 
+Some of the same leases cover the net acres shown for the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+Undeveloped Acreage Expiration
+The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2011 that
+will expire prior to December 31, 2013 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates or unless the existing leases are renewed prior to expiration: 
+Acres 
+Expiring 2012 
+Acres 
+Expiring 2013 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+15,044 
+4,349 
+12,165 
+7,149 
+Austin Chalk 
+5,731 
+1,133 
+3,851 
+2,646 
+Area Total (1) 
+15,044 
+4,349 
+12,165 
+7,149 
+NW Louisiana/E Texas 
+Haynesville 
+644 
+395 
+40 
+5 
+Cotton Valley 
+750 
+401 
+40 
+5 
+Area Total (2) 
+750 
+401 
+40 
+5 
+SW Wyoming, NE Utah, SE Idaho 
+101,905 
+93,356 
+8,461 
+8,301 
+SE New Mexico, West Texas 
+1,712 
+79 
+8,454 
+2,715 
+Total 
+119,411 
+98,185 
+29,120 
+18,170 
+(1) 
+Some of the same leases cover the net acres shown for the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+(2) 
+Some of the same leases cover the net acres shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than the Haynesville shale.
+Consequently, the total acreage will not equal the sum of the acreage by operating area. 
+22 
+Table of Contents 
+Many of the leases comprising the acreage set forth in the table above will expire at the
+end of their respective primary terms unless production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. We also have options to
+extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there
+may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. Our leases are mainly fee leases with three to five years of primary
+term. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. 
+Drilling Results 
+The following table summarizes our drilling activity for
+the three years ended December 31, 2011, 2010 and 2009: 
+Year Ended December 31, 
+2011 
+2010 
+2009 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development Wells 
+Productive 
+30 
+0.6 
+5 
+1.7 
+3 
+1.3 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Exploration Wells 
+Productive 
+30 
+10.2 
+36 
+3.4 
+15 
+6.0 
+Dry 
+– 
+– 
+– 
+– 
+2 
+2.0 
+Total Wells 
+Productive 
+60 
+10.8 
+41 
+5.1 
+18 
+7.3 
+Dry 
+– 
+– 
+– 
+– 
+2 
+2.0 
+Marketing 
+Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting
+price. As a consequence, the prices we receive for crude oil and liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil are also deducted
+from the price received for crude oil. 
+Our natural gas is sold under both long-term and short-term natural gas purchase
+agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based
+on various pipeline indices less any associated fees. When there is an opportunity to do so, the mid-stream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are
+then paid for the extracted liquids based on a negotiated percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or based on other negotiated pricing arrangements. 
+The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the
+level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political
+conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall 
+23 
+Table of Contents 
+economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term
+disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations
+do curtail our production capabilities and ability to maintain a steady source of revenue for our company. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder
+winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to
+Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+For the year ended December 31, 2009, we had
+three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (32%), Regency Gas Services LP (25%), and J-W Operating Company (17%). For the year ended December 31, 2010,
+we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Chesapeake Operating Inc. (42%), Regency Gas Services LP (17%) and Petrohawk Energy Corporation (11%). For the year ended
+December 31, 2011, we had three significant purchasers that each accounted for more than 10% of our total oil and natural gas revenues: Sequent Energy Management (24%), Chesapeake Operating Inc. (21%) and Eastex Crude Company (15%). Due to
+the nature of the markets for oil and natural gas, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of
+time. 
+While we do not have any commitments to sell a fixed and determinable quantity of oil or natural gas to a particular
+buyer, we were party to two natural gas transportation agreements at December 31, 2011 that require us to deliver a specified volume of natural gas through pipelines for a fixed period of time. If we fail to meet the volume requirements, we are
+required to pay an amount to the owners of the pipelines to offset a portion of the expenses they incurred in building the pipelines to our well locations. Neither of these contracts constitutes a material commitment. 
+Title to Properties 
+We
+endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual
+arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests
+will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will
+not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by making lease rental payments or by producing wells in paying quantities prior to expiration of various
+time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result
+of Title Deficiencies in the Properties in Which We Invest.” 
+Competition 
+The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural
+gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, 
+24 
+Table of Contents 
+operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to
+absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects
+and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling
+rigs. 
+Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to
+conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while our competitors have a longer history of operations, and
+most of them have also demonstrated the ability to operate through industry cycles. 
+The oil and natural gas industry also
+competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors – Competition in the Oil and Natural Gas Industry Is Intense Making It More
+Difficult for Us to Acquire Properties, Market Natural Gas and Secure Trained Personnel.” 
+Regulation 
+Oil and Natural Gas Regulation 
+Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules
+and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or
+reinterpreted and new rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas
+industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. 
+Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and
+reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas matters,
+including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are
+drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes
+prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas
+wells below natural production capacity in order to conserve supplies of oil and natural gas. 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. 
+25 
+Table of Contents 
+Some of our oil and natural gas leases are issued by agencies of the federal government, as
+well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. 
+Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of
+transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as
+under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural
+gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
+In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act,
+among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly
+increase the penalties for violations of the NGA, the NGPA, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related
+regulations, in addition to FERC-imposed penalties, we may also be subject to third party damage claims. 
+Intrastate natural
+gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and
+services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our
+operations in any way that is materially different from our competitors that are similarly situated. 
+The price we receive
+from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though
+other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the
+effects, if any, of these regulations on our operations. 
+In 2007, the Energy Independence & Security Act of 2007, or
+the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations
+that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future regulations or their impact. 
+U.S. Federal and State Taxation 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions
+of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and 
+26 
+Table of Contents 
+presidential administrations concerning a variety of energy tax proposals. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and natural
+gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Many states have raised state
+taxes on energy sources, and additional increases may occur. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become
+Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect
+Our Business, Financial Condition, Results of Operations and Cash Flows.” 
+Hydraulic Fracturing Policies and
+Procedures 
+We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in almost
+every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary,
+as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our horizontal wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other
+costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditures budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs
+and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or
+Delays.” 
+The protection of groundwater quality is important to us. We believe that we follow all state and federal
+regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage). Our policy and
+practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing. A surface casing string is typically set deeper than the deepest usable quality fresh water zones and cemented back to the surface in
+accordance with the appropriate regulations, lease requirements and legal requirements. This surface string of casing is then pressure tested to ensure mechanical integrity of the casing string prior to continuing drilling operations. We follow
+strict quality control procedures for conducting hydraulic fracturing operations that include a multi-point safety checklist, managing inventories of all materials and chemicals on the well site and ensuring that Material Safety Data Sheets are on
+location for every well that is hydraulically fractured. We contract with third parties to conduct hydraulic fracturing operations, and we send at least one of our own engineers or an experienced consultant to the well site to personally supervise
+each hydraulic fracture treatment. On a real-time basis, we closely monitor pump rates and pressures on existing casing strings to ensure that wellbore integrity is maintained during hydraulic fracturing operations. Our policy regarding monitoring
+well pressures would require stopping the hydraulic fracturing operations upon any indication that wellbore integrity may have been compromised. 
+We follow additional regulatory requirements and recommended practices to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These include the
+following: 
+• 
+Prior to perforating the production casing and hydraulic fracturing operations, a cement bond log is run to verify cement integrity between the
+formation to be fractured and shallow formations. Then, the casing is pressure tested to ensure no leaks exist within the casing; 
+27 
+Table of Contents 
+• 
+Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all high pressure lines and
+connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, the service companies we engage must provide specialized equipment to monitor and record surface pressures, pumping
+rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Our engineers at the job site have laptop computers with special software to monitor and collect, for permanent
+archiving, information from the hydraulic fracturing operations. As part of this process, when fracturing operations are being performed down casing, we also monitor the casing annular pressure to ensure that there is no communication of hydraulic
+pressure and fracture fluids outside the casing that could communicate with shallow formations. Should any problem be detected at any time during the hydraulic fracturing treatment, the operation would be shut down until the problem is evaluated,
+reported and remediated; and 
+• 
+As a means to further protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing
+operation, special precautions are taken both during and after the operation. During the fracturing operation, all chemicals are mixed into the fracturing fluid as it is being pumped into the well as opposed to being pre-mixed in the “frac
+pits” or work tanks. While chemical additives are stored on location in independent containment vessels, only fresh water is stored in the frac pits or work tanks. All pumping equipment used during the operation is pressure tested and
+monitored. When the well is flowed back, after the fracturing operation, all fluids are produced into closed-top storage tanks. All flowback equipment and piping are pressure tested to ensure no leaks are present and the fluids are properly
+contained. 
+Once the final string of casing is set in place, cement is pumped into the casing/wellbore
+annulus where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design establishes a pressure seal essentially eliminating any pathway for the
+fracturing fluid to contact fresh water aquifers during the hydraulic fracturing operation. Furthermore, in the areas in which we conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable quality underground
+fresh water aquifers by thousands of feet of impermeable rock layers. This natural geological separation serves as a protective barrier, preventing migration of fracturing fluids or hydrocarbons upwards into any fresh water zones. 
+Although rare, if and when the cement and steel casing used in well construction need to be remediated, we deal with these problems by
+evaluating the issue, running diagnostic tools including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs. We repair wellhead leaks by replacing wellhead components, re-installing components to proper
+specifications and re-testing. In wellbores that utilize downhole packers, pressure integrity issues are rectified by repairing or replacing packers. Casing integrity lost due to corrosion on a producing well is remedied by identifying the specific
+location of the leak by cased hole logging tools, mechanical isolation and pressure testing or other diagnostic methods, followed by high pressure squeeze cementing and subsequent pressure testing to ensure the leak has been repaired. Throughout the
+process we believe we abide by applicable regulations. 
+The vast majority of hydraulic fracturing treatments are made up of
+water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies.
+These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to
+28 
+Table of Contents 
+develop more environmentally friendly fracturing fluids. As previously mentioned, we also follow strict safety procedures and monitor all aspects of the fracturing operation to ensure
+environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. 
+While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture
+stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in a way that does not impact surface waters. All produced water is disposed
+of in permitted and regulated disposal facilities. 
+Environmental Regulation 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells,
+are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety
+of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the
+Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject
+to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Civil and criminal
+fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities,
+limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and
+regulations and expect that these laws and regulations will not have a material adverse impact on us. 
+The OPA 90 and its
+regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic
+zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal
+costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to
+comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with
+applicable requirements under the OPA 90 will not have a material and adverse effect on us. 
+The CWA and comparable state laws
+impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions
+will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the
+federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, 
+29 
+Table of Contents 
+produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental
+Protection Agency, or the EPA, has 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. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of
+removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and
+meet construction and operating standards. 
+CERCLA, also known as the “Superfund” law, and comparable state statutes
+impose liability, without regard to fault or the legality of the original conduct, on various 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 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 responsible for releases of hazardous substances under
+CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. 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 hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will,
+involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Certain state statutes may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have
+been subjected to, or have caused or contributed to, prior releases of hazardous wastes. 
+RCRA and comparable state and local
+statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a
+statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the
+wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of
+this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors,
+to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. 
+The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose
+stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On
+July 28, 2011, the EPA proposed new regulations targeting air emissions from the oil and natural gas industry. The proposed rules, if adopted, would impose new requirements on production and processing and transmission and storage facilities
+and on hydraulic fracturing activities. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air
+emission-related issues, we do not believe that such requirements will affect our operations in any way that is materially different from our competitors. 
+30 
+Table of Contents 
+Changes in environmental laws and regulations occur frequently, and any changes that result
+in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general.
+For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
+atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas
+emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural
+gas. 
+The EPA has published its findings that emissions of greenhouse gases presented an endangerment to human health and the
+environment. 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 CAA. Subsequently, the EPA proposed and adopted
+two sets of regulations, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulated emissions of greenhouse gases from certain large stationary sources. In addition, on October 30,
+2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final
+rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities.
+Reporting of greenhouse gas emissions from such onshore production will be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or
+limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could
+adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development
+of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric
+plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative
+initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from
+oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a
+regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water.
+The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate five underground injection wells and expect to own other similar wells. Failure to obtain,
+or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. 
+31 
+Table of Contents 
+Our activities involve the use of hydraulic fracturing. For more information on our
+hydraulic fracturing operations, see “Business — Regulation — Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from
+regulation as underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of
+“underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain
+construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of
+chemicals used in the fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in
+any such legislation could have a significant impact on our financial condition, results of operations and cash flows. 
+In
+addition, at the federal level and in some states, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and in some areas to severely restrict or prohibit those activities. Certain bills have been
+introduced in the Senate and the House of Representatives that, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased
+operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. At the state level, Wyoming and Texas, for
+example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during hydraulic
+fracturing in Texas. The law went into effect in 2011 and implementing regulations have been adopted. In addition, at least a few local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local
+ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will
+result in additional expense and delay in our operations. 
+The EPA has recently been taking action to assert federal
+regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. Interim results of
+the study are expected in 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This
+study remains subject to review and public comment but such studies could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous
+owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire reserves
+against some of the liability for environmental claims associated with these properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties
+will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. 
+32 
+Table of Contents 
+Additionally, in the course of our routine oil and natural gas operations, surface spills
+and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is
+present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams.
+Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our
+lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 
+We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community
+right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations.
+Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. 
+We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to
+our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We cannot assure you that more stringent laws
+and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to
+Government Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.” 
+The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment,
+and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse
+effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will
+not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. 
+We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may
+not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is
+not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 
+Office
+Lease 
+Our corporate headquarters are located in 28,743 square feet of office space in One Lincoln Centre, 5400 LBJ
+Freeway, Suite 1500, Dallas, Texas. In April 2011, we entered into a third amended and restated office lease agreement pursuant to which our office space was increased from 20,849 to 28,743 square feet and the term of our lease was extended from
+July 1, 2011 to June 30, 2022. Beginning July 1, 2011, through 
+33 
+Table of Contents 
+June 30, 2012, we are not required to pay a monthly base rent. From July 1, 2012 through June 30, 2015, our monthly base rent is $47,905. From July 1, 2015 through
+June 30, 2017, our monthly base rent is $50,300. From July 1, 2017 through June 30, 2019, our monthly base rent is $52,696. From July 1, 2019 through June 30, 2020, our monthly base rent is $55,091. From July 1, 2020
+through the expiration date of the lease, our monthly base rent is $57,726. In addition, the lease contains a renewal option in our favor for an additional 60-month period at the then existing market rate as determined in accordance with the lease.
+Employees 
+At December 31, 2011, we had 41 full-time employees. We believe that our relationships with our employees are satisfactory. No
+employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, construction,
+design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and
+on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to
+employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. 
+Available Information
+Our Internet website address is www.matadorresources.com . We expect to make available, free of charge, through our
+website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit
+Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a written request to the
+Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this report or any other report or document we file and any reference to
+our website is intended to be an inactive textual reference only. 
+34 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/item13.txt b/raw/filings/0001520006/2011/0001193125-12-145249/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f64669f4035fbe9df25a0f6ae13dca9d57e128fe
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/item13.txt
@@ -0,0 +1,4 @@
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence. 
+The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.
\ No newline at end of file
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/item9a.txt b/raw/filings/0001520006/2011/0001193125-12-145249/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..19d6b65a653961f473fc69454ab8442c4d09e5ca
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/item9a.txt
@@ -0,0 +1,18 @@
+Item 9A. 
+Controls and Procedures. 
+This Annual Report does not include a report of management’s assessment regarding internal control over financial reporting or an
+attestation report of the company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies. 
+Prior to the completion of our initial public offering, we maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal
+control over financial reporting. In connection with our audit for the year ended December 31, 2011, our independent registered public accountants identified and communicated a material weakness related to accounting for stock compensation expense.
+A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial
+statements will not be prevented or detected and corrected on a timely basis. 
+We have begun the process of evaluating our
+internal control over financial reporting and expect to put into place new accounting processes and control procedures to address the weakness described above, including the hiring of outside consultants to review significant or complex accounting
+issues and calculations, the implementation of a more formalized closing process, the formation of a disclosure committee and the hiring of additional personnel. We cannot predict the outcome of this process at this time. We will be required to make
+our first assessment of our internal control over financial reporting at December 31, 2012. 
+We became a public company
+on February 1, 2012 in connection with the completion of our initial public offering. Prior to that date, we were a private company and were not required to file or submit reports under the Securities Exchange Act of 1934, as amended (the
+“Exchange Act”) and maintained disclosure controls and procedures in accordance with being a private company. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our
+disclosure controls and procedures (as defined in Rule 13a-15(e)) under the Exchange Act was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon
+this evaluation, as of the end of the period covered by this report, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective because we were not yet a public company and,
+therefore, had not yet established formal disclosure controls and procedures and because the material weakness described above relating to our internal control over financial reporting was identified.
\ No newline at end of file
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/rp_note.txt b/raw/filings/0001520006/2011/0001193125-12-145249/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..f2b346a713a0f3a8b55222b9c7e78041c6685f14
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/rp_note.txt
@@ -0,0 +1,14 @@
+NOTE 15 — TRANSACTIONS WITH RELATED PARTIES 
+In January 2007, the Company entered into a joint venture with Marlan Downey and Julie Downey Garvin of Roxanna Oil Company
+(“Roxanna”) to assemble acreage for and to market a new gas shale prospect in southwest Wyoming, northeast Utah and southeast Idaho. Mr. Downey is a special advisor to the Company’s Board of Directors and a shareholder in the
+Company. Ms. Garvin is President of Roxanna, which is also a shareholder in Matador. Mr. Downey and Ms. Garvin developed the prospect concept independently and sought the Company’s expertise in assembling a large acreage position
+across the prospect. At December 31, 2011, the Company has assembled over 140,000 acres across the prospect at a total cost of approximately $9,700,000. The Company actively marketed this prospect in conjunction with Mr. Downey and
+Ms. Garvin. In May 2010, the Company, Roxanna and its subsidiary, Roxanna Rocky Mountains, LLC, entered into participation and joint operating agreements with an industry partner for the joint exploration and development of this opportunity.
+Under these agreements, Roxanna Rocky Mountains, LLC reserves a 2.5% overriding royalty interest in the leases and has the opportunity to earn up to a 10% working interest in all wells drilled. The industry partner has a 50% working interest in the
+project, and the Company retains a working interest equal to the difference between 50% and the working interest participation elected by Roxanna Rocky Mountains, LLC. The Company, as operator, drilled the initial test well for this prospect located
+in Lincoln County, Wyoming during 2011. This well was awaiting completion at December 31, 2011. 
+F-41
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2011, 2010 and 2009
\ No newline at end of file
diff --git a/raw/filings/0001520006/2011/0001193125-12-145249/rpt_disclosure.txt b/raw/filings/0001520006/2011/0001193125-12-145249/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..e81438e215415930a78179289d6b5d99355fb1f2
--- /dev/null
+++ b/raw/filings/0001520006/2011/0001193125-12-145249/rpt_disclosure.txt
@@ -0,0 +1,142 @@
+TRANSACTIONS WITH RELATED PERSONS 
+Since January 1, 2011, there has not been, nor is there currently proposed, any transaction or series of similar transactions to
+which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our 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, other than compensation arrangements with directors and executive officers, which are described in “Compensation of Named Executive Officers,” and the
+transactions described or referred to below. 
+Participation in Our Initial Public Offering 
+On February 7, 2012, upon the closing of our initial public offering, the following directors and executive officers purchased at
+least $120,000 of Common Stock in the directed share program and from the underwriters in the offering at the initial price to the public: 
+Director or Executive Officer 
+Amount 
+Joseph Wm. Foran (1) 
+$ 
+1,660,800 
+Charles L. Gummer 
+264,000 
+David M. Laney (2) 
+684,000 
+Wade I. Massad (3) 
+252,000 
+Gregory E. Mitchell (4) 
+200,004 
+Margaret B. Shannon 
+200,004 
+(1) 
+$1,200,000 of shares were purchased by Mr. Foran and $460,800 of shares were purchased by Sage Resources, Ltd., a limited partnership owned by the Foran family,
+including Mr. Foran. 
+(2) 
+$180,000 of shares were purchased by Mr. Laney, $144,000 of shares were purchased by Mr. Laney’s adult children, who gave Mr. Laney voting power of
+such shares through a revocable power of attorney and $360,000 of shares were purchased by Laney Investments Ltd., for which Mr. Laney has sole voting and investment power. 
+(3) 
+$216,000 of shares were purchased by Cleveland Capital L.P. for which Mr. Massad is the co-managing member and $36,000 of shares were purchased using funds from
+Mr. Massad’s Individual Retirement Account. 
+(4) 
+All of the shares were purchased by JAMAL Enterprises, LP, for which Mr. Mitchell has sole voting and investment authority. 
+Loan Program 
+During 2011, we guaranteed the repayment of loans to certain of our executive officers by Comerica Bank. The purpose of these loans was to assist our executive officers in buying shares of our Common
+Stock pursuant to the exercise of stock options. We guaranteed the repayment of loans and made deposits of funds in certificates of deposit to secure our guaranties for the following executive officers at December 31, 2011: 
+Executive Officer and Date of Loan or Renewal 
+Loan 
+Amount 
+Interest 
+Rate 
+Interest Paid or 
+Payable 
+in 2011 
+Maturity Date 
+Matthew V. Hairford; December 29, 2009; renewed October 8, 2011 
+$ 
+310,000 
+5.25 
+% 
+$ 
+16,231 
+April 5, 2012 
+David E. Lancaster; April 30, 2009; 
+renewed May 30, 2011 
+$ 
+470,000 
+5.25 
+% 
+$ 
+24,608 
+May 29, 2012 
+Bradley M. Robinson; December 29, 2008; renewed January 29, 2011 
+$ 
+280,000 
+5.25 
+% 
+$ 
+14,660 
+January 28, 2012 
+Our Board of Directors approved the termination of the loan program on April 7, 2011 and we
+terminated our guaranties and the associated pledge of our certificates of deposit with Comerica Bank relating to these loans in January 2012. We made no payments to Comerica Bank pursuant to these loan guaranties. 
+61 
+Table of Contents 
+Issuance of Our Securities 
+In January 2011, we completed a private placement offering of shares of our Class A Common Stock. See “Business—Recent
+Developments.” As detailed in the table below, several of our directors and executive officers participated in such offering on the same terms and conditions as the other investors in the offering. 
+Director or Executive Officer 
+Aggregate 
+Consideration 
+Joseph Wm. Foran 
+$ 
+1,171,500 
+(1) 
+David M. Laney 
+$ 
+473,000 
+(2) 
+Michael C. Ryan 
+$ 
+1,100,000 
+Margaret B. Shannon (3) 
+$ 
+249,700 
+(1) 
+Sage Resources, Ltd., which is a limited partnership owned by the Foran family, including Mr. Foran, purchased a portion of the shares for an aggregate
+consideration of $346,500. 
+(2) 
+Mr. Laney’s adult children purchased a portion of the shares for an aggregate consideration of $198,000. At that time, Mr. Laney had the power to vote
+his children’s shares pursuant to a revocable power of attorney. In addition, Laney Investments Ltd., for which Mr. Laney has sole voting and investment power, purchased a portion of the shares for an aggregate consideration of $275,000.
+(3) 
+Mrs. Shannon was not a member of our Board of Directors at the time of purchase. 
+Procedures for Approval of Related Party Transactions 
+Our Board of Directors has adopted a written related party transaction policy. Pursuant to this policy, a “Related Party Transaction” is defined as a transaction (including any financial
+transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, involving a Related Party (as defined below) and in which we
+are a participant, other than: 
+• 
+a transaction involving compensation of directors; 
+• 
+a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, change in control provision or
+agreement or a special supplemental benefit for an executive officer; 
+• 
+a transaction available to all employees generally or to all salaried employees generally; 
+• 
+a transaction with a Related Party involving less than $120,000; 
+• 
+a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that
+class receive the same benefit on a pro rata basis; or 
+• 
+a transaction in which the rates or charges involved therein are determined on competitive bids, or a transaction that involves the rendering of
+services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. 
+“Related Party” means: 
+• 
+any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or nominees for directors;
+• 
+any person who is known by us to be the beneficial owner of more than 5.0% of our Common Stock; 
+• 
+any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law,
+father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficial owner of more than 5.0% of our Common Stock; and 
+62 
+Table of Contents 
+• 
+any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general
+partner or executive officer or in which such person, together with all other of the foregoing persons, has a 10.0% or greater beneficial ownership interest. 
+Pursuant to our related party transaction policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or disapproval of the Related Party
+Transaction to the full Board of Directors, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all material facts of the
+Related Party Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be disclosed in our filings
+with the SEC and/or our website in accordance with applicable laws, rules and regulations. All of the Related Party Transactions discussed above occurred prior to the adoption of the policy except for participation in our initial public offering.
+Those executive officers and directors who participated in our initial public offering negotiated with RBC Capital Markets, LLC; therefore, the related party transaction policy was not triggered. 
+63 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/filing.txt b/raw/filings/0001520006/2012/0001193125-13-111031/filing.txt
new file mode 100644
index 0000000000000000000000000000000000000000..fa615188b724996df3aec0b01cdc63dc5a21c630
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/filing.txt
@@ -0,0 +1,9108 @@
+10-K
+1
+d444422d10k.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 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 001-34574
+Matador Resources Company 
+(Exact name of registrant as specified in its charter) 
+Texas 
+27-4662601 
+(State or other jurisdiction of 
+incorporation or organization) 
+(I.R.S. Employer 
+Identification No.) 
+5400 LBJ Freeway, Suite 1500 
+Dallas, Texas 75240 
+75240 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code: (972) 371-5200 
+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 
+New York Stock Exchange 
+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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for 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 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 
+¨ 
+Accelerated filer 
+x 
+Non-accelerated filer 
+¨ (Do not check if a smaller reporting company) 
+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 equity of the registrant held by non-affiliates, computed by reference to
+the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $454,393,967. 
+As of March 14, 2013, there were 55,894,438 shares of common stock outstanding. 
+DOCUMENTS
+INCORPORATED BY REFERENCE 
+The information required by Part III of this annual report on Form 10-K, to the extent not set
+forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2013 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the
+fiscal year to which this annual report on Form 10-K relates. 
+Table of Contents 
+MATADOR RESOURCES COMPANY 
+FORM 10-K 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012 
+TABLE OF CONTENTS 
+Page 
+PART I 
+I TEM 1. 
+B USINESS 
+3 
+I TEM 1A. 
+R ISK F ACTORS 
+39 
+I TEM 1B. 
+U NRESOLVED S TAFF C OMMENTS 
+63 
+I TEM 2. 
+P ROPERTIES 
+63 
+I TEM 3. 
+L EGAL P ROCEEDINGS 
+63 
+I TEM 4. 
+M INE S AFETY D ISCLOSURES 
+63 
+PART II 
+I TEM 5. 
+M ARKET FOR R EGISTRANT ’ S C OMMON E QUITY , R ELATED S TOCKHOLDER
+M ATTERS AND I SSUER P URCHASES OF E QUITY S ECURITIES 
+64 
+I TEM 6. 
+S ELECTED F INANCIAL D ATA 
+66 
+I TEM 7. 
+M ANAGEMENT ’ S D ISCUSSION AND A NALYSIS OF F INANCIAL C ONDITION
+AND R ESULTS OF O PERATIONS 
+70 
+I TEM 7A. 
+Q UANTITATIVE AND Q UALITATIVE D ISCLOSURES ABOUT M ARKET R ISK
+97 
+I TEM 8. 
+F INANCIAL S TATEMENTS AND S UPPLEMENTARY D ATA 
+101 
+I TEM 9. 
+C HANGES IN AND D ISAGREEMENTS W ITH A CCOUNTANTS ON A CCOUNTING
+AND F INANCIAL D ISCLOSURE 
+101 
+I TEM 9A. 
+C ONTROLS AND P ROCEDURES 
+101 
+I TEM 9B. 
+O THER I NFORMATION 
+104 
+PART III 
+I TEM 10. 
+D IRECTORS , E XECUTIVE O FFICERS AND C ORPORATE 
+G OVERNANCE 
+104 
+I TEM 11. 
+E XECUTIVE C OMPENSATION 
+104 
+I TEM 12. 
+S ECURITY O WNERSHIP OF C ERTAIN B ENEFICIAL O WNERS AND M ANAGEMENT
+AND R ELATED S TOCKHOLDER M ATTERS 
+104 
+I TEM 13. 
+C ERTAIN R ELATIONSHIPS AND R ELATED T RANSACTIONS , AND D IRECTOR
+I NDEPENDENCE 
+104 
+I TEM 14. 
+P RINCIPAL A CCOUNTING F EES AND S ERVICES 
+104 
+PART IV 
+I TEM 15. 
+E XHIBITS AND F INANCIAL S TATEMENT S CHEDULES 
+105 
+i 
+Table of Contents 
+Cautionary Note Regarding Forward-Looking Statements 
+Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable
+U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by
+the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,”
+“predict,” “project,” “should” or other similar words. 
+By their very nature, forward-looking
+statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity
+and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the success of our drilling program, the timing of planned capital expenditures,
+availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well
+as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors
+discussed below and elsewhere in this Annual Report on Form 10-K and in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking
+statements may include statements about: 
+• 
+our business strategy; 
+• 
+our reserves; 
+• 
+our technology; 
+• 
+our cash flows and liquidity; 
+• 
+our financial strategy, budget, projections and operating results; 
+• 
+our oil and natural gas realized prices; 
+• 
+the timing and amount of future production of oil and natural gas; 
+• 
+the availability of drilling and production equipment; 
+• 
+the availability of oil field labor; 
+• 
+the amount, nature and timing of capital expenditures, including future exploration and development costs; 
+• 
+the availability and terms of capital; 
+• 
+our drilling of wells; 
+• 
+government regulation and taxation of the oil and natural gas industry; 
+• 
+our marketing of oil and natural gas; 
+• 
+our exploitation projects or property acquisitions; 
+• 
+our costs of exploiting and developing our properties and conducting other operations; 
+• 
+general economic conditions; 
+• 
+competition in the oil and natural gas industry; 
+1 
+Table of Contents 
+• 
+the effectiveness of our risk management and hedging activities; 
+• 
+environmental liabilities; 
+• 
+counterparty credit risk; 
+• 
+developments in oil-producing and natural gas-producing countries; 
+• 
+our future operating results; 
+• 
+estimated future reserves and the present value thereof; and 
+• 
+our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. 
+Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us
+on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition. 
+You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could
+differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular
+forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially
+affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law,
+including the securities laws of the United States and the rules and regulations of the SEC. 
+2 
+Table of Contents 
+PART I 
+Item 1. 
+Business. 
+In this
+Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador
+Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly-owned subsidiary of Matador Resources Company, now known as MRC Energy
+Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its
+corporate name to Matador Resources Company. 
+Unless the context otherwise requires, the term “common stock”
+refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only
+class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of
+our initial public offering. 
+For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the
+“Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. 
+General 
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources
+in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas
+and in the Haynesville shale play in Northwest Louisiana. In 2012, more than 90% of our total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we sought to transition to a
+more balanced commodity portfolio through the drilling of wells that were prospective for oil and liquids. For the year ended December 31, 2012, approximately 37% of our total production by volume (using a conversion ratio of one Bbl of oil per
+6 Mcf of natural gas) and 79% of our total oil and natural gas revenues were attributable to oil production, primarily from the Eagle Ford shale. In 2013, we expect that approximately 82% of our estimated capital expenditures of $310.0 million will
+be directed to increasing our oil production and oil reserves in South Texas, primarily in the Eagle Ford shale play. Although we did not drill any operated Haynesville shale natural gas wells during 2012, we directed approximately 3% of our capital
+expenditures to the Haynesville shale in 2012 to participate in several non-operated wells. In addition to these primary operating areas, we have a growing acreage position in Southeast New Mexico and West Texas where we plan to drill three
+exploratory wells to test the Wolfcamp and Bone Spring plays during 2013. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale. 
+We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO. Mr. Foran began his career as an
+oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by
+Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5
+million. 
+3 
+Table of Contents 
+On February 2, 2012, our common stock began trading on the NYSE under the symbol
+“MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167
+shares of common stock, including shares sold pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.
+In 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South
+Texas, as we continued to execute our strategy to significantly increase our oil production and oil reserves during 2012. During the year ended December 31, 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net Eagle
+Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin
+Chalk/upper Eagle Ford, or “Chalkleford,” intervals in 2012. In addition, during 2012, we completed and began producing natural gas from 28 gross/1.1 net non-operated Haynesville shale wells. We also re-entered and drilled a horizontal
+lateral from the previously suspended Crawford Federal #1 vertical well in Southwest Wyoming; we plan to complete this well in the third quarter of 2013. 
+We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract), and
+almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. We did not drill any operated wells in the Haynesville shale play in Northwest Louisiana during 2012 as a result of the decline in natural gas prices
+compared to recent years. At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County. 
+Our average daily production for the year ended December 31, 2012 was approximately 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, as compared to 7,049
+BOE per day, including 422 Bbl of oil per day and 39.8 MMcf of natural gas per day for the year ended December 31, 2011. Our total oil production increased almost eight-fold to just over 1.2 million Bbl of oil during the year ended
+December 31, 2012 from approximately 154,000 Bbl of oil during the year ended December 31, 2011. This increased oil production is a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised approximately
+37% of our total production for the year ended December 31, 2012, as compared to only 6% of our total production for the year ended December 31, 2011. 
+During the three months ended December 31, 2012, specifically, our average daily production was 10,385 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day. This was
+an increase of almost 50% compared to our average daily production for the three months ended December 31, 2011 of 6,953 BOE per day, including 448 Bbl of oil per day and 39.0 MMcf of natural gas per day. Our total oil production increased
+ten-fold to 426,000 Bbl of oil during the three months ended December 31, 2012, as compared to total oil production of 41,000 Bbl of oil during the three months ended December 31, 2011. Our average daily production for the fourth quarter
+of 2012 was a sequential increase of 18% from the average daily production of 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day, achieved during the third quarter of 2012. For the three months ended
+December 31, 2012, our oil production grew 41% sequentially, as compared to the three months ended September 30, 2012. 
+At December 31, 2012, our estimated total proved reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas (13.3 million BOE). At December 31, 2012,
+58% of our total proved reserves were proved developed reserves compared to 34% at December 31, 2011. At December 31, 2012, 44% of our total proved reserves were oil and 56% of our total proved reserves were
+4 
+Table of Contents 
+natural gas, as compared to 12% oil and 88% natural gas at December 31, 2011. Our proved oil reserves grew 176% (almost three-fold) from 3.8 million Bbl at December 31, 2011 to
+10.5 million Bbl at December 31, 2012. This growth in oil reserves was attributable to our drilling program in the Eagle Ford shale during 2012. Our proved natural gas reserves declined to 80.0 Bcf at December 31, 2012 from 170.4 Bcf
+at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana
+from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these
+previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices
+improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+The PV-10
+of our estimated total proved reserves was $423.2 million at December 31, 2012 compared to a PV-10 of $248.7 million at December 31, 2011, an increase of 70% despite lower commodity prices used to estimate PV-10 in 2012 compared to 2011.
+The PV-10 at December 31, 2012 was determined using the 12-month unweighted average of first-day-of-the-month oil and natural gas prices for 2012 of $91.21 per barrel and $2.757 per MMBtu, respectively, adjusted by lease for quality, energy
+content, regional price differentials and other expenses as needed compared to average oil and natural gas prices of $92.71 per barrel and $4.118 per MMBtu, respectively, adjusted as further described above, used to determine PV-10 at
+December 31, 2011. The Standardized Measure of estimated future net cash flows from our total proved reserves, including estimated future income tax expenses, was $394.6 million at December 31, 2012 and $215.5 million at
+December 31, 2011. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at
+10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see
+“—Estimated Proved Reserves.” 
+For the year ended December 31, 2012, our oil and natural gas revenues were
+approximately $156.0 million, or an increase of about 133%, as compared to approximately $67.0 million for the year ended December 31, 2011. Our oil revenues increased over eight-fold to approximately $123.7 million for the year ended
+December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our total realized revenues for 2012, including realized gain on derivatives, were approximately $170.0 million, or an increase of about 129%, as
+compared to $74.1 million for 2011. For the year ended December 31, 2012, our Adjusted EBITDA was approximately $115.9 million, or an increase of about 132%, as compared to an Adjusted EBITDA of approximately $49.9 million for the year ended
+December 31, 2011. Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income (loss) and net cash flow provided by operating activities, see “Selected Financial Data — Non-GAAP Financial
+Measures.” 
+5 
+Table of Contents 
+The following table presents certain summary data for each of our operating areas as of and
+for the year ended December 31, 2012: 
+Net Acreage 
+Producing 
+Wells 
+Total Identified 
+Drilling Locations (1) 
+Estimated Net Proved 
+Reserves (2) 
+Avg. Daily 
+Production 
+(BOE/d) (3) 
+Gross 
+Net 
+Gross 
+Net 
+MBOE (3) 
+% 
+Developed 
+South Texas: 
+Eagle Ford 
+27,911 
+37.0 
+31.7 
+274.0 
+221.0 
+14,331 
+45.5 
+3,908 
+Austin Chalk (4) 
+17,465 
+4.0 
+4.0 
+17.0 
+17.0 
+20 
+100.0 
+20 
+Area Total (5) 
+27,911 
+41.0 
+35.7 
+291.0 
+238.0 
+14,351 
+45.6 
+3,928 
+NW Louisiana/E Texas: 
+Haynesville 
+14,173 
+134.0 
+12.7 
+472.0 
+101.1 
+7,856 
+71.5 
+4,336 
+Cotton Valley (6) 
+22,469 
+106.0 
+69.7 
+71.0 
+49.3 
+1,512 
+100.0 
+706 
+Area Total (7) 
+24,968 
+240.0 
+82.4 
+543.0 
+150.4 
+9,368 
+76.1 
+5,042 
+SE New Mexico, West Texas (8) 
+7,591 
+13.0 
+5.7 
+39.0 
+25.1 
+100 
+100.0 
+30 
+SW Wyoming, NE Utah, SE Idaho 
+27,180 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Total 
+87,650 
+294.0 
+123.8 
+873.0 
+413.5 
+23,819 
+57.8 
+9,000 
+(1) 
+These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is
+calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At December 31, 2012, these identified drilling locations included 30 gross and 26.8 net locations
+to which we have assigned proved undeveloped reserves in the Eagle Ford and 2 gross and 1.9 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to identified drilling
+locations in the Austin Chalk or Cotton Valley or in the Wolfcamp or Bone Spring plays in Southeast New Mexico and West Texas at December 31, 2012. 
+(2) 
+These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
+(3) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(4) 
+Includes two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(5) 
+Some of the same leases cover the net acres shown for both the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation.
+Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for South Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
+(6) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(7) 
+Some of the same leases cover the net acres shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville
+formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these
+formations. 
+(8) 
+Includes potential future drilling locations identified in either the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas at December
+31, 2012. 
+At December 31, 2012, our properties included approximately 42,500 gross acres and 27,900 net
+acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, LaSalle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In
+addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 70% of
+our Eagle Ford acreage was held by production at December 31, 2012, and approximately 84% of our Eagle Ford acreage was either held by production at December 31, 2012 or not burdened by lease expirations before 2014. 
+At December 31, 2012, we had 37 gross and 31.7 net wells producing from the Eagle Ford shale in South Texas, and we have identified
+274 gross locations and 221.0 net locations for potential future drilling 
+6 
+Table of Contents 
+on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties,
+estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated
+horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Of the 274 gross and 221.0 net locations identified for potential
+future drilling in the Eagle Ford shale at December 31, 2012, we consider 155 gross and 125.1 net locations as Tier 1 locations. We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of
+225,000 Bbl of oil or greater. Of these Tier 1 locations, 115 gross locations and 109.1 net locations would be operated by us. These identified locations presume that we will be able to develop our Eagle Ford properties on 40-acre to 80-acre
+spacing, depending on the specific property and the wells we have already drilled. We anticipate that our acreage in central and northern LaSalle County and in northern Karnes County can be developed on 40-acre spacing in the Eagle Ford, while our
+other properties may be more likely developed on 80-acre spacing. We are currently drilling on 80-acre spacing on most of our properties. Although we had not yet drilled any wells on 40-acre spacing at December 31, 2012, we have several tests on
+less than 80-acre spacing planned on certain of our properties during 2013. We define Tier 2 Eagle Ford locations, including 119 gross and 95.9 net locations, as those locations that we anticipate to have estimated ultimate recoveries of between
+150,000 Bbl and 225,000 Bbl of oil, locations that are primarily prospective for natural gas or other locations on properties already held by existing production. At December 31, 2012, Tier 2 locations were identified primarily on our acreage in
+Zavala County and in southern LaSalle County; we have identified no potential future Eagle Ford drilling locations on our Atascosa County acreage. All of these Tier 2 locations would be operated by us, and approximately 85% of these locations are
+located on properties already held by production from the Eagle Ford or other producing horizons. Although we have no plans to drill any of these Tier 2 locations in 2013, as long as these properties remain held by production, these locations remain
+available for us to drill at a later time should commodity prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. Certain of these properties, such as our properties in Zavala and
+Atascosa Counties, also offer the opportunity to explore horizons other than the Eagle Ford, including the Austin Chalk, Buda, Edwards or Pearsall, and we may develop new prospects on these properties in the future. As we explore and develop all of
+our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for future drilling, particularly on those properties where we now presume development on 80-acre spacing. At December 31, 2012, these 274 gross and
+221.0 net potential future drilling locations included 30 gross and 26.8 net locations to which we have assigned proved undeveloped reserves. 
+In addition, at December 31, 2012, we had approximately 22,300 gross acres and 14,200 net acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and
+petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells
+drilled across the Haynesville shale play, approximately 5,700 of our net acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been
+drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production from the Haynesville or other formations, and we believe much of it is also
+prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play, although as of December 31, 2012, we had
+not tested the Middle Bossier shale on our acreage. 
+7 
+Table of Contents 
+At December 31, 2012, we had identified 472 gross locations and 101.1 net locations for
+potential future drilling on our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return,
+estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal
+lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 472 gross locations identified for future drilling, 397 of these locations
+(50.2 net locations) have been identified within the approximately 5,700 net acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may
+identify additional locations for future drilling. At December 31, 2012, these identified potential future drilling locations included only 2 gross and 1.9 net locations in the Haynesville shale play to which we have assigned proved undeveloped
+reserves. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total
+proved reserves at June 30, 2012, most of which were attributable to non-operated properties, including 100 gross and 14.8 net locations to which we had previously assigned proved undeveloped reserves. As long as the leasehold acreage
+associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes and the corresponding potential drilling locations remain available to be
+developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+At December 31, 2012, our properties also included approximately 15,900 gross and 7,600 net acres in the Delaware Basin in Southeast
+New Mexico and West Texas where we are developing new oil prospects. We believe that approximately 8,200 gross and 5,500 net acres are prospective for the Wolfcamp shale and Bone Spring formations, as well as other potential uphole targets including
+the Delaware sands and the Avalon shale. We believe that the Wolfcamp, Bone Spring, Avalon and Delaware formations are all prospective primarily for oil and that multiple target intervals may be prospective within each formation. At
+December 31, 2012, approximately 6,000 gross and 3,900 net of these acres were already held by production from other producing horizons. We expect to begin exploring this acreage position during the second and third quarters of 2013 and plan to
+drill a total of three test wells on this acreage in 2013. Two wells will test the Wolfcamp shale and one well will test the Second Bone Spring formation. At December 31, 2012, we had identified 39 gross and 25.1 net locations for potential future
+drilling in the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas, including the three exploratory test wells planned for 2013. These locations have been identified on a property-by-property basis and take into
+account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from nearby wells producing from the Wolfcamp and Bone Spring formations based on available public data, drilling
+densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
+Because we are just beginning the exploration of our properties in Southeast New Mexico and West Texas in 2013, our identified well locations at December 31, 2012 presume that only one horizon in the Wolfcamp or the Bone Spring may be developed at
+any one surface location and that these properties may be developed on 160-acre well spacing, although we believe that multiple intervals may be prospective at any one surface location and that denser well spacing may be possible. In addition,
+although our potential future drilling locations presume the drilling of horizontal wells, we also believe that certain portions of our acreage could lend itself to development with vertical wells. As a result, as we explore and develop our
+Southeast New Mexico and West Texas acreage further, we believe it is possible that we may identify additional locations 
+8 
+Table of Contents 
+for future drilling. At December 31, 2012, we had not assigned proved undeveloped reserves to any of these potential drilling locations in the Wolfcamp or Bone Spring formations. Although we
+believe that prospective well locations exist on this acreage for the Avalon shale and the Delaware sands, we had not included any Avalon or Delaware locations in our identified well locations at December 31, 2012. 
+At December 31, 2012, we also had a large unevaluated acreage position, including approximately 55,300 gross and 27,200 net acres in
+Southwest Wyoming and adjacent areas in Utah and Idaho, where we began drilling our initial well in February 2011 to test the Meade Peak natural gas shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak
+shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations in November 2011. After taking time to review
+and analyze the extensive well log and core data collected in this well, we re-entered the vertical well and drilled an approximately 2,500-ft horizontal lateral in the Meade Peak shale during the fourth quarter of 2012. Operations on this well are
+temporarily suspended, but we plan to complete and test the horizontal lateral portion of this well beginning in the third quarter of 2013. 
+We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation
+and others. At December 31, 2012, we were the operator for approximately 91% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large
+portion of our acreage in the core area of the Haynesville shale is operated by a subsidiary of Chesapeake Energy Corporation. We also operate the vast majority of our acreage in Southeast New Mexico and West Texas, as well as all of our acreage in
+Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interest is relatively small, particularly in the Haynesville shale. 
+At December 31, 2012, we were a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal
+Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc. and Hunt Oil Company in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation
+governing the Haynesville operations underlying our Elm Grove/Caspiana properties in Southern Caddo Parish, Louisiana and joint operating agreements with EOG Resources, Inc. and Hunt Oil Company governing operations on our joint acreage in Atascosa
+and Wilson Counties, Texas, respectively. We have not entered into a joint operating agreement with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our
+working interest is small, we do not always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices.
+Where we do have joint operating agreements with affiliates of other companies, these agreements call for significant
+penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and
+equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation
+at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose. 
+While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to
+maintain ongoing communications with the technical staff of these operators in 
+9 
+Table of Contents 
+an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these
+locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. 
+We currently intend to allocate approximately 82% of our estimated 2013 capital expenditure budget of $310.0 million to the exploration,
+development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play. We also plan to allocate about 16% of our 2013 capital expenditure budget to the exploration and acquisition of additional interests in the
+Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas and in Southeast New Mexico and West Texas, we plan to dedicate about 98% of our 2013
+anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted approximately $310.0 million for 2013, the aggregate amount of capital we will expend may fluctuate materially based on market
+conditions, the actual costs to drill scheduled wells, our drilling results and our ability to obtain capital. Since approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014, 79% of
+our Wolfcamp and Bone Spring acreage was either held by production or not burdened by lease expirations before 2014 and almost all of our Haynesville acreage was held by production at December 31, 2012, we possess the financial flexibility to
+allocate our capital when and where we believe it is economical and justified. 
+Recent Developments 
+On March 11, 2013, the borrowing base under our Credit Agreement was increased to $255.0 million based on the lenders’ review of
+our proved oil and natural gas reserves at December 31, 2012. At that time, we also amended our Credit Agreement to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank in our lending group, which also
+includes Royal Bank of Canada (“RBC”), as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. At March 14, 2013, we had $180.0 million in borrowings and $1.3 million in letters of credit
+outstanding under our Credit Agreement. 
+Principal Areas of Interest 
+Our focus since inception has been the exploration for oil and natural gas in unconventional resource plays with a particular focus in
+recent years in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. During 2012, we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in
+South Texas as we sought to increase our oil production and reserves. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential
+for multiple-zone completions. We have also sought to balance the risk profile of our prospects, as well as to explore for more conventional targets in addition to the unconventional resource plays. 
+At December 31, 2012, our principal areas of interest consisted of (1) the Eagle Ford shale play in South Texas, (2) the
+Haynesville shale play, including the Middle Bossier shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations in Northwest Louisiana and East Texas, (3) the Wolfcamp and Bone Spring plays in Southeast New Mexico
+and West Texas, particularly in the Delaware Basin, and (4) the Meade Peak shale play in Southwest Wyoming and the adjacent areas of Utah and Idaho. 
+10 
+Table of Contents 
+South Texas 
+Eagle Ford Shale and Other Formations 
+The Eagle Ford shale extends across
+portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower
+Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases
+consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more
+natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet natural gas with condensate. We believe that approximately 88% of our South Texas acreage at December 31, 2012
+lies within those portions of the Eagle Ford shale that are prone to produce oil or wet natural gas with condensate. 
+During
+2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas as we continued executing our strategy to significantly increase our oil production and oil reserves. In 2012, we
+completed and began producing oil and natural gas from 28 gross/24.5 net operated Eagle Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We had two contracted drilling rigs operating in
+South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract). At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas:
+one in LaSalle County and one in DeWitt County. More than 90% of our 2012 total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale. 
+For the year ended December 31, 2012, about 43% of our daily production, or 3,908 BOE per day, including 3,246 Bbl of oil per day
+and 4.0 MMcf of natural gas per day, was produced from the Eagle Ford shale in South Texas. Almost all of our oil production in 2012 was attributed to the Eagle Ford shale. The Eagle Ford contributed 98% of our daily oil production and about 12% of
+our daily natural gas production during 2012 as compared to 78% of our daily oil production and 3% of our daily natural gas production during 2011. During the year ended December 31, 2011, only about 8% of our daily production, or 548 BOE per
+day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past year reflects our ongoing drilling and
+completion program in the Eagle Ford shale. 
+At December 31, 2012, approximately 60% of our estimated total proved oil
+and natural gas reserves, or 14.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.4 million Bbl of oil and 23.8 Bcf of natural gas. Our proved reserves attributable to the Eagle Ford shale increased just
+over three-fold for the year to 14.3 million BOE for the year ended December 31, 2012, as compared to 4.7 million BOE for the year ended December 31, 2011. Our Eagle Ford proved reserves at December 31, 2012 comprised
+approximately 99% of our proved oil reserves and 30% of our proved natural gas reserves, as compared to approximately 96% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2011. The PV-10 of our proved
+reserves in the Eagle Ford at December 31, 2012 was $393.2 million, or about 93% of the PV-10 of our total proved reserves of $423.2 million. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see
+“— Estimated Proved Reserves.” We anticipate that the percentage of our daily production and proved reserves attributable to the Eagle Ford shale will continue to grow in 2013 as we intend to allocate approximately 82% of our 2013
+11 
+Table of Contents 
+capital expenditure budget to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play, in an effort to continue growing the oil
+and liquids component of our production and reserves. 
+At December 31, 2012, we had drilled and completed a total of 32
+gross/30.5 net Eagle Ford wells on our operated properties, and all of these wells were producing to sales. At December 31, 2012, we had also participated in 3 gross/0.6 net Eagle Ford wells with EOG Resources, Inc. as operator, on portions of
+our Atascosa County acreage and 2 gross/0.6 net Eagle Ford wells with Hunt Oil Company as operator, on portions of our Wilson County acreage. 
+During the year ended December 31, 2012, we completed and began producing oil and natural gas from 25 gross/23.7 net operated Eagle Ford wells drilled on our acreage position in South Texas. As we
+completed and began producing oil and natural gas from these wells during 2012, our Eagle Ford production increased significantly. During the fourth quarter of 2011, our daily production from the Eagle Ford shale averaged 584 BOE per day, including
+378 Bbl of oil per day and 1.2 MMcf of natural gas per day. By comparison, during the fourth quarter of 2012, our daily oil production from the Eagle Ford shale averaged 5,363 BOE per day, including 4,545 Bbl of oil per day and 4.9 MMcf of natural
+gas per day. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other
+heavier natural gas liquids components. Our Eagle Ford wells typically yield three to seven gallons of natural gas liquids per thousand cubic feet of natural gas produced at the wellhead depending on the specific property. 
+During the year ended December 31, 2012, we believe that we increased our technical knowledge on how to drill, complete and produce
+Eagle Ford shale wells. Eagle Ford wells drilled on the eastern portion of our acreage in Karnes and DeWitt Counties are typically 1,000 to 2,500 feet deeper than wells drilled on the western portion of our acreage in LaSalle County. At
+December 31, 2012, the typical drilling time for wells on the western portion of our acreage ranged from 10 to 15 days from spud to rig release and the typical drilling time for wells on the eastern portion of our acreage ranged from 15 to 20
+days from spud to rig release. These drilling times compared to 20 to 30 days from spud to rig release for wells drilled in the earlier months of 2012. As a result of more efficient drilling and reduced completion costs, the overall drilling and
+completion costs associated with our Eagle Ford wells declined during 2012. At December 31, 2012, we estimate that the cost for us to drill and complete a 5,000-ft Eagle Ford shale well was approximately $6 million to $7 million on the western
+portion of our acreage in LaSalle County and approximately $8 million to $10 million on the eastern portion of our acreage in Karnes and DeWitt Counties. We believe the reduction in drilling and completion costs we achieved during 2012 was due in
+part to improved efficiencies in our own operations, as well as to declining service costs associated with an increase in the supply of drilling and completion services in South Texas during 2012. We do not anticipate that service costs will decline
+to the same extent in 2013, although we will continue to look for ways to improve the costs associated with our operations. 
+At December 31, 2012, our aggregate leasehold interests consisted of approximately 42,500 gross acres and 27,900 net acres in the
+Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, LaSalle, Wilson and Zavala Counties in South Texas. We believe portions of this acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we
+would expect to produce 
+12 
+Table of Contents 
+predominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate typically ranging in thickness from 200 to 400 feet, and the Buda formation,
+which is a naturally fractured carbonate typically ranging in thickness from 90 to 160 feet, have produced from several fields on or nearby portions of our acreage. 
+During the year ended December 31, 2012, we acquired approximately 5,500 gross and 3,400 net acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This
+acreage essentially replaced the acreage upon which we drilled and established oil and natural gas production and reserves during 2012. We also allowed approximately 11,800 gross and 4,300 net acres of our Eagle Ford leasehold position, primarily in
+Atascosa County, but also including acreage in northeast Webb and southeast Dimmit Counties, to expire undrilled during the year ended December 31, 2012, as we no longer considered this acreage to be economic for further exploration and
+development in the Eagle Ford shale at then-current commodity prices. 
+At December 31, 2012, we owned a 100% working
+interest in approximately 26,900 gross acres and 24,100 net acres in Gonzales, Karnes, LaSalle, Wilson and Zavala Counties and a 50% working interest in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of this
+acreage. We also owned an approximate 21% working interest in approximately 12,800 gross acres in Atascosa County operated by EOG Resources, Inc. At December 31, 2012, approximately 84% of our Eagle Ford acreage was either held by production or
+not burdened by lease expirations before 2014. 
+Between March and July 2011, we acquired leasehold interests in approximately
+6,300 gross and 4,800 net acres in DeWitt, Gonzales, Karnes and Wilson Counties in the Eagle Ford shale play from Orca ICI Development, JV (“Orca”). We initially acquired a 50% working interest in the acreage (approximately 2,800 gross and
+1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Gonzales, Karnes and Wilson Counties and are the operator. At December 31, 2012,
+we had drilled and completed 15 gross/12.7 net wells on this acreage. 
+At December 31, 2012, we had paid 100% of the
+costs to drill and complete the first six wells drilled on the acreage in DeWitt County. We have an 85% working interest in these six wells until we have recovered all of our acquisition, drilling, completion, facilities and operating costs from
+each well, at which time Orca’s working interest will increase to 50%. After we have recovered all of our acquisition, drilling, completion, facilities and operating costs, when the cumulative production from any of these first six wells
+reaches 500,000 BOE, on a well-by-well basis, then Orca’s working interest in that well will increase to 55%. If the cumulative production from any of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s working
+interest in that well will increase to 70%. Orca retains the right to pay its share of the costs and to participate for a 50% working interest in all subsequent wells drilled on the acreage in DeWitt County, and we have no further obligation to
+carry any of Orca’s costs in any subsequent well drilled on the acreage. Should Orca elect not to participate in a subsequent well that we propose to drill on the acreage, we will own a 100% working interest in the well until such time as we
+have recovered 400% of our acquisition, drilling, completion, facilities and operating costs from such well, at which time Orca’s working interest will increase to 50%. As of December 31, 2012, Orca had declined to participate in one
+subsequent well we drilled in DeWitt County, and we own an initial 100% working interest in this well. 
+At December 31,
+2012, we had paid 100% of the costs to drill and complete the first five wells drilled on the acreage in Gonzales, Karnes and Wilson Counties. We have a 100% working interest in these wells until we have recovered all of our acquisition, drilling,
+completion, facilities and operating costs from each of these five wells. After we have recovered all of our acquisition, drilling, completion, facilities and 
+13 
+Table of Contents 
+operating costs from any of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in such wells. In addition, Orca retained a one-time election for a
+short period of time after we completed these first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchase price equal to 25% of our costs to acquire the acreage in Gonzales, Karnes
+and Wilson Counties. Following the completion of these first five wells, Orca declined to exercise its right to participate in all future wells drilled on this acreage. As a result, we will have a 100% working interest, and Orca will have no
+interest, in all subsequent wells drilled on this acreage. At December 31, 2012, we had drilled or participated in a total of 8 gross/6.6 net wells on this specific acreage. 
+As we continue to explore and develop our leasehold positions in the Eagle Ford shale in South Texas, we may face challenges with
+establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we
+produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our
+current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during the year ended December 31, 2012, although we experienced these
+problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to
+the successful development and profitability of the Eagle Ford shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing
+Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans Within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations
+and Cash Flows.” 
+We did experience temporary pipeline and natural gas processing interruptions from time to time during
+the year ended December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. To alleviate most of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we
+entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the
+counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No
+assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these
+facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our
+Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and
+Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+In addition to the Eagle Ford potential on our acreage, we believe that approximately 22,800 gross acres and 17,500 net acres in South
+Texas are prospective primarily for the Austin Chalk and 15,600 gross and 10,500 net acres are prospective primarily for the Buda formation, which have historically been targeted by operators in South Texas. During the year ended December 31,
+2012, we completed and began 
+14 
+Table of Contents 
+producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or “Chalkleford,” intervals. Both of these wells were
+drilled on our acreage in Zavala County, which is in the heart of the historic Pearsall (Austin Chalk) Field where significant volumes of oil and natural gas have previously been produced from the Austin Chalk. Both of these wells are producing oil,
+but the results of these wells did not meet our expectations, with the upper Austin Chalk well apparently largely depleted by previous Austin Chalk production from nearby wells. We have not yet drilled an Austin Chalk well at any other location on
+our leasehold positions in South Texas, and although we believe that other prospective Austin Chalk well locations exist on this acreage, we have only included 17 gross and 17.0 net Austin Chalk well locations in our total identified drilling
+locations at December 31, 2012. We plan to drill an operated Austin Chalk exploratory test well on one of our leases in Gonzales County during 2013. At December 31, 2012, we had not included any Buda locations in our identified future drilling
+locations, although we do plan to participate in the drilling of an exploratory Buda test well on one of our leases in Atascosa County operated by EOG Resources, Inc. during the first quarter of 2013. 
+Northwest Louisiana and East Texas 
+As a result of substantially lower natural gas prices in 2012, we did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during
+the year ended December 31, 2012. We did, however, participate in the drilling and completion of 28 gross/1.1 net non-operated Haynesville shale wells in 2012, comprising about 3% of our total capital expenditures. We do not plan to drill any
+operated Haynesville wells in 2013, but we have budgeted capital expenditures of approximately $5.1 million for our participation in approximately 10 gross/0.5 net wells that we anticipate may be drilled by other operators on certain of our
+non-operated properties in 2013. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to
+be the core area of the Haynesville shale play. Of the approximately 5,700 net acres that we consider to be in the core area of the Haynesville play, we operate about 22% of that acreage. 
+For the year ended December 31, 2012, about 56% of our average daily production, or 5,042 BOE per day, including 31 Bbl of oil per
+day and 30.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. The vast majority of our natural gas production in 2012 was attributable to these properties. Natural gas production from
+these properties comprised approximately 88% of our daily natural gas production, but oil production from these properties only comprised about 1% of our daily oil production during 2012, as compared to 96% of our daily natural gas production and
+15% of our daily oil production during 2011. During the year ended December 31, 2011, approximately 92% of our daily production, or 6,459 BOE per day, including 64 Bbl of oil per day and 38.4 MMcf of natural gas per day, was attributable to our
+properties in Northwest Louisiana and East Texas. The decline in oil and particularly natural gas production from these properties over the past year reflects (i) the natural decline in production from these properties, (ii) the voluntary
+curtailment by the operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) our decision not to drill any operated Haynesville shale or Cotton Valley
+wells during 2012. 
+For the year ended December 31, 2012, about 76% of our daily natural gas production, or 26.0 MMcf of
+natural gas per day, was produced from the Haynesville shale, with another 12%, or 4.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations in this area. For the year ended December 31, 2011, about 81% of
+our daily natural gas production, or 32.3 MMcf of natural gas per day, was produced from the Haynesville shale, with another 15%, or 6.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties.
+15 
+Table of Contents 
+At December 31, 2012, approximately 33% of our estimated total proved reserves, or
+7.9 million BOE, were attributable to the Haynesville shale underlying this acreage with another 6% of our proved reserves, or 1.5 million BOE, associated with the Cotton Valley and shallower formations. As a result of substantially lower
+natural gas prices in 2012, we removed 97.8 Bcf (or 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, most of
+which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these
+previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices
+improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+During
+2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures
+contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest
+delivery date. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improve further from these levels, the costs to drill and complete these wells decline further
+from their recent levels or new technologies are developed that increase expected recoveries. See “Risk Factors — Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could
+Materially Alter the Occurrence or Timing of Their Drilling.” 
+Haynesville and Middle Bossier Shales 
+The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above
+the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and
+Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be
+productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although
+there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. 
+At December 31, 2012, we had leasehold and mineral interests in approximately 22,300 gross and 14,200 net acres prospective for the
+Haynesville shale. This acreage includes approximately 5,700 net acres in what we believe is the core area of the play. Over 99% of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are
+also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play as well. We
+have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations exist on this acreage, we have not included any Middle Bossier locations in our identified drilling locations at December 31, 2012.
+16 
+Table of Contents 
+Within the 5,700 net acres that we believe to be in the core area of the Haynesville shale
+play, we are the operator of approximately 1,200 net acres in two sections where we have working interests of 95% and 100%, respectively, in all wells to be drilled. We have identified 12 gross and 11.7 net potential additional Haynesville locations
+that we may drill and operate in the future in these two sections. The remainder of our acreage in the core area of the Haynesville shale play, about 4,500 net acres, is operated by other companies, including approximately half of our non-operated
+Haynesville acreage in this area of the play that is operated by a subsidiary of Chesapeake following a sale of a portion of our interest in July 2008. Including the acreage operated by a subsidiary of Chesapeake, our non-operated Haynesville
+acreage is attributable to leasehold interests that we hold in 81 sections in Caddo, DeSoto, Bossier and Red River Parishes in Northwest Louisiana. Our working interests in the Haynesville wells in these sections range from less than 1% to more than
+30%. 
+Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations 
+Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest
+Louisiana and East Texas were attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East
+Texas. 
+All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in Northwest Louisiana,
+approximately 10,000 gross and net acres at December 31, 2012, is held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to
+discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. 
+In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. on our Elm Grove/Caspiana properties,
+in DeSoto Parish and commenced sales of natural gas from this well. Based on the performance of this well and data available from public sources on other Cotton Valley horizontal wells drilled in this area of Northwest Louisiana, we believe that
+Cotton Valley horizontal wells drilled on our Elm Grove/Caspiana properties may have estimated ultimate natural gas recoveries of 4 to 6 Bcf. Prior to drilling this well, we had only drilled and completed vertical Cotton Valley and Hosston wells on
+these properties. We are the operator and have a 100% working interest in this well. We have identified 71 gross and 49.3 net additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove/Caspiana properties. We did not
+drill any of these locations in 2012 and do not plan to drill any of these locations in 2013. As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however,
+these Cotton Valley natural gas volumes remain available to be developed by us at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+We also continue to hold the shallow rights by existing production or by leases that are still in their primary terms in our Central and
+Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2012, we held an estimated 11,500 net leasehold and mineral acres by existing production in these areas. 
+Southeast New Mexico and West Texas — Delaware Basin 
+During 2012, we added to our acreage position in the Delaware Basin in Southeast New Mexico and West Texas, which is a mature exploration and production province with extensive developments in a wide
+variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of 
+17 
+Table of Contents 
+development in this basin has focused on relatively conventional reservoir targets, but we believe the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling
+and hydraulic fracturing technology is enhancing the development potential of this basin. 
+One example of such an opportunity
+appears to be the so-called “Wolf-Bone” play of the Delaware Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp formations span several thousand feet of stacked shales, sandstones, limestones and
+dolomites, representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural gas have been produced primarily from conventional sandstone and carbonate
+reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized by a number of operators as targets for horizontal
+drilling and multi-stage hydraulic fracturing techniques. As a result, several large industry players are expanding positions and conducting drilling programs throughout Eddy and Lea Counties in Southeast New Mexico and Loving, Pecos, Reeves and
+Ward Counties in West Texas. 
+For the year ended December 31, 2012, less than 1% of our average daily production, or only
+about 30 BOE per day, including 25 Bbl of oil per day and 30 Mcf of natural gas per day, was attributable to our leasehold properties in Southeast New Mexico and West Texas. At December 31, 2012, we held leasehold interests in approximately
+15,900 gross and 7,600 net acres in Southeast New Mexico and West Texas where we are developing new oil prospects. In particular, in August 2012, we acquired approximately 4,900 gross and 2,900 net acres prospective for the Wolfcamp and Bone Spring
+formations in Loving County, Texas, almost all of which is held by production from uphole formations to which we did not acquire the exploration and development rights. Subsequent to that time, we have added additional interests in this immediate
+area and at December 31, 2012, we held approximately 5,200 gross and 3,000 net acres in this leasehold position in Loving County. We have budgeted approximately $15.0 million of our anticipated 2013 capital expenditures to acquire additional
+leasehold interests prospective for oil and liquids production in Southeast New Mexico and West Texas. A portion of our leasehold interests in this area, including approximately 7,700 gross and 2,100 net acres in Winkler County, Texas, is no longer
+considered to be prospective by us, and we plan to let this acreage expire without drilling. 
+At December 31, 2012, we
+believe that approximately 8,200 gross and 5,500 net acres of our leasehold interests in the Delaware Basin are prospective for the Wolfcamp and Bone Spring formations, as well as other potential uphole targets, including the Avalon shale and
+Delaware sands, of which approximately 6,000 gross and 3,900 net acres are already held by existing production from other horizons by us or other operators. We believe that the Wolfcamp, Bone Spring, Avalon and Delaware formations are all
+prospective primarily for oil and that multiple intervals may be prospective within each target formation. We expect to begin exploring this acreage position during the second and third quarters of 2013, with plans to drill three exploratory test
+wells on this acreage in 2013. We have allocated approximately $35.6 million of our 2013 capital expenditure budget for these drilling and completion operations, including an estimated $5.4 million for pipelines, production facilities and related
+infrastructure. Two of these wells will test the Wolfcamp and one well will test the Second Bone Spring formation. 
+Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale 
+The Meade Peak shale is an organic-rich member of the Phosphoria formation, a source rock that is believed to have sourced much of the oil
+and natural gas in conventional reservoirs in the western Wyoming and eastern Utah area. The Phosphoria/Meade Peak shale has an observed shale thickness of 70 to 350 feet, total organic carbon values of 3% to 14% and vitrinite reflectance values
+ranging from 1.8% to 2.7%. The 
+18 
+Table of Contents 
+formation is encountered at depths of 3,000 to 14,000 feet, with the majority of our acreage in the depth range of 3,000 to 10,000 feet. The shale has been penetrated by over 100 wells in the
+area, most of which have natural gas shows. 
+We believe there have been no previous attempts to drill horizontally or to
+hydraulically fracture the Meade Peak shale in this area. Our focus to date has been to confirm the physical characteristics of the Meade Peak shale and evaluate its production potential. We have gathered well log data in the area, conducted a
+series of mapping evaluations of structural disposition and studied the petrophysical characteristics of the Meade Peak shale. In addition, we have purchased 2-D seismic data and conducted surface mapping studies using a structural geologist who has
+experience in the immediate area to better understand the area’s tectonic history. 
+At December 31, 2012, we held
+leasehold interests in approximately 55,300 gross and 27,200 net acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a
+combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are
+the operator of this prospect. We had no production, no proved reserves and no identified drilling locations attributable to this acreage at December 31, 2012. 
+At December 31, 2011, we held leasehold interests in approximately 144,000 gross and 136,000 net acres in this prospect, of which approximately 102,000 gross and 93,000 net acres were scheduled to
+expire at various times during 2012. Although we elected to take extensions or new leases on some portions of this expiring acreage during 2012, certain leases, particularly those taken on state lands, did not offer the opportunity for automatic
+extension and expired during 2012. Should we desire to reacquire mineral rights on these lands, we would need to seek new leases. 
+Along with our partners, we began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet,
+approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling, well logging
+and coring operations in November 2011. During 2012, we conducted detailed evaluations of the well logs and conducted special core analysis tests to better understand the petrophysical characteristics of the Meade Peak shale. 
+In September 2012, we entered into an agreement with our principal partner related to the ongoing exploration of the Meade Peak shale,
+pursuant to which our principal partner (i) paid us a prospect fee of $1.0 million, (ii) agreed to provide up to a total cost of $3.0 million (carrying our 50% share) for extensions of expiring leases and new leasing in the prospect in
+which we will have a 50% working interest at no cost to us and (iii) agreed to carry our 50% share of the drilling and completion costs associated with the horizontal lateral up to a total cost for these operations of $5.0 million, with each
+party paying 50% of all drilling and completion costs in excess of $5.0 million. In return for this consideration, in December 2012, we assigned 50% of our gross and net leasehold interests in the prospect to our principal partner. 
+In November 2012, we re-entered the Crawford Federal #1 vertical well and drilled a horizontal lateral from that wellbore into the Meade
+Peak shale approximately 2,500 feet in length. We temporarily suspended this well following drilling operations. We expect to return to this well in the third quarter of 2013 to conduct the completion operations on the horizontal lateral, which we
+expect will consist of three to 
+19 
+Table of Contents 
+four hydraulic fracture treatments along the length of the lateral. After the horizontal lateral is completed, we and our partners plan to test and evaluate this well before making further
+decisions concerning the future exploration of the Meade Peak shale in this prospect. 
+Operating Summary 
+The following table sets forth certain unaudited production data for the years ended December 31, 2012, 2011 and 2010: 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+Unaudited Production Data 
+Net Production Volumes: 
+Oil (MBbl) 
+1,214 
+154 
+33 
+Natural gas (Bcf) 
+12.5 
+14.5 
+8.4 
+Total oil equivalent (MBOE) (1) 
+3,294 
+2,573 
+1,433 
+Average daily production (BOE/d) (1) 
+9,000 
+7,049 
+3,926 
+Average Sales Prices: 
+Oil, with realized derivatives (per Bbl) 
+$ 
+103.55 
+$ 
+93.80 
+$ 
+76.39 
+Oil, without realized derivatives (per Bbl) 
+$ 
+101.86 
+$ 
+93.80 
+$ 
+76.39 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+3.55 
+$ 
+4.11 
+$ 
+4.38 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+2.59 
+$ 
+3.62 
+$ 
+3.75 
+Operating Expenses (per BOE): 
+Production taxes and marketing 
+$ 
+3.54 
+$ 
+2.44 
+$ 
+1.38 
+Lease operating 
+$ 
+8.56 
+$ 
+2.82 
+$ 
+3.69 
+Depletion, depreciation and amortization 
+$ 
+24.43 
+$ 
+12.34 
+$ 
+10.89 
+General and administrative 
+$ 
+4.42 
+$ 
+5.21 
+$ 
+6.77 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2012 from our primary operating areas: 
+Average Net Daily Production 
+Total
+Net 
+Production 
+(MBOE) (1) 
+Percentage of 
+Total
+Net 
+Production 
+Oil 
+(Bbl/d) 
+Gas 
+(Mcf/d) 
+Oil Equivalent 
+(BOE/d) (1) 
+South Texas: 
+Eagle Ford 
+3,246 
+3,976 
+3,908 
+1,431 
+43.4 
+% 
+Austin Chalk (2) 
+15 
+31 
+20 
+7 
+0.3 
+Area Total 
+3,261 
+4,007 
+3,928 
+1,438 
+43.7 
+NW Louisiana/E Texas: 
+Haynesville 
+1 
+26,007 
+4,336 
+1,587 
+48.2 
+Cotton Valley (3) 
+30 
+4,051 
+706 
+258 
+7.8 
+Area Total 
+31 
+30,058 
+5,042 
+1,845 
+56.0 
+SE New Mexico, West Texas 
+25 
+30 
+30 
+11 
+0.3 
+SW Wyoming, NE Utah, SE Idaho (4) 
+– 
+– 
+– 
+– 
+– 
+Total 
+3,317 
+34,095 
+9,000 
+3,294 
+100.0 
+% 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(4) 
+We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+20 
+Table of Contents 
+The following table sets forth information regarding our average net daily production and
+total production for the year ended December 31, 2011 from our primary operating areas: 
+Average Net Daily Production 
+Total
+Net 
+Production 
+(MBOE) (1) 
+Percentage of 
+Total
+Net 
+Production 
+Oil 
+(Bbl/d) 
+Gas 
+(Mcf/d) 
+Oil Equivalent 
+(BOE/d) (1) 
+South Texas: 
+Eagle Ford 
+331 
+1,298 
+548 
+200 
+7.8 
+% 
+Austin Chalk (2) 
+– 
+30 
+5 
+2 
+0.1 
+Area Total 
+331 
+1,328 
+553 
+202 
+7.9 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+32,319 
+5,387 
+1,966 
+76.4 
+Cotton Valley (3) 
+64 
+6,054 
+1,072 
+392 
+15.2 
+Area Total 
+64 
+38,373 
+6,459 
+2,358 
+91.6 
+SE New Mexico, West Texas 
+27 
+59 
+37 
+13 
+0.5 
+SW Wyoming, NE Utah, SE Idaho (4) 
+– 
+– 
+– 
+– 
+– 
+Total 
+422 
+39,760 
+7,049 
+2,573 
+100.0 
+% 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(4) 
+We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+Our total production of approximately 3.3 million BOE for the year ended December 31, 2012 was an increase of 28% over our
+total production of approximately 2.6 million BOE for the year ended December 31, 2011. This increased production was primarily due to drilling operations in the Eagle Ford shale. Our average daily production for the year ended
+December 31, 2012 was 9,000 BOE per day, as compared to 7,049 BOE per day for the year ended December 31, 2011. Our average daily oil production for the year ended December 31, 2012 was 3,317 Bbl of oil per day, an approximate
+eight-fold increase from 422 Bbl of oil per day for the year ended December 31, 2011. 
+21 
+Table of Contents 
+Producing Wells 
+The following table sets forth information relating to producing wells at December 31, 2012. Wells are classified as oil wells or natural gas wells according to their predominant production stream.
+We do not have any currently active dual completions. We have an approximate average working interest of 93% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 44%, and
+average approximately 8%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. 
+Oil Wells 
+Natural Gas Wells 
+Total Wells 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+35.0 
+29.7 
+2.0 
+2.0 
+37.0 
+31.7 
+Austin Chalk (1) 
+2.0 
+2.0 
+2.0 
+2.0 
+4.0 
+4.0 
+Area Total 
+37.0 
+31.7 
+4.0 
+4.0 
+41.0 
+35.7 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+– 
+134.0 
+12.7 
+134.0 
+12.7 
+Cotton Valley (2) 
+2.0 
+2.0 
+104.0 
+67.7 
+106.0 
+69.7 
+Area Total 
+2.0 
+2.0 
+238.0 
+80.4 
+240.0 
+82.4 
+SE New Mexico, West Texas 
+12.0 
+5.1 
+1.0 
+0.6 
+13.0 
+5.7 
+SW Wyoming, NE Utah, SE Idaho (3) 
+– 
+– 
+– 
+– 
+– 
+– 
+Total 
+51.0 
+38.8 
+243.0 
+85.0 
+294.0 
+123.8 
+(1) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(3) 
+We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+22 
+Table of Contents 
+Estimated Proved Reserves 
+The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2012, 2011 and 2010. The reserves estimates were based on evaluations prepared by our engineering
+staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves
+reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be
+attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids,
+which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 
+At December
+31, (1) 
+2012 
+2011 
+2010 
+Estimated Proved Reserves
+Data: (2) 
+Estimated proved reserves: 
+Oil (MBbl) 
+10,485 
+3,794 
+152 
+Natural Gas (Bcf) 
+80.0 
+170.4 
+127.4 
+Total (MBOE) (3) 
+23,819 
+32,196 
+21,387 
+Estimated proved developed reserves: 
+Oil (MBbl) 
+4,764 
+1,419 
+152 
+Natural Gas (Bcf) 
+54.0 
+56.5 
+43.1 
+Total (MBOE) (3) 
+13,771 
+10,843 
+7,342 
+Percent Developed 
+57.8 
+% 
+33.7 
+% 
+34.3 
+% 
+Estimated proved undeveloped reserves: 
+Oil (MBbl) 
+5,721 
+2,375 
+– 
+Natural Gas (Bcf) 
+26.0 
+113.9 
+84.3 
+Total (MBOE) (3) 
+10,048 
+21,353 
+14,045 
+PV-10 (4) (in millions) 
+$ 
+423.2 
+$ 
+248.7 
+$ 
+119.9 
+Standardized Measure (5) (in millions) 
+$ 
+394.6 
+$ 
+215.5 
+$ 
+111.1 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative
+transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for
+natural gas, for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas, and for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas. These
+prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. 
+(3) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(4) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2010, 2011 and 2012 may be reconciled to our Standardized Measure
+of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2010, 2011 and 2012 were, in millions, $8.8, $33.2,
+and $28.6, respectively. 
+(5) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+23 
+Table of Contents 
+Our proved oil reserves grew 176% (almost three-fold) from approximately 3.8 million
+Bbl at December 31, 2011 to approximately 10.5 million Bbl at December 31, 2012. This increase is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas. Proved oil reserves at
+December 31, 2012 comprised 44% of our total proved reserves as compared to only 12% at December 31, 2011. 
+Our
+total proved oil and natural gas reserves decreased from 32.2 million BOE at December 31, 2011 to 23.8 million BOE at December 31, 2012, reflecting primarily the decrease in our proved natural gas reserves from 170.4 Bcf at
+December 31, 2011 to 80.0 Bcf at December 31, 2012. This decrease in our proved natural gas reserves was primarily attributable to the decrease in our proved undeveloped natural gas reserves from 113.9 Bcf at December 31, 2011 to 26.0
+Bcf at December 31, 2012. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest
+Louisiana from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at
+December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available
+to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. The PV-10 of our total proved oil and natural gas
+reserves increased by 70% from $248.7 million at December 31, 2011 to $423.2 million at December 31, 2012. Our total proved reserves at December 31, 2012 were made up of approximately 44% oil and 56% natural gas as compared to 12% oil
+and 88% natural gas at December 31, 2011. 
+Our proved developed oil and natural gas reserves increased from
+10.8 million BOE at December 31, 2011 to 13.8 million BOE at December 31, 2012 due primarily to additions resulting from our drilling operations in the Eagle Ford shale. Our proved developed oil reserves increased from
+1.4 million Bbl at December 31, 2011 to 4.8 million Bbl at December 31, 2012 as a result of our drilling operations in the Eagle Ford shale. Our proved developed natural gas reserves declined from 56.5 Bcf (9.4 million BOE) at
+December 31, 2011 to 54.0 Bcf (9.0 million BOE) at December 31, 2012. The net increase of 3.0 million BOE in our proved developed reserves from December 31, 2011 to December 31, 2012 was composed of (1) additions of
+7.4 million BOE, including 4.7 million Bbl of oil and 16.2 Bcf of natural gas (2.7 million BOE), plus conversions of 0.4 million BOE, including 0.3 million Bbl of oil and 0.8 Bcf of natural gas (0.1 million BOE) from proved
+undeveloped to proved developed reserves, less (2) net oil and natural gas production of 3.3 million BOE, including 1.2 million Bbl of oil and 12.5 Bcf of natural gas (2.1 million BOE), less (3) downward revisions of proved
+developed reserves by 1.5 million BOE, including 0.5 million Bbl of oil and 6.2 Bcf of natural gas (1.0 million BOE). The downward revisions in proved developed natural gas reserves were primarily attributable to the lower natural gas
+prices used to estimate proved reserves at December 31, 2012 as compared to December 31, 2011. During the year ended December 31, 2012, we recorded no changes to proved developed reserves as a result of the acquisition or divestment
+of reserves. 
+Our proved undeveloped oil and natural gas reserves decreased from 21.4 million BOE at December 31,
+2011 to 10.1 million BOE at December 31, 2012. Our proved undeveloped oil reserves increased from 2.4 million Bbl at December 31, 2011 to 5.7 million Bbl at December 31, 2012 as a result of our drilling operations in
+the Eagle Ford shale. Our proved undeveloped natural gas reserves decreased from 113.9 Bcf (19.0 million BOE) at December 31, 2011 to 26.0 Bcf (4.3 million BOE) at December 31, 2012 due primarily to the removal of 97.8 Bcf (16.3 million
+BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana as a result of lower natural gas prices in 2012. The net decrease of 11.3 million BOE in our proved undeveloped reserves from
+December 31, 
+24 
+Table of Contents 
+2011 to December 31, 2012 is composed of (1) additions to proved undeveloped reserves of 5.5 million BOE, including 4.0 million Bbl of oil and 9.3 Bcf of natural gas (1.5
+million BOE) identified through drilling operations, less (2) the conversion of 0.4 million BOE of proved undeveloped reserves to proved developed reserves, including 0.3 million Bbl of oil and 0.8 Bcf of natural gas (0.1 million
+BOE), less (3) the net downward revisions of proved undeveloped reserves by 16.4 million BOE in the period, including 0.3 million Bbl of oil and 96.4 Bcf (16.1 million BOE). During the year ended December 31, 2012, we recorded no
+changes to proved undeveloped reserves as a result of the acquisition or divestment of reserves. At December 31, 2012, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking.
+The following table sets forth additional summary information by operating area with respect to our estimated net proved
+reserves at December 31, 2012: 
+Net Proved
+Reserves (1) 
+Oil 
+Gas 
+Oil 
+Equivalent 
+PV-10 (2) 
+Standardized 
+Measure (3) 
+(MBbl) 
+(Bcf) 
+(MBOE) (4) 
+(in millions) 
+(in millions) 
+South Texas: 
+Eagle Ford 
+10,358 
+23.8 
+14,331 
+393.2 
+366.6 
+Austin Chalk (5) 
+7 
+0.1 
+20 
+0.4 
+0.4 
+Area Total 
+10,365 
+23.9 
+14,351 
+393.6 
+367.0 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+47.1 
+7,856 
+21.8 
+20.3 
+Cotton Valley (6) 
+34 
+8.9 
+1,512 
+5.8 
+5.4 
+Area Total 
+34 
+56.0 
+9,368 
+27.6 
+25.7 
+SE New Mexico, West Texas 
+86 
+0.1 
+100 
+2.0 
+1.9 
+SW Wyoming, NE Utah, SE Idaho (7) 
+– 
+– 
+– 
+– 
+– 
+Total 
+10,485 
+80.0 
+23,819 
+423.2 
+394.6 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2012 may be reconciled to our Standardized Measure of discounted
+future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2012 were approximately $28.6 million. 
+(3) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+(4) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(5) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(6) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(7) 
+At December 31, 2012, we had no proved reserves attributable to our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+Technology Used to Establish Reserves 
+Under current SEC rules, proved reserves are those quantities of oil and natural gas, 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 economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of
+oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty 
+25 
+Table of Contents 
+can be established using techniques that have been proven 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 have been field tested and have been demonstrated to provide reasonably certain results with
+consistency and repeatability in the formation being evaluated or in an analogous formation. 
+In order to establish reasonable
+certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include,
+but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production
+performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both
+developed and undeveloped properties were forecast using either volumetric and/or analogy methods. 
+Internal Control Over
+Reserves Estimation Process 
+We maintain an internal staff of petroleum engineers and geoscience professionals to ensure
+the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Reserves Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over 16 years of industry experience. Our
+Reserves Manager received his Ph.D. degree in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a certificate of completion in a prescribed course of study in Reserves and
+Evaluation from Texas A&M University in May 2009. Our Vice President – Reservoir Engineering is responsible for reviewing and approving our reserves estimates and has over 35 years of industry experience. Following the preparation of our
+reserves estimates, we had our reserves estimates audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Engineering Committee of our board of directors reviews the reserves report
+and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by members of our board of directors, including members of our Audit Committee. 
+Acreage Summary 
+The
+following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2012. At that date, about 44% of our total net acreage had been developed, although these percentages are somewhat higher
+in South Texas and much higher in Northwest Louisiana and East Texas. 
+Developed Acres 
+Undeveloped Acres 
+Total Acres 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+18,236 
+15,736 
+24,220 
+12,175 
+42,456 
+27,911 
+Austin Chalk 
+8,892 
+8,892 
+13,893 
+8,573 
+22,785 
+17,465 
+Area Total (1) 
+18,236 
+15,736 
+24,220 
+12,175 
+42,456 
+27,911 
+NW Louisiana/E Texas: 
+Haynesville 
+19,286 
+11,178 
+2,995 
+2,995 
+22,281 
+14,173 
+Cotton Valley (2) 
+22,085 
+19,435 
+3,370 
+3,034 
+25,455 
+22,469 
+Area Total (3) 
+24,749 
+21,859 
+3,444 
+3,109 
+28,193 
+24,968 
+SE New Mexico, West Texas 
+1,160 
+991 
+14,700 
+6,600 
+15,860 
+7,591 
+SW Wyoming, NE Utah, SE Idaho 
+– 
+– 
+55,273 
+27,180 
+55,273 
+27,180 
+Total 
+44,145 
+38,586 
+97,637 
+49,064 
+141,782 
+87,650 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford
+shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for South Texas. 
+26 
+Table of Contents 
+(2) 
+Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas. 
+(3) 
+Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the
+Haynesville shale. Therefore, the sum of the net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Undeveloped Acreage Expiration 
+The following table sets forth the
+approximate number of gross and net undeveloped acres at December 31, 2012 that will expire prior to December 31, 2014 by operating area unless production is established within the spacing units covering the acreage prior to the expiration
+dates or unless the existing leases are renewed prior to expiration or unless continued operations maintain the leases beyond the expiration of each respective primary term. 
+Acres 
+Expiring 2013 
+Acres 
+Expiring 2014 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+8,832 
+4,455 
+3,903 
+613 
+Austin Chalk 
+5,260 
+3,689 
+589 
+89 
+Area Total (1) 
+8,832 
+4,455 
+3,903 
+613 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+– 
+33 
+33 
+Cotton Valley 
+– 
+– 
+– 
+– 
+Area Total (2) 
+– 
+– 
+33 
+33 
+SE New Mexico, West Texas 
+8,717 
+2,658 
+7,514 
+497 
+SW Wyoming, NE Utah, SE Idaho 
+5,882 
+2,861 
+– 
+– 
+Total 
+23,431 
+9,974 
+11,450 
+1,143 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford
+shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for South Texas. 
+(2) 
+Some of the same leases cover the gross and net acreage shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than the Haynesville
+shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless
+operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or unless production from the acreage has been established prior to such date, in which event the lease will remain in
+effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In
+addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not
+been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. Our leases are mainly fee leases with three to five years of primary term. We believe that our lease terms are similar to
+our competitors’ fee lease terms as they relate to both primary term and royalty interests. 
+27 
+Table of Contents 
+Drilling Results 
+The following table summarizes our drilling activity for the years ended December 31, 2012, 2011 and 2010: 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development Wells 
+Productive 
+36 
+17.1 
+30 
+0.6 
+5 
+1.7 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Exploration Wells 
+Productive 
+22 
+10.4 
+30 
+10.2 
+36 
+3.4 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Total Wells 
+Productive 
+58 
+27.6 
+60 
+10.8 
+41 
+5.1 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Marketing 
+Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a
+consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down
+independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. 
+Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at
+various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When
+there is an opportunity to do so, the mid-stream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a
+negotiated percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation
+fees. 
+The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations
+include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative
+fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices do adversely affect the
+carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled
+maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has
+historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the
+Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+28 
+Table of Contents 
+For the years ended December 31, 2012, 2011 and 2010, we had three significant
+purchasers that accounted for approximately 74%, 60% and 70%, respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the
+loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. 
+Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a
+significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the
+counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its firm natural gas transportation
+agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. 
+Under this agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year,
+we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas
+deficiency. We believe that our current and anticipated production from the wells covered by this agreement is sufficient to meet 80% of the maximum thermal quantity transportation and processing commitments under this agreement. 
+We were also party to one natural gas transportation agreement at December 31, 2012 that requires us to deliver a specified volume
+of natural gas through a pipeline for a fixed period of time. If we fail to meet the volume requirement, we are required to pay an amount to the owners of the pipeline to offset a portion of the expenses they incurred in building the pipeline to our
+well location. This contract does not constitute a material commitment. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by
+Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Title to Properties 
+We endeavor to assure that title to our properties is
+in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often
+will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of
+these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or
+affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, where required, or making lease rental payments or by producing oil and natural gas from wells in paying quantities prior to expiration of
+various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a
+Result of Title Deficiencies in the Properties in Which We Invest.” 
+29 
+Table of Contents 
+Competition 
+The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property
+acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other
+resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able
+to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be
+able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. 
+Our ability to drill and
+explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting
+field operations since 2004 while our competitors have a longer history of operations, and most of them have also demonstrated the ability to operate through industry cycles. 
+The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors
+— Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” 
+Regulation 
+Oil and Natural Gas Regulation 
+Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local
+laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of
+doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with
+the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict
+the impact of future government regulation on our properties or operations. 
+Texas, New Mexico, Louisiana, Wyoming, Idaho and
+Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have
+statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the
+regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states
+restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed
+price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. 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. 
+30 
+Table of Contents 
+Some of our oil and natural gas leases are issued by agencies of the federal government, as
+well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. 
+Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of
+transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as
+under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural
+gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
+In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act,
+among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly
+increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related
+regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. 
+Intrastate natural
+gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and
+services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our
+operations in any way that is materially different from our competitors that are similarly situated. 
+The price we receive
+from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though
+other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the
+effects, if any, of these regulations on our operations. 
+In 2007, the Energy Independence & Security Act of 2007, or
+the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations
+that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. 
+U.S. Federal and State Taxation 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions
+of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated 
+31 
+Table of Contents 
+with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning
+a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to
+eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We
+Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a
+Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” 
+Hydraulic Fracturing Policies and Procedures 
+We use hydraulic fracturing
+as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals.
+Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our horizontal wells are associated with hydraulic
+fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state
+laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic
+Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” 
+The protection of
+groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and
+federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). 
+Although
+rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue, running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed
+by pumping remedial cement jobs and other appropriate remedial measures. 
+The vast majority of hydraulic fracturing treatments
+are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate
+governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more
+environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture
+stimulation procedures. 
+While current fracture stimulation procedures utilize a significant amount of water, we typically
+recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal
+facilities in a way that is designed to avoid any impact to surface waters. 
+32 
+Table of Contents 
+Environmental Regulation 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells,
+are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety
+of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource
+Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to
+regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and
+criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some
+activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental
+laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. 
+The OPA 90 and
+its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the
+exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for
+removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure
+to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable
+requirements under the OPA 90 will not have a material adverse effect on us. 
+The CWA and comparable state laws impose
+restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be
+imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal
+National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and
+offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has 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. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other
+pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require
+certain oil-storing facilities to prepare plans and meet construction and operating standards. 
+33 
+Table of Contents 
+CERCLA, also known as the “Superfund” law, imposes liability, without regard to
+fault or the legality of the original conduct, on various 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 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 responsible for releases of hazardous substances under CERCLA may be subject to
+joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. 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 hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or
+handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for
+petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. 
+RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and
+nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration
+and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made
+to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state
+statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal
+requirements than are nonhazardous wastes. 
+The CAA, as amended, and comparable state laws restrict the emission of air
+pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain
+projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New
+Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for
+completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (VOC) emissions from natural gas not sent to the gathering line during well
+completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it
+available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish
+specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the
+installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business. 
+34 
+Table of Contents 
+Changes in environmental laws and regulations occur frequently, and any changes that result
+in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general.
+For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
+atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas
+emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and
+natural gas. 
+The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources
+under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on
+October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule
+that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas
+distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting
+obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our
+profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional
+greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of
+emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our
+business, financial condition, results of operations and cash flows. 
+Underground injection is the subsurface placement of
+fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil
+bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent
+migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate
+five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. 
+Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—
+Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing 
+35 
+Table of Contents 
+regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level
+pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass
+hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and
+recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption
+for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our
+financial condition, results of operations and cash flows. 
+In addition, in some states and localities, there has been a push
+to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of
+the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to
+assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. 
+The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground
+Injection Control Program. The EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released in December 2012, with final results expected in 2014. In addition, in December
+2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review, but such studies could result in additional regulatory
+scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. The BLM has indicated that it is considering proposed rules to regulate hydraulic fracturing on federal lands. Further,
+the EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on
+some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims
+associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that
+these costs will not result in material expenditures that adversely affect our profitability. 
+Additionally, in the course of
+our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural
+gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude
+oil and natural gas production and processing streams. Some states, including Texas, 
+36 
+Table of Contents 
+have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the
+operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 
+We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community
+right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain
+of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. 
+The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is
+listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife
+Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may
+materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted. 
+We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to
+our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws
+and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government
+Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.” 
+The clear
+trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2011 to 2013 is to focus on compliance by the energy
+extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material
+adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that
+we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. 
+We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not
+currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not
+fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 
+Office Lease 
+Our
+corporate headquarters are located in approximately 36,500 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The initial lease, as amended, expires on
+37 
+Table of Contents 
+June 30, 2022 and at December 31, 2012 covered approximately 29,000 square feet. On January 16, 2013, we entered into a fourth amendment to our office lease agreement to include
+approximately 7,800 square feet of additional space, increasing the size of our corporate headquarters from approximately 28,700 square feet to approximately 36,500 square feet. 
+Employees 
+At December 31, 2012, we had 50 full-time employees. We
+believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional
+services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services.
+Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant
+opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. 
+Available Information 
+Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report
+on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance
+Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a
+written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other
+report or document we file and any reference to our website is intended to be an inactive textual reference only. 
+38 
+Table of Contents 
+Item 1A. 
+Risk Factors. 
+Risks Related to the
+Oil and Natural Gas Industry and Our Business 
+Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas
+Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. 
+The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital
+expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in
+supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous
+factors. These factors include the following: 
+• 
+the domestic and foreign supply of oil and natural gas; 
+• 
+the domestic and foreign demand for oil and natural gas; 
+• 
+the prices and availability of competitors’ supplies of oil and natural gas; 
+• 
+the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production
+controls; 
+• 
+the price and quantity of foreign imports; 
+• 
+the impact of U.S. dollar exchange rates on oil and natural gas prices; 
+• 
+domestic and foreign governmental regulations and taxes; 
+• 
+speculative trading of oil and natural gas futures contracts; 
+• 
+the availability, proximity and capacity of gathering, processing and transportation systems for natural gas; 
+• 
+the availability of refining capacity; 
+• 
+the prices and availability of alternative fuel sources; 
+• 
+weather conditions and natural disasters; 
+• 
+political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America; 
+• 
+the continued threat of terrorism and the impact of military action and civil unrest; 
+• 
+public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate
+hydraulic fracturing activities; 
+• 
+the level of global oil and natural gas inventories and exploration and production activity; 
+• 
+the impact of energy conservation efforts; 
+• 
+technological advances affecting energy consumption; and 
+• 
+overall worldwide economic conditions. 
+Approximately 63% of our production during the year ended December 31, 2012 and 56% of our proved reserves at December 31, 2012 were attributable to natural gas. In addition, three of our
+largest assets or prospects — the Haynesville shale, Cotton Valley and Meade Peak shale — currently produce or are expected to produce predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices.
+39 
+Table of Contents 
+During 2012, natural gas prices declined to their lowest levels in many years, ranging from
+a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices had declined again
+since late November 2012 before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date. We would not expect to drill any operated natural gas wells, except for
+natural gas wells in specific exploration prospects like the Meade Peak shale, until natural gas prices improve further from these levels, the costs to drill and complete these wells decline further from their recent levels or new technologies are
+developed that increase expected recoveries. 
+In 2011, we began to focus on increasing our oil and liquids production.
+Specifically, our drilling opportunities in the Eagle Ford shale play in South Texas and our planned drilling opportunities in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas focus on oil and liquids. Approximately 37% of
+our production during the year ended December 31, 2012 and 44% of our proved reserves at December 31, 2012 were attributable to oil. We currently intend to allocate approximately 98% of our 2013 capital expenditure budget to opportunities
+prospective for oil and liquids production, including primarily the Eagle Ford shale and the Wolfcamp and Bone Spring plays. These opportunities are sensitive to changes in oil prices. 
+Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can
+produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil prices decrease to economically unattractive levels and remain there for an extended period of time or should natural gas prices decline further or
+remain at current levels, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from
+such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the
+borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount
+sufficient to cover such excess or repay the deficit in equal installments over a period of six months. 
+Drilling for and Producing Oil and
+Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business. 
+Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach
+certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of
+planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling, completing and operating processes. Before a well is spud, we may incur
+significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The
+analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs,
+we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. 
+40 
+Table of Contents 
+If we decide to drill a certain location, there is a risk that no commercially productive
+oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling,
+operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be
+economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction
+in production and reserves from, or abandonment of, the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following: 
+• 
+general economic and industry conditions, including the prices received for oil and natural gas; 
+• 
+shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; 
+• 
+potential drainage by operators on adjacent properties; 
+• 
+loss of or damage to oilfield development and service tools; 
+• 
+problems with title to the underlying properties; 
+• 
+increases in severance taxes; 
+• 
+adverse weather conditions that delay drilling activities or cause producing wells to be shut in; 
+• 
+domestic and foreign governmental regulations; and 
+• 
+proximity to and capacity of gathering, processing and transportation facilities. 
+If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows
+and reserves could be materially and adversely affected. 
+Our Exploration, Development and Exploitation Projects Require Substantial
+Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. 
+Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures
+in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash, operating cash flows and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all
+of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. 
+Although we currently have no plans to do so, we may sell additional equity securities or issue debt securities to raise capital. If we
+succeed in selling additional equity securities or securities convertible into equity securities to raise funds, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to
+those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. 
+Our cash flows from operations and access to capital are subject to a number of variables, including: 
+• 
+our estimated proved oil and natural gas reserves; 
+• 
+the amount of oil and natural gas we produce from existing wells; 
+41 
+Table of Contents 
+• 
+the prices at which we sell our production; 
+• 
+the costs of developing and producing our oil and natural gas reserves; 
+• 
+our ability to acquire, locate and produce new reserves; 
+• 
+the ability and willingness of banks to lend to us; and 
+• 
+our ability to access the equity and debt capital markets. 
+In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large
+company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely
+review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could
+adversely affect our access to funding for our operations in the future. 
+If our revenues decrease as a result of lower oil
+and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties
+or invest in certain exploration opportunities. Alternatively, to fund an acquisition, increase our rate of growth or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or
+equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable
+terms, our business, financial condition and future results of operations could be adversely affected. 
+We May Incur Additional
+Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. 
+At March 14, 2013, we had available borrowings of approximately $73.7 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined
+semi-annually by our lenders based primarily on the estimated value of our existing and future acquired oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates.
+Our Credit Agreement is secured by substantially all of our interests in our oil and natural gas properties and other assets and contains covenants restricting our ability to incur additional indebtedness, which may limit our ability to obtain
+additional financing. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to
+increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. 
+In the future, we may incur significant amounts of additional indebtedness, including under our Credit Agreement, in order to make
+acquisitions or to develop our properties. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. Our level of indebtedness could affect our operations in several ways,
+including the following: 
+• 
+a significant portion of our cash flows could be used to service our indebtedness; 
+42 
+Table of Contents 
+• 
+a high level of debt would increase our vulnerability to general adverse economic and industry conditions; 
+• 
+any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets,
+pay dividends and make certain investments; 
+• 
+a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take
+advantage of opportunities that our indebtedness may prevent us from pursuing; 
+• 
+our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and
+• 
+a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and
+general corporate or other purposes. 
+A high level of indebtedness increases the risk that we may default on
+our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our
+operations and our future performance. We may not be able to generate sufficient cash flows to pay the principal of or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such
+debt. Factors that will affect our ability to raise cash through an offering of our capital stock or debt securities or a refinancing of our debt include financial market conditions, the value of our assets, our oil and natural gas production and
+our performance at the time we need capital. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets or have a portion of our assets
+foreclosed upon which could have a material adverse effect on our business and financial results. 
+Our Operations Are Subject to
+Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. 
+There are numerous
+operational hazards inherent in oil and natural gas exploration, development, production and gathering, including: 
+• 
+unusual or unexpected geologic formations; 
+• 
+natural disasters; 
+• 
+adverse weather conditions; 
+• 
+unanticipated pressures; 
+• 
+loss of drilling fluid circulation; 
+• 
+blowouts where oil or natural gas flows uncontrolled at a wellhead; 
+• 
+cratering or collapse of the formation; 
+• 
+pipe or cement leaks, failures or casing collapses; 
+• 
+fires or explosions; 
+• 
+releases of hazardous substances or other waste materials that cause environmental damage; 
+• 
+pressures or irregularities in formations; and 
+• 
+equipment failures or accidents. 
+43 
+Table of Contents 
+In addition, there is an inherent risk of incurring significant environmental costs and
+liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of
+hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss
+of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial
+business centers and industrial sites, could significantly increase the level of damages resulting from these risks. 
+Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and
+completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available
+insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at
+commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to
+obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to
+large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows.
+We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells or in Production Activities, Which
+Could Adversely Affect Our Business. 
+While we are drilling and completing oil or natural gas wells or involved in
+production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a
+potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from, or abandonment of, the well. 
+Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in Production and Markets Relating to Any Property Could Have a Material Impact on Our Business.
+Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in
+South Texas and in Northwest Louisiana and East Texas. For the year ended December 31, 2012, 44% of our oil and natural gas production, including 99% of our average daily oil production was attributable to our properties in South Texas. At
+December 31, 2012, approximately 93% of the PV-10 of our proved reserves and 99% of our total proved oil reserves were attributable to our properties in South Texas, primarily in the Eagle Ford shale. We expect that most of our operations in
+the near future will be primarily in South Texas. 
+Even though we have entered into a firm five-year natural gas processing
+and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas, we may be disproportionately exposed to the impact of delays or interruptions of production from our
+wells in these areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation,
+44 
+Table of Contents 
+natural disasters, adverse weather conditions or plant closures for scheduled maintenance. In addition, the increased industry focus on the Eagle Ford shale may adversely impact our ability to
+process and transport our production due to increased competition for these facilities. 
+Our operations in South Texas may
+also be adversely affected by hurricanes and tropical storms resulting in delays in exploration and drilling, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a
+timely manner. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they
+might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash flows. 
+The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment
+and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash
+Flows. 
+Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay
+or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of
+other vendors to the industry. These costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to
+establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. 
+In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The
+accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment
+and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs could result and could adversely affect our business, financial condition, results of operations and
+cash flows. 
+If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to
+Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. 
+We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of
+water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations 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. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays,
+interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. 
+45 
+Table of Contents 
+Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would
+Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The rate of production from our
+oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our
+current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Eagle Ford shale play, an area in which our
+competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in this area and may experience such difficulty in other areas in the future. During periods of low oil
+and/or natural gas prices, existing reserves may no longer be economic. In addition, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our
+reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. 
+Our Oil
+and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and
+Present Value of Our Reserves. 
+The process of estimating accumulations of oil and natural gas is complex and inexact, due
+to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain
+economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: 
+• 
+the quality and quantity of available data; 
+• 
+the interpretation of that data; 
+• 
+the judgment of the persons preparing the estimate; and 
+• 
+the accuracy of the assumptions. 
+The accuracy of any estimates of proved reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future
+production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the
+estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and
+other factors. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating
+expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could
+materially affect the quantities and present value of our reserves. 
+46 
+Table of Contents 
+The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not
+Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. 
+It should not be
+assumed that the present value of future net cash flows included in this Annual Report on Form 10-K is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows
+from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately
+preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: 
+• 
+actual prices we receive for oil and natural gas; 
+• 
+actual costs and timing of development and production expenditures; 
+• 
+the amount and timing of actual production; and 
+• 
+changes in governmental regulations or taxation. 
+In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under Generally Accepted Accounting Principles, or GAAP, is not
+necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. 
+Approximately 43% of Our Total Proved Reserves at December 31, 2012 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those
+Reserves May Not Ultimately Be Developed or Produced. 
+At December 31, 2012, approximately 42% of our total proved
+reserves were undeveloped and approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have
+projected or at the costs we have budgeted. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues
+estimated for such reserves, resulting in some projects becoming uneconomical. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have
+to reclassify a portion of our proved reserves as unproved reserves, which could materially affect our business, financial condition, results of operations and cash flows. 
+Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. 
+Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill
+and develop these locations depends on a number of factors, including assessment of risks, costs, drilling results, oil and natural gas prices, the availability of equipment and capital, approval by regulators and seasonal conditions. The final
+determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of our drilling activities with respect to our established
+drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any
+other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our financial condition, results of operations and cash flows. 
+47 
+Table of Contents 
+Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next
+Several Years Unless Production Is Established on Units Containing the Acreage. 
+At December 31, 2012, we had
+leasehold interests in approximately 11,000 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2014. Unless we
+establish production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases will expire. If our leases expire, we will lose our right to develop the related properties. 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. In addition, on certain portions of our acreage, third party leases may have been taken and could become
+immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows.
+We May Not Increase Our Acreage Positions in Areas with Exposure to Oil, Condensate and Natural Gas Liquids. 
+If we are unable to increase our acreage positions in the Eagle Ford shale in South Texas or in the Wolfcamp and Bone Spring plays in
+Southeast New Mexico and West Texas, this may detract from our efforts to realize our growth strategy in oil and liquids-rich plays. Additionally, we may be unable to find or consummate other opportunities in these areas or in other areas with
+similar exposure to oil, condensate and natural gas liquids on similar terms or at all. 
+The 2-D and 3-D Seismic Data and Other Advanced
+Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. 
+We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These
+techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling
+unproductive wells based on these technologies. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows.
+We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty Obtaining Additional Data at a
+Reasonable Cost, Which Could Adversely Affect Our Results of Operations and Cash Flows. 
+We currently own only a limited
+amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that
+data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost. 
+Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel. 
+Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and
+select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, 
+48 
+Table of Contents 
+there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources
+substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or
+personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in
+recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality
+personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively.
+Our industry is subject to rapid and significant advancements in technology, including the introduction of new products
+and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In
+addition, many of our competitors will 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 cannot be certain
+that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.
+Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations.
+Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas
+interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These
+relationships are subject to change and, if they do, our ability to grow may be impaired. 
+To develop our business, we will
+endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that
+supply equipment and other resources that we expect to use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with
+strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not
+established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. 
+The
+Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and
+Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue. 
+The unavailability of satisfactory oil,
+natural gas and natural gas liquids gathering, processing and transportation arrangements may hinder our access to oil, natural gas and natural gas liquids markets or 
+49 
+Table of Contents 
+delay production from our wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for, and
+supply of, oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems,
+pipelines, processing facilities and oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut in wells for
+lack of a market or because of inadequate or unavailable pipelines, gathering systems or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our
+production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. 
+The disruption of third party facilities due to maintenance, weather or other factors could negatively impact our ability to market and
+deliver our oil, natural gas and natural gas liquids. The third parties control when or if such facilities are restored and what prices will be charged. We experienced temporary pipeline interruptions from time to time during the year ended
+December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. While we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a
+significant portion of our Eagle Ford acreage in South Texas, no assurance can be given that this agreement will alleviate these issues completely. We may experience similar interruptions and processing capacity constraints as we begin to explore
+and develop our Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these
+facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Financial
+Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets.
+We derive essentially all of our revenues from the sale of our oil, natural gas and natural gas liquids to unaffiliated
+third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and
+cash flows. 
+Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of
+our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a
+farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be
+required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.
+The Third Parties on Whom We Rely for Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other
+Laws that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. 
+The operations of the third
+parties on whom we rely for gathering, processing and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state
+and local government authorities. 
+50 
+Table of Contents 
+These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third party services are revised or
+reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely
+could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” 
+We Have Limited Control over Activities on Properties We Do Not Operate. 
+We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a
+subsidiary of Chesapeake Energy Corporation in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New
+Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest
+owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and
+timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: 
+• 
+timing and amount of capital expenditures; 
+• 
+the operator’s expertise and financial resources; 
+• 
+the rate of production of reserves, if any; 
+• 
+approval of other participants in drilling wells; and 
+• 
+selection and implementation or execution of technology. 
+In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of
+those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition,
+the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and
+associated revenues from these properties until the operator elects to return them to production. 
+A Component of Our Growth May Come
+through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. 
+We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. 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. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity
+financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage
+our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial
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+Table of Contents 
+position, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not
+successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted. 
+We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash
+on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our Credit Agreement includes covenants limiting our ability to incur additional debt. If we
+were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or
+geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. 
+We
+May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations.
+Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating
+costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or
+potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may
+not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume
+environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows
+could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. 
+We May Incur Losses or Costs as a
+Result of Title Deficiencies in the Properties in Which We Invest. 
+If an examination of the title history of a property
+that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired or other title deficiencies, our interest would be worth less than what we paid and may be
+worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. 
+It is our practice in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, not to undergo the
+expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work in
+examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. 
+Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a
+preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to
+correct deficiencies in the marketability of the title, and 
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+Table of Contents 
+such curative work entails expense. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from
+title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an
+interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows. 
+We
+May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition. 
+There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we
+have: 
+• 
+downward adjustments to our estimated proved reserves; 
+• 
+increases in our estimates of development costs; or 
+• 
+deterioration in our exploration and development results. 
+We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less
+related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved
+reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the
+excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, but it does reduce the book value of our net tangible assets, retained earnings and
+shareholders’ equity and could lower the value of our common stock. 
+Hedging Transactions, or the Lack Thereof, May Limit Our
+Potential Gains and Could Result in Financial Losses. 
+To manage our exposure to price risk, we, from time to time, enter
+into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option which is
+financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call
+option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in
+the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the
+maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged. 
+In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in
+which our production is less than expected or the counterparties to our put and call option contracts fail to perform under the contracts. 
+53 
+Table of Contents 
+Disruptions in the financial markets could lead to sudden changes in a counterparty’s
+liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict
+sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. 
+Furthermore, there may be
+times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production
+and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued
+application of our current strategies nor our use of different hedging strategies may be successful. 
+An Increase in the Differential
+between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as
+NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead
+prices we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience
+in respect of our production. As such, we will be exposed to any increase in such differentials. 
+We Are Subject to Government Regulation
+and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. 
+The exploration,
+development, production and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include
+discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and
+regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for: 
+• 
+personal injuries; 
+• 
+property damage; 
+• 
+containment and clean-up of oil and other spills; 
+• 
+management and disposal of hazardous materials; 
+• 
+remediation, clean-up costs and natural resource damages; and 
+• 
+other environmental damages. 
+We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or
+termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed
+frequently and the changes often include increasingly stringent requirements. 
+54 
+Table of Contents 
+These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be
+liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In
+addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged
+non-compliance with certain of these laws, rules and regulations. 
+We Are Subject to Federal, State and Local Taxes, and May Become Subject
+to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our
+Business, Financial Condition, Results of Operations and Cash Flows. 
+The federal, state and local governments in the
+areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or
+state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax
+proposals. 
+Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently
+available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain 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 or manufacturing activities and (iv) the increase in the amortization period for geological and
+geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural
+gas exploration and production companies like ours. President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. The passage of any legislation as a
+result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively
+impact our financial condition, results of operations and cash flows. 
+Federal and State Legislation and Regulatory Initiatives Relating to
+Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. 
+In past sessions,
+Congress has considered, but did not pass, legislation to amend the Safe Drinking Water Act, or SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing diesel) and to
+require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock
+formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to produce oil, natural gas and natural gas liquids from formations such as the Eagle Ford and the Haynesville shales, where we focus our operations, and
+we anticipate using hydraulic fracturing in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas. The EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on
+drinking water and groundwater. A progress report was released in December 2012, with final results expected in 2014. In addition, in 
+55 
+Table of Contents 
+December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming. Consequently, even if federal
+legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action towards federal legislation and regulation of hydraulic fracturing or similar production operations. Also at the
+federal level, the BLM has indicated that it is considering proposed rules to regulate hydraulic fracturing on federal lands. Additionally, the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing
+the disclosure of hydraulic fracturing chemicals. 
+In addition, a number of states and local regulatory authorities are
+considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, which could include a moratorium on drilling and effectively prohibit further production of oil and natural gas through the use of hydraulic
+fracturing or similar operations. Texas and Wyoming have adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process. This legislation and any implementing regulations could
+increase our costs of compliance and doing business. 
+The adoption of new laws or regulations imposing reporting obligations
+on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional resource plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result
+of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely
+affect our business and results of operations. 
+Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in
+Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding
+to Those Effects. 
+The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse
+gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has adopted rules under
+the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with
+the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published 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. On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems.
+Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports filed in 2012. 
+In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity
+of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected.
+Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects or increased
+costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided
+by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to 
+56 
+Table of Contents 
+recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require
+large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable
+Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and
+quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. 
+New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. 
+On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source
+Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of
+hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (VOC) emissions from natural gas not sent to the gathering line during well completion either by
+flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale,
+which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements,
+effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to
+control emissions. We are currently evaluating the effect these rules will have on our business. 
+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.
+There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse
+gases from a wide range of sources. Any such legislation could adversely affect demand for the oil, natural gas and natural gas liquids that we produce. 
+A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It 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 NGA exempts natural gas gathering facilities from regulation by
+FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas
+company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services 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. A change in the jurisdictional characterization by FERC, the courts or Congress or a change in policy by FERC or Congress may result in increased regulation of our assets, which may
+cause our revenues to decline and operating expenses to increase. 
+57 
+Table of Contents 
+Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders,
+We Could Be Subject to Substantial Penalties and Fines. 
+Under the Energy Policy Act, FERC has civil penalty authority
+under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. The nature of our gathering facilities is such that we have not yet been regulated
+by FERC as a natural gas company subject to the provisions of the NGA. It is possible, however, that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to
+comply with those laws, rules and regulations in the future could subject us to civil penalty liability. 
+The Derivatives Legislation
+Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. 
+On
+July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act,
+among other things, sets forth a framework for regulating certain derivative products including commodity hedges of the type we use, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result,
+it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with
+respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the
+implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our
+counterparties and may increase the cost of our derivative arrangements in the future. 
+If these types of commodity hedges
+become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could
+also materially affect our ability to conduct acquisitions. 
+We May Have Difficulty Managing Growth in Our Business, Which Could Have a
+Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. 
+Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our
+activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management
+resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers,
+geoscientists, petroleum engineers and landmen, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. 
+58 
+Table of Contents 
+Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our
+Chairman of the Board, Chief Executive Officer and President, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt
+Our Business Operations. 
+Investors in our common stock must rely upon the ability, expertise, judgment and discretion of
+our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and
+technical personnel, including our Chairman, President and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as
+effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel
+resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any
+insurance against the loss of any of these individuals. 
+We have an active board of directors that meets at least quarterly
+throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further
+development. Many of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to
+find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. 
+In
+addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role
+in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. 
+Our Management Team Owns Approximately 11% of Our Common Stock, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the
+Interests of Our Management Could Differ from Other Shareholders. 
+Our directors and officers beneficially own
+approximately 11% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our
+certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely
+affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and officers may be able to remain entrenched in their positions. 
+59 
+Table of Contents 
+Risks Relating to Our Common Stock 
+The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. 
+Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2012, our stock price fluctuated between a high of $12.33 and a low of $7.70. In the future,
+the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our
+common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of
+our common stock. 
+Factors that could affect our stock price or result in fluctuations in the market price or trading volume
+of our common stock include: 
+• 
+our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates;
+• 
+quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies
+that are perceived to be similar to us; 
+• 
+changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; 
+• 
+speculation in the press or investment community; 
+• 
+public reaction to our press releases, announcements and filings with the SEC; 
+• 
+sales of our common stock by us or shareholders, or the perception that such sales may occur; 
+• 
+general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices;
+• 
+the realization of any of the risk factors presented in this Annual Report on Form 10-K; 
+• 
+the recruitment or departure of key personnel; 
+• 
+commencement of or involvement in litigation; 
+• 
+the prices of oil, natural gas and natural gas liquids; 
+• 
+the success of our exploration and development operations, and the marketing of any oil, natural gas and natural gas liquids we produce;
+• 
+changes in market valuations of companies similar to ours; and 
+• 
+domestic and international economic, legal and regulatory factors unrelated to our performance. 
+The Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended,
+and the Requirements of the Sarbanes-Oxley Act of 2002, Have Increased Our Costs and Occupy a Significant Amount of Management’s Time. 
+As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related
+regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE. Complying 
+60 
+Table of Contents 
+with these statutes, regulations and requirements is difficult and occupies a significant amount of time of our board of directors and management and has significantly increased our costs and
+expenses. 
+If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our
+Financial Results Could Be Adversely Affected. 
+Until February 2012, we were a private company and maintained
+internal controls and procedures in accordance with being a private company. We maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal control over financial
+reporting. In connection with our audits for the years ended December 31, 2011 and 2010, our independent registered public accountants identified and communicated material weaknesses. There were no material weaknesses identified in connection
+with our audit for the year ended December 31, 2012. 
+A material weakness is a control deficiency, or a combination of
+control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected and corrected on a timely
+basis. 
+Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective
+controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to avoid material
+weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the
+SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. 
+We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. 
+We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends
+will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends
+and other considerations that our board of directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain
+covenants in our Credit Agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is
+no guarantee that the price of our common stock will exceed the price you paid. 
+The Trading Volume of Our Common Stock Has Been Low, and
+the Sale of a Substantial Number of Shares in the Public Market Could Depress the Price of Our Common Stock. 
+Our common
+stock is listed on the NYSE, but since the completion of our initial public offering, it has had a low average daily trading volume relative to many other stocks. Thinly traded stock can be more volatile than stock trading in an active public
+market, which can lead to significant price swings even when a relatively small number of shares are being traded and can limit an investor’s ability to quickly sell blocks of stock. 
+61 
+Table of Contents 
+Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common
+Stock by Us Could Depress the Price of Our Common Stock. 
+The market price of our common stock could decline as a result
+of sales of a large number of shares of our common stock in the market, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell,
+substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a
+price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. 
+We may also sell additional shares of common stock or securities convertible into common stock. We cannot predict the size of future issuances of our common stock or convertible securities or the effect,
+if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. 
+Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders.
+Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or
+acquisition that our shareholders may consider favorable. These provisions include: 
+• 
+authorization for our board of directors to issue preferred stock without shareholder approval; 
+• 
+a classified board of directors so that not all members of our board of directors are elected at one time; 
+• 
+the prohibition of cumulative voting in the election of directors; and 
+• 
+a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock.
+Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us,
+which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any affiliated shareholder, cannot acquire us for a period of three years from the date this
+person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our board of directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our
+outstanding voting shares not beneficially owned by the affiliated shareholder. 
+Our Board of Directors Can Authorize the Issuance of
+Preferred Stock, which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. 
+Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences
+and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise
+adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a
+change of control of the company, even if that change of control might benefit our shareholders. 
+62 
+Table of Contents 
+Item 1B. 
+Unresolved Staff Comments. 
+Not applicable. 
+Item 2. 
+Properties. 
+See
+“Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See “Note 13 – Commitments and Contingencies ” to the consolidated
+financial statements in this Annual Report on Form 10-K for the future minimum rental payments. Such information is incorporated herein by reference. 
+Item 3. 
+Legal Proceedings. 
+See
+“Note 13 – Commitments and Contingencies ” to the consolidated financial statements in this Annual Report on Form 10-K. Such information is incorporated herein by reference. 
+Item 4. 
+Mine Safety Disclosures. 
+Not applicable. 
+63 
+Table of Contents 
+PART II 
+Item 5. 
+Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+General Market Information 
+Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since
+February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+On
+March 14, 2013, we had 55,894,438 shares of common stock outstanding held by approximately 444 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. 
+The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated:
+2012 
+High 
+Low 
+First Quarter 
+$ 
+12.33 
+$ 
+10.85 
+Second Quarter 
+12.09 
+8.63 
+Third Quarter 
+11.53 
+9.41 
+Fourth Quarter 
+10.50 
+7.70 
+On March 14, 2013, the last reported sales price of our common stock on the NYSE was $8.80 per
+share. 
+Dividend Policy 
+We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our
+business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition,
+certain covenants in our Credit Agreement may limit our ability to pay dividends on our common stock. 
+Prior to the
+consummation of our initial public offering on February 7, 2012, the holders of our Class B common stock were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of
+dividends. These dividends accrued and were payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding. For the year ended December 31, 2011, we declared dividends on our outstanding shares of Class B common
+stock totaling $274,853. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of our initial public offering, the right of the holders of Class B common stock to dividends was terminated and such holders
+were paid approximately $28,000 during the first quarter of 2012 for all accrued but unpaid dividends existing at the time of such conversion. 
+64 
+Table of Contents 
+Equity Compensation Plan Information 
+The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2012.
+Equity Compensation Plan
+Information 
+Plan Category 
+Number of 
+Shares to be 
+Issued Upon 
+Exercise
+of 
+Outstanding 
+Options, 
+Warrants 
+and 
+Rights 
+Weighted- 
+Average 
+Exercise 
+Price of 
+Outstanding 
+Options, 
+Warrants 
+and
+Rights 
+($) 
+Number of 
+Shares 
+Remaining 
+Available for 
+Future 
+Issuance 
+Under
+Equity 
+Compensation 
+Plans 
+Equity compensation plans approved by security holders (1)
+(2) 
+1,229,437 
+$ 
+10.19 
+3,056,957 
+Equity compensation plans not approved by security holders 
+– 
+– 
+– 
+Total 
+1,229,437 
+$ 
+10.19 
+3,056,957 
+(1) 
+Our board of directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan.
+(2) 
+Our 2012 Long-Term Incentive Plan was approved by our board of directors in December 2011 and took effect on January 1, 2012. The 2012 Long-Term Incentive Plan was
+also approved by our shareholders at the Annual Meeting of Shareholders on June 7, 2012. For a description of our 2012 Long-Term Incentive Plan, see “ Note 8 – Stock-Based Compensation” to the consolidated financial
+statements in this Annual Report on Form 10-K. 
+Share Performance Graph 
+The following graph compares the cumulative return on a $100 investment in our common stock from February 2, 2012, the date our
+common stock began trading on the NYSE, through December 31, 2012, to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return,
+reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Securities
+Exchange Act of 1934, as amended (the “Exchange Act”), whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s
+disclosure rules. This historic stock performance is not indicative of future stock performance. 
+65 
+Table of Contents 
+Comparison of Cumulative Total Return Among 
+Matador Resources Company, the Russell 2000 Index 
+and the Russell 2000 Energy Index 
+Item 6. 
+Selected Financial Data. 
+You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial
+Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K. The financial information included in this Annual Report on Form 10-K may
+not be indicative of our future results of operations, financial position or cash flows. 
+66 
+Table of Contents 
+The following selected financial information is summarized from our results of operations
+for the five-year period ended December 31, 2012 and selected consolidated balance sheet data at December 31, 2012, 2011, 2010, 2009 and 2008 and should be read in conjunction with the consolidated financial statements for the years ended
+December 31, 2012, 2011 and 2010 included herewith. 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+(In thousands, except per share data) 
+Statement of operations data: 
+Revenues: 
+Oil and natural gas revenues 
+$ 
+155,998 
+$ 
+67,000 
+$ 
+34,042 
+$ 
+19,039 
+$ 
+30,645 
+Realized gain (loss) on derivatives 
+13,960 
+7,106 
+5,299 
+7,625 
+(1,326 
+) 
+Unrealized (loss) gain on derivatives 
+(4,802 
+) 
+5,138 
+3,139 
+(2,375 
+) 
+3,592 
+Total revenues 
+165,156 
+79,244 
+42,480 
+24,289 
+32,911 
+Expenses: 
+Production taxes and marketing 
+11,672 
+6,278 
+1,982 
+1,077 
+1,639 
+Lease operating 
+28,184 
+7,244 
+5,284 
+4,725 
+4,667 
+Depletion, depreciation and amortization 
+80,454 
+31,754 
+15,596 
+10,743 
+12,127 
+Accretion of asset retirement obligations 
+256 
+209 
+155 
+137 
+92 
+Full-cost ceiling impairment 
+63,475 
+35,673 
+– 
+25,244 
+22,195 
+General and administrative 
+14,543 
+13,394 
+9,702 
+7,115 
+8,252 
+Total expenses 
+198,584 
+94,552 
+32,719 
+49,041 
+48,972 
+Operating (loss) income 
+(33,428 
+) 
+(15,308 
+) 
+9,761 
+(24,752 
+) 
+(16,061 
+) 
+Other income (expense): 
+Net (loss) gain on asset sales and inventory impairment 
+(485 
+) 
+(154 
+) 
+(224 
+) 
+(379 
+) 
+136,978 
+Interest expense 
+(1,002 
+) 
+(683 
+) 
+(3 
+) 
+– 
+– 
+Interest and other income 
+224 
+315 
+364 
+781 
+2,984 
+Total other (expense) income 
+(1,263 
+) 
+(522 
+) 
+137 
+402 
+139,962 
+Net (loss) income 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+$ 
+103,878 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+$ 
+2.50 
+Class B 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+$ 
+2.77 
+Diluted 
+Class A 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+$ 
+2.46 
+Class B 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+$ 
+2.73 
+Class B dividend declared, per share 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+67 
+Table of Contents 
+At December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+(In thousands) 
+Balance sheet data: 
+Cash and cash equivalents 
+$ 
+2,095 
+$ 
+10,284 
+$ 
+21,060 
+$ 
+104,230 
+$ 
+150,768 
+Certificates of deposit 
+230 
+1,335 
+2,349 
+15,675 
+20,782 
+Net property and equipment 
+591,090 
+399,865 
+303,880 
+142,078 
+125,261 
+Total assets 
+632,029 
+439,469 
+346,382 
+277,400 
+314,539 
+Current liabilities 
+96,492 
+74,576 
+30,097 
+8,868 
+35,475 
+Long-term liabilities 
+156,433 
+93,378 
+34,408 
+4,211 
+2,059 
+Total shareholders’ equity 
+$ 
+379,104 
+$ 
+271,515 
+$ 
+281,877 
+$ 
+264,321 
+$ 
+277,005 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+(In thousands) 
+Other financial data: 
+Net cash provided by operating activities 
+$ 
+124,228 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+$ 
+25,851 
+Net cash (used in) provided by investing activities 
+(306,916 
+) 
+(160,088 
+) 
+(147,334 
+) 
+(49,415 
+) 
+115,481 
+Oil and natural gas properties capital expenditures 
+(300,689 
+) 
+(156,431 
+) 
+(159,050 
+) 
+(54,244 
+) 
+(104,119 
+) 
+Expenditures for other property and equipment 
+(7,332 
+) 
+(4,671 
+) 
+(1,610 
+) 
+(307 
+) 
+(3,012 
+) 
+Net cash provided by financing activities 
+174,499 
+87,444 
+36,891 
+1,086 
+419 
+Adjusted EBITDA (1) 
+$ 
+115,923 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+$ 
+18,411 
+(1) 
+Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash
+provided by operating activities, see “Non-GAAP Financial Measures” below. 
+Non-GAAP Financial
+Measures 
+We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and
+amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, including stock option and grant expense and
+restricted stock and restricted stock units expense and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP
+financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. 
+Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing
+methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these amounts can vary substantially from company to company within our industry depending upon accounting methods and
+book values of assets, capital structures and the method by which certain assets were acquired. 
+Adjusted EBITDA should not be
+considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA
+are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company
+because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash
+provided by operating activities, respectively. 
+68 
+Table of Contents 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+(In thousands) 
+Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): 
+Net (loss) income 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+$ 
+103,878 
+Interest expense 
+1,002 
+683 
+3 
+– 
+– 
+Total income tax (benefit) provision 
+(1,430 
+) 
+(5,521 
+) 
+3,521 
+(9,925 
+) 
+20,023 
+Depletion, depreciation and amortization 
+80,454 
+31,754 
+15,596 
+10,743 
+12,127 
+Accretion of asset retirement obligations 
+256 
+209 
+155 
+137 
+92 
+Full-cost ceiling impairment 
+63,475 
+35,673 
+– 
+25,244 
+22,195 
+Unrealized loss (gain) on derivatives 
+4,802 
+(5,138 
+) 
+(3,139 
+) 
+2,375 
+(3,592 
+) 
+Stock option and grant expense 
+(589 
+) 
+2,362 
+824 
+622 
+605 
+Restricted stock and restricted stock units expense 
+729 
+44 
+74 
+34 
+60 
+Net loss (gain) on asset sales and inventory impairment 
+485 
+154 
+224 
+379 
+(136,977 
+) 
+Adjusted EBITDA 
+$ 
+115,923 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+$ 
+18,411 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+2009 
+2008 
+(In thousands) 
+Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: 
+Net cash provided by operating activities 
+$ 
+124,228 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+$ 
+25,851 
+Net change in operating assets and liabilities 
+(9,307 
+) 
+(12,594 
+) 
+(2,230 
+) 
+15,717 
+(17,888 
+) 
+Interest expense 
+1,002 
+683 
+3 
+– 
+– 
+Current income tax (benefit) provision 
+– 
+(46 
+) 
+(1,411 
+) 
+(2,324 
+) 
+10,448 
+Adjusted EBITDA 
+$ 
+115,923 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+$ 
+18,411 
+69 
+Table of Contents 
+Item 7. 
+Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our
+consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected
+performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results
+to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves
+and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering,
+processing and transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report
+on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” 
+Overview 
+We are an
+independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other
+unconventional resource plays. Our current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas and in the Haynesville shale play in Northwest Louisiana. In 2012, more than 90% of our total
+capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we sought to transition to a more balanced commodity portfolio through the drilling of wells that were prospective for oil
+and liquids. For the year ended December 31, 2012, approximately 37% of our total production by volume (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) and 79% of our total oil and natural gas revenues were attributable
+to oil production, primarily from the Eagle Ford shale. In 2013, we expect that approximately 82% of our estimated capital expenditures of $310.0 million will be directed to increasing our oil production and oil reserves in South Texas, primarily in
+the Eagle Ford shale play. Although we did not drill any operated Haynesville shale natural gas wells during 2012, we directed approximately 3% of our capital expenditures to the Haynesville play in 2012 to participate in several non-operated wells.
+In addition to these primary operating areas, we have a growing acreage position in Southeast New Mexico and West Texas where we plan to drill three exploratory wells to test the Wolfcamp and Bone Spring plays during 2013. We also have a large
+exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale. 
+On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common
+stock at $12.00 per share (the “Initial Public Offering”). We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold pursuant to the partial
+exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory
+developments, as well as competition from other sources of energy. 
+70 
+Table of Contents 
+Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which is impacted by overall economic
+activity, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Prices for oil, natural gas and natural gas liquids will affect the cash flows available to us for capital
+expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices would not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that
+we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. 
+During 2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November,
+based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry
+Hub natural gas futures contract for the earliest delivery date. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improve further from these levels or unless
+the costs to drill and complete these wells decline further from their recent levels or new technologies are developed that increase expected recoveries. See “Risk Factors — Our Identified Drilling Locations Are Scheduled out over Several
+Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” 
+In 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas, as
+we continued to execute our strategy to significantly increase our oil production and oil reserves during 2012. During the year ended December 31, 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net Eagle Ford
+shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin
+Chalk/upper Eagle Ford, or “Chalkleford,” intervals in 2012. In addition, during 2012, we completed and began producing natural gas from 28 gross/1.1 net non-operated Haynesville shale wells. We also re-entered and drilled a horizontal
+lateral from the previously suspended Crawford Federal #1 vertical well in Southwest Wyoming; we plan to complete this well in the third quarter of 2013. 
+We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract), and
+almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. We did not drill any operated wells in the Haynesville shale play in Northwest Louisiana during 2012 as a result of the decline in natural gas prices
+compared to recent years. At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County. 
+Our average daily production for the year ended December 31, 2012 was approximately 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, as compared to 7,049
+BOE per day, including 422 Bbl of oil per day and 39.8 MMcf of natural gas per day for the year ended December 31, 2011. Our total oil production increased almost eight-fold to just over 1.2 million Bbl of oil during the year ended
+December 31, 2012, from approximately 154,000 Bbl of oil during the year ended December 31, 2011. This increased oil production is a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised approximately
+37% of our total production for the year ended December 31, 2012, as compared to only 6% of our total production for the year ended December 31, 2011. 
+71 
+Table of Contents 
+During the three months ended December 31, 2012 specifically, our average daily production
+was 10,385 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day. This was an increase of almost 50% compared to our average daily production for the three months ended December 31, 2011 of 6,953 BOE per day,
+including 448 Bbl of oil per day and 39.0 MMcf of natural gas per day. Our total oil production increased ten-fold to 426,000 Bbl of oil during the three months ended December 31, 2012, as compared to total oil production of 41,000 Bbl of oil
+during the three months ended December 31, 2011. Our average daily production for the fourth quarter of 2012 was a sequential increase of 18% from the average daily production of 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3
+MMcf of natural gas per day, achieved during the third quarter of 2012. For the three months ended December 31, 2012, our oil production grew 41% sequentially, as compared to the three months ended September 30, 2012. 
+At December 31, 2012, our estimated total proved reserves were 23.8 million BOE, including 10.5 million Bbl of oil and
+80.0 Bcf of natural gas (13.3 million BOE). At December 31, 2012, 58% of our total proved reserves were proved developed reserves compared to 34% at December 31, 2011. At December 31, 2012, 44% of our total proved reserves were oil
+and 56% of our total proved reserves were natural gas, as compared to 12% oil and 88% natural gas at December 31, 2011. Our proved oil reserves grew 176% (almost three-fold) from 3.8 million Bbl at December 31, 2011 to
+10.5 million Bbl at December 31, 2012. This growth in oil reserves was attributable to our drilling program in the Eagle Ford shale during 2012. Our proved natural gas reserves declined to 80.0 Bcf at December 31, 2012 from 170.4 Bcf
+at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana
+from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these
+previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices
+improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+The PV-10
+of our estimated total proved reserves was $423.2 million at December 31, 2012 compared to a PV-10 of $248.7 million at December 31, 2011, an increase of 70% despite lower commodity prices used to estimate PV-10 in 2012 compared to 2011.
+The PV-10 at December 31, 2012 was determined using the 12-month unweighted average of first-day-of-the-month oil and natural gas prices for 2012 of $91.21 per barrel and $2.757 per MMBtu, respectively, adjusted by lease for quality, energy
+content, regional price differentials and other expenses as needed compared to average oil and natural gas prices of $92.71 per barrel and $4.118 per MMBtu, respectively, adjusted as further described above, used to determine PV-10 at
+December 31, 2011. The Standardized Measure of estimated future net cash flows from our total proved reserves, including estimated future income tax expenses, was $394.6 million at December 31, 2012 and $215.5 million at December 31,
+2011, respectively. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” 
+For the year ended December 31, 2012, our oil and natural gas revenues were approximately $156.0 million, or an increase of about 133%, as compared to approximately $67.0 million for the year ended
+December 31, 2011. Our oil revenues increased over eight-fold to approximately $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our total realized revenues for
+2012, including realized gain on derivatives, were approximately $170.0 million, or an increase of about 129%, as compared to $74.1 million for 2011. For the year ended December 31, 2012, our Adjusted EBITDA was approximately $115.9 million, or
+an increase of about 132%, as compared to an 
+72 
+Table of Contents 
+Adjusted EBITDA of approximately $49.9 million for the year ended December 31, 2011. For a reconciliation of Adjusted EBITDA to net income (loss) and net cash provided by operating
+activities, see “Selected Financial Data — Non-GAAP Financial Measures.” 
+We currently intend to allocate
+approximately 82% of our 2013 capital expenditure budget to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play. We also plan to allocate about 16% of our 2013 capital
+expenditure budget to the exploration and acquisition of additional interests in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas
+and in Southeast New Mexico and West Texas, we plan to dedicate approximately 98% of our 2013 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted capital expenditures of
+approximately $310.0 million for 2013, the aggregate amount we will expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, our drilling results and our ability to obtain additional capital. Since
+approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014, 79% of our Wolfcamp and Bone Spring acreage was either held by production or not burdened by lease expirations before 2014
+and almost all of our Haynesville acreage was held by production at December 31, 2012, we possess the financial flexibility to allocate our capital when and where we believe it is economical and justified. 
+As we continue to explore and develop our leasehold positions in the Eagle Ford shale in South Texas and as we begin to explore and
+develop our leasehold positions in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, we may face various challenges in establishing operations in new areas, including securing the necessary services to drill and complete
+wells and securing the necessary facilities to gather, process, transport and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases
+throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic
+fracturing, services for our newly drilled wells during the year ended December 31, 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that
+maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play, as well as the Wolfcamp and Bone Spring plays
+in Southeast New Mexico and West Texas. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could
+Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.”
+We did experience temporary pipeline and natural gas processing interruptions from time to time during the year ended
+December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. To alleviate most of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a
+firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system
+for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No assurance can be made that this
+agreement will alleviate these issues completely, and if we were required to shut in our 
+73 
+Table of Contents 
+production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business,
+financial condition, results of operations and cash flows. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in
+2013. See “Risk Factors — The Marketability of Our Production Is Dependent Upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and
+Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Revenues
+Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may
+vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices. 
+Realized gain on derivatives. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. This revenue item
+includes the net realized cash gains and losses associated with the settlement of these derivative financial instruments for a given reporting period. 
+Unrealized gain (loss) on derivatives . We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. This revenue
+item recognizes the non-cash change in the fair value of our open derivative contracts between reporting periods. 
+The
+following table summarizes our revenues and production data for the periods indicated: 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+Operating Results: 
+Revenues (in thousands): 
+Oil 
+$ 
+123,654 
+$ 
+14,457 
+$ 
+2,507 
+Natural gas 
+32,344 
+52,543 
+31,535 
+Total oil and natural gas revenues 
+155,998 
+67,000 
+34,042 
+Realized gain on derivatives 
+13,960 
+7,106 
+5,299 
+Unrealized (loss) gain on derivatives 
+(4,802 
+) 
+5,138 
+3,139 
+Total revenues 
+$ 
+165,156 
+$ 
+79,244 
+$ 
+42,480 
+Net Production Volumes: 
+Oil (MBbl) 
+1,214 
+154 
+33 
+Natural gas (Bcf) 
+12.5 
+14.5 
+8.4 
+Total oil equivalent (MBOE) (1) 
+3,294 
+2,573 
+1,433 
+Average daily production (BOE/d) ( 1 ) 
+9,000 
+7,049 
+3,926 
+Average Sales Prices: 
+Oil, with realized derivatives (per Bbl) 
+$ 
+103.55 
+$ 
+93.80 
+$ 
+76.39 
+Oil, without realized derivatives (per Bbl) 
+$ 
+101.86 
+$ 
+93.80 
+$ 
+76.39 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+3.55 
+$ 
+4.11 
+$ 
+4.38 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+2.59 
+$ 
+3.62 
+$ 
+3.75 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+Year Ended December 31, 2012 as Compared to Year Ended December 31, 2011 
+Oil and natural gas revenues . Our oil and natural gas revenues increased by $89.0 million to $156.0 million, or an increase of about 133%, for the year ended December 31, 2012, as compared to
+the year ended 
+74 
+Table of Contents 
+December 31, 2011. This increase in oil and natural gas revenues reflects an increase in our oil revenues of $109.2 million and a decrease in our natural gas revenues of $20.2 million for
+the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our oil revenues increased over eight-fold to $123.7 million for the year ended December 31, 2012, as compared to $14.5 million for the year ended
+December 31, 2011. Our oil production also increased almost eight-fold to just over 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, from approximately 154,000 Bbl of oil, or about 422 Bbl of oil per day, during the comparable
+periods due to our drilling operations in the Eagle Ford shale. A portion of this increase in oil revenue also reflects a higher weighted average oil price of $101.86 per Bbl realized during the year ended December 31, 2012, as compared to a
+weighted average oil price of $93.80 per Bbl realized during the year ended December 31, 2011. The decrease in our natural gas revenues reflects a decline in our natural gas production by about 14% to approximately 12.5 Bcf for the year ended
+December 31, 2012, as compared to approximately 14.5 Bcf for the year ended December 31, 2011. This decline in natural gas production is due to several factors, including (i) the natural decline in natural gas production primarily
+from our existing Haynesville shale and Cotton Valley wells in Northwest Louisiana and East Texas, coupled with our decision not to drill any operated Haynesville shale or Cotton Valley wells in 2012, (ii) the voluntary curtailment by the
+operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) delays in natural gas production from our newly completed Eagle Ford shale wells in South
+Texas as a result of natural gas pipeline and production facility constraints. This decrease in natural gas revenues also results from a significantly lower weighted average natural gas price of $2.59 per Mcf realized during the year ended
+December 31, 2012, as compared to a weighted average natural gas price of $3.62 per Mcf realized during the year ended December 31, 2011. 
+Realized gain on derivatives . Our realized gain on derivatives increased by approximately $6.9 million to $14.0 million for the year ended December 31, 2012 from $7.1 million for the year
+ended December 31, 2011. For the year ended December 31, 2012, we realized a gain of approximately $11.9 million on our open natural gas derivative contracts and a gain of approximately $2.1 million on our open oil derivative contracts. As
+a result of declining natural gas prices between the comparable periods, we realized an average gain of approximately $1.45 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2012, as
+compared to $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011. Our total natural gas volumes hedged for the year ended December 31, 2012 were also approximately 19%
+higher than the total natural gas volumes hedged for the year ended December 31, 2011. We realized an average gain of $1.74 per Bbl hedged on all of our open oil contracts during the year ended December 31, 2012. We had no open oil or NGL
+derivative contracts during the year ended December 31, 2011. 
+Unrealized gain (loss) on derivatives. Our
+unrealized loss on derivatives was approximately $4.8 million for the year ended December 31, 2012, as compared to an unrealized gain of $5.1 million for the year ended December 31, 2011. During the period from December 31, 2011 to
+December 31, 2012, the net fair value of our open oil, natural gas and natural gas liquids derivative contracts decreased from approximately $9.3 million to approximately $4.5 million, resulting in an unrealized loss on derivatives of
+approximately $4.8 million for the year ended December 31, 2012. During the year ended December 31, 2012, the net fair value of our open natural gas costless collar contracts decreased by $8.7 million due primarily to the gains realized on
+these contracts during 2012. The net fair value of our open oil derivative contracts increased $3.7 million during the year ended December 31, 2012 as a result of a decrease in oil prices at December 31, 2012 compared to December 31,
+2011 and also as a result of two additional oil derivatives contracts we entered into during 2012. During the year ended December 31, 2012, we also entered into various NGL swap contracts which had a net fair value of approximately $0.2 million
+at December 31, 2012. We had no open NGL swap contracts during the year ended December 31, 2011. 
+75 
+Table of Contents 
+Year Ended December 31, 2011 as Compared to Year Ended December 31, 2010
+Oil and natural gas revenues . Our oil and natural gas revenues increased by $33.0 million to $67.0 million, or an
+increase of about 97%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. This increase in oil and natural gas revenues corresponds with an increase of about 79% in our oil and natural gas production to
+2.6 million BOE for the year ended December 31, 2011 from 1.4 million BOE for the year ended December 31, 2010. This increased production was almost entirely due to drilling operations in the Eagle Ford and Haynesville shales. A
+portion of the increase in oil and natural gas revenues reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011 as compared to the year ended December 31, 2010, as well as a higher average oil
+price of $93.80 per Bbl realized during 2011, as compared to an average oil price of $76.39 per Bbl realized during 2010. 
+Realized gain on derivatives . Our realized gain on derivatives increased by approximately $1.8 million to $7.1 million for the
+year ended December 31, 2011 from $5.3 million for the year ended December 31, 2010. The realized gain from our open natural gas costless collar contracts increased primarily as a result of the decline in natural gas prices during the
+comparable periods. We realized approximately $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011 as compared to $0.89 per MMBtu hedged on all of our open natural gas costless
+collar contracts during the year ended December 31, 2010. Our total natural gas volumes hedged for the year ended December 31, 2011 were also approximately 16% higher than the total natural gas volumes hedged for 2010. 
+Unrealized gain (loss) on derivatives. Our unrealized gain on derivatives was approximately $5.1 million for the year ended
+December 31, 2011, as compared to an unrealized gain of $3.1 million for the year ended December 31, 2010. During the period from December 31, 2010 to December 31, 2011, the net fair value of our open natural gas costless collar
+contracts increased by approximately $5.7 million, due primarily to a decrease in natural gas prices during 2011, as compared to 2010, as well as to an increase in the total number of our open natural gas costless collar contracts at
+December 31, 2011, as compared to December 31, 2010. The net fair value of our open oil derivative contracts decreased by approximately $0.6 million during the year ended December 31, 2011. 
+Expenses 
+Production
+taxes and marketing. Production taxes are paid on produced oil, natural gas and natural gas liquids based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or
+local taxing authorities. We attempt to take advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay tend to correlate to the changes in our oil and natural gas revenues. Marketing
+expenses are fees charged by the purchasers of the oil and natural gas we produce and sell and principally include compression, processing, transportation and marketing fees. 
+Lease operating expenses. Lease operating expenses are the daily costs incurred to produce oil, natural gas and natural gas liquids, as well as the daily costs incurred to maintain our producing
+properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional workover expenses related to our oil and natural gas properties. 
+Depletion, depreciation and amortization . Depletion, depreciation and amortization includes the systematic expensing of the
+capitalized costs incurred in the acquisition, exploration and development of oil and natural gas. We use the full-cost method of accounting and, accordingly, we capitalize all costs associated with the acquisition, exploration and development of
+oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly 
+76 
+Table of Contents 
+related to acquisition, exploration or development activities and do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil
+and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved oil and natural gas reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used
+to determine depletion, depreciation and amortization. 
+Accretion of asset retirement obligations . Asset retirement
+obligations relate to the future costs associated with plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. We recognize the fair value of
+an asset retirement obligation in the period it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil
+and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in our consolidated statements of operations. 
+Full-cost ceiling impairment . The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized
+costs less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the present value
+discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated
+properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs of
+developing these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. 
+General and administrative expenses. General and administrative expenses include, but are not limited to, compensation and
+benefits for our employees, costs of renting and maintaining our headquarters, office service contracts, board of directors fees, franchise taxes, stock-based compensation expense and accounting, legal and other professional fees. 
+Other Income (Expense) 
+Net gain (loss) on asset sales and inventory impairment . This other income (expense) item includes the net gain or loss we experience on infrequent asset sales or impairment charges associated with
+certain equipment held in inventory. This item also includes infrequent sales of oil and natural gas properties that we consider to be extraordinary when considered in relation to the normal course of our business. 
+Interest expense. Interest expense includes interest paid to our lenders as a result of borrowings under our revolving Credit
+Agreement. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under the Credit Agreement, and as a result, we incur interest expense that is affected by both fluctuations in interest rates
+and our financing decisions. In addition, we include any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees), commitment or facility fees and annual agency fees as interest expense and in our
+interest rate calculations and related disclosures. 
+Interest and other income . Interest income includes interest
+earned periodically on the cash and cash equivalents we hold in money market accounts composed of U.S. Treasury securities offering daily liquidity and the interest earned periodically on our certificates of deposit. Other income includes income we
+receive for providing salt water disposal and natural gas transportation services to other working interest participants in wells that we operate. 
+77 
+Table of Contents 
+Total income tax provision (benefit) . Total income tax provision (benefit) includes
+the net current and deferred portions of our estimated income tax liabilities. We file a U.S. federal income tax return and state tax returns in those states where we conduct oil and natural gas operations. The current portion of our income tax
+provision (benefit) reflects actual income tax payments made or refunds received by us as a result of filing these income tax returns. The deferred portion of our income tax provision is the result of temporary timing differences between the
+financial statement carrying values and the tax bases of our assets and liabilities. 
+The following table summarizes our
+operating expenses and other income (expense) for the periods indicated. As a result of the increasing significance of our oil production, all per unit expenses are presented as per BOE as compared to per Mcfe in prior reporting periods. 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+(In thousands, except expenses per BOE) 
+Expenses: 
+Production taxes and marketing 
+$ 
+11,672 
+$ 
+6,278 
+$ 
+1,982 
+Lease operating 
+28,184 
+7,244 
+5,284 
+Depletion, depreciation and amortization 
+80,454 
+31,754 
+15,596 
+Accretion of asset retirement obligations 
+256 
+209 
+155 
+Full-cost ceiling impairment 
+63,475 
+35,673 
+– 
+General and administrative 
+14,543 
+13,394 
+9,702 
+Total expenses 
+198,584 
+94,552 
+32,719 
+Operating (loss) income 
+(33,428 
+) 
+(15,308 
+) 
+9,761 
+Other (expense) income: 
+Net loss on asset sales and inventory impairment 
+(485 
+) 
+(154 
+) 
+(224 
+) 
+Interest expense 
+(1,002 
+) 
+(683 
+) 
+(3 
+) 
+Interest and other income 
+224 
+315 
+364 
+Total other (expense) income 
+(1,263 
+) 
+(522 
+) 
+137 
+(Loss) income before income taxes 
+(34,691 
+) 
+(15,830 
+) 
+9,898 
+Total income tax (benefit) provision 
+(1,430 
+) 
+(5,521 
+) 
+3,521 
+Net (loss) income 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+Expenses per BOE: 
+Production taxes and marketing 
+$ 
+3.54 
+$ 
+2.44 
+$ 
+1.38 
+Lease operating 
+$ 
+8.56 
+$ 
+2.82 
+$ 
+3.69 
+Depletion, depreciation and amortization 
+$ 
+24.43 
+$ 
+12.34 
+$ 
+10.89 
+General and administrative 
+$ 
+4.42 
+$ 
+5.21 
+$ 
+6.77 
+Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 
+Production taxes and marketing. Our production taxes and marketing expenses increased by $5.4 million to $11.7 million, or an
+increase of approximately 86%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase in our production taxes and marketing expenses primarily reflects the increase in our total oil and natural
+gas revenues by 133% for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The majority of this increase was attributable to increased production taxes associated with the large increase in our oil
+production during 2012 resulting from our drilling operations in the Eagle Ford shale in South Texas. Our total production was comprised of approximately 37% oil and 63% natural gas during the year ended December 31, 2012, as compared to
+approximately 6% oil and 94% natural gas during the year ended December 31, 2011. On a unit-of-production basis, our production taxes and marketing expenses increased by 45% to $3.54 per BOE for the year ended December 31, 2012, as
+compared to $2.44 per BOE for the year ended December 31, 2011. 
+Lease operating expenses. Our lease operating
+expenses increased by $20.9 million to $28.2 million, or an increase of about 289%, for the year ended December 31, 2012, as compared to the year ended 
+78 
+Table of Contents 
+December 31, 2011. Our total oil and natural gas production increased by about 28% to approximately 3.3 million BOE for the year ended December 31, 2012 from approximately
+2.6 million BOE for the year ended December 31, 2011, but our oil production increased almost eight-fold to just over 1.2 million Bbl from approximately 154,000 Bbl during the respective period. The increase in lease operating
+expenses was primarily attributable to the increased costs associated with operating oil production resulting from drilling operations in the Eagle Ford shale in 2012, as compared to the lower lease operating expenses associated with operating
+primarily dry natural gas production from the Haynesville and Cotton Valley in 2011. In addition, oil production comprised 37% of our total production during the year ended December 31, 2012, as compared to only 6% for the year ended
+December 31, 2011, resulting in higher overall lease operating expenses during the year ended December 31, 2012. During the year ended December 31, 2012, we completed and initiated oil and natural gas production from 28 gross/24.5 net
+wells in the Eagle Ford shale (plus 2 gross/2.0 net Austin Chalk/“Chalkleford” wells), most of which were on properties where new production facilities were being installed or natural gas pipelines were awaiting completion. While these new
+facilities were being installed and tested, much of the oil and natural gas was produced through rental equipment monitored by 24-hour contract personnel, resulting in higher operating costs from these properties during the year ended
+December 31, 2012 than we anticipate going forward now that the permanent production facilities and natural gas pipeline connections on most of these properties are complete. Approximately one-third of our total lease operating expenses in 2012
+were attributable to these extended flowback operations. As we continue to drill on new properties in the Eagle Ford shale and in Southeast New Mexico and West Texas throughout 2013, however, we also expect to produce new wells on these properties
+through similar rental test equipment until more permanent facilities can be constructed and installed. Our lease operating expenses per unit of production increased 204% to $8.56 per BOE for the year ended December 31, 2012, as compared to
+$2.82 per BOE for the year ended December 31, 2011. 
+Depletion, depreciation and amortization. Our depletion,
+depreciation and amortization expenses increased by $48.7 million to $80.5 million, or an increase of about 153%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. On a unit-of-production basis, our
+depletion, depreciation and amortization expenses increased to $24.43 per BOE for the year ended December 31, 2012, as compared to $12.34 per BOE for the year ended December 31, 2011. This increase in our depletion, depreciation and
+amortization expenses was primarily attributable to the decrease in our total proved oil and natural gas reserves to 23.8 million BOE at December 31, 2012, as compared to 32.2 million BOE at December 31, 2011. As a result of
+substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at
+June 30, 2012, and these proved undeveloped reserves were likewise not included in our total proved reserves at December 31, 2012. The increase in depletion, depreciation and amortization expenses was also partially attributable to the
+increase of approximately 28% in our oil and natural gas production to approximately 3.3 million BOE for the year ended December 31, 2012, as compared to approximately 2.6 million BOE for the year ended December 31, 2011, as well
+as to the higher drilling and completion costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas as compared with our Haynesville shale natural gas assets in Northwest Louisiana. 
+Accretion of asset retirement obligations . Our accretion of asset retirement obligations expenses increased by approximately
+$47,000 to $256,000, or an increase of about 23%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The increase in the accretion of our asset retirement obligations was due primarily to the addition of
+new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses. 
+79 
+Table of Contents 
+Full-cost ceiling impairment. At June 30, 2012, the net capitalized costs of our
+oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million. As a result, we recorded an impairment charge of $33.2 million to the net capitalized costs of our oil and natural gas properties and
+a deferred income tax credit of $11.9 million. At September 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million. As a result, we recorded an
+impairment charge of $3.6 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $1.3 million. At December 31, 2012, the net capitalized costs of our oil and natural gas properties less
+related deferred income taxes exceeded the full-cost ceiling by $17.3 million. As a result, we recorded an impairment charge of $26.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $9.4
+million. These full-cost ceiling impairment charges in 2012 were primarily attributable to declining natural gas prices throughout much of the year. As a result of substantially lower natural gas prices in 2012, we had downward revisions of our
+natural gas reserves totaling 103.4 Bcf (17.2 million BOE), including the removal of 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total
+proved reserves at June 30, 2012. These impairment charges are reflected in our operating expenses for the year ended December 31, 2012. During the first quarter of 2011, the net capitalized costs of our oil and natural gas properties less
+related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of
+$12.7 million, which is reflected in our operating expenses for the year ended December 31, 2011. 
+General and
+administrative. Our general and administrative expenses increased by $1.1 million to $14.5 million, or an increase of about 9%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our general and
+administrative expenses decreased by 15% on a unit-of-production basis to $4.42 per BOE for the year ended December 31, 2012, as compared to $5.21 per BOE for the year ended December 31, 2011. The increase in our general and administrative
+expenses was attributable to increased compensation, accounting, legal and other administrative expenses, most of which was associated with becoming a public company in February 2012, partially offset by a net decrease in non-cash stock-based
+compensation expense of $2.3 million for the year ended December 31, 2012, as compared to the year ended December 31, 2011. 
+Net gain (loss) on asset sales and inventory impairment . We incurred a loss on asset sales and inventory impairment of approximately $485,000 for the year ended December 31, 2012, as compared
+to a loss of $154,000 for the year ended December 31, 2011. The loss during 2012 was primarily related to the impairment of certain equipment held in inventory, mostly consisting of drilling rig parts. During the year ended December 31,
+2011, the loss was primarily related to the sale of pipe and other equipment and the impairment of certain equipment held in inventory, mostly consisting of drilling rig parts. 
+Interest expense. For the year ended December 31, 2012, we incurred total interest expense of approximately $2.6 million. We
+capitalized approximately $1.6 million of our interest expense on certain qualifying projects for the year ended December 31, 2012 and expensed the remaining $1.0 million to operations. In February 2012, we repaid our borrowings then
+outstanding of $123.0 million under our Credit Agreement using a portion of the net proceeds received from our Initial Public Offering. From March 1 through December 31, 2012, we borrowed $150.0 million under our Credit Agreement to
+finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at December 31, 2012 were $150.0 million, and the effective interest rate on the borrowings was approximately 3.3%. At
+December 31, 2011, we had total borrowings of $113.0 million outstanding under 
+80 
+Table of Contents 
+our Credit Agreement, and we incurred total interest expense of approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for
+the year ended December 31, 2011 and expensed the remaining $0.7 million to operations. 
+Interest and other income.
+Our interest and other income decreased by approximately $0.1 million to approximately $0.2 million, or a decrease of about 29%, for the year ended December 31, 2012, as compared to the year ended December 31, 2011. The decrease in our
+interest and other income was due primarily to a decrease in the natural gas transportation income received from third parties during the year ended December 31, 2012, as compared to the year ended December 31, 2011. Our cash and
+certificates of deposit decreased to approximately $2.3 million at December 31, 2012 from approximately $11.6 million at December 31, 2011. 
+Total income tax provision (benefit) . We recorded a total income tax benefit of approximately $1.4 million for the year ended December 31, 2012, as compared to a total income tax benefit of
+approximately $5.5 million for the year ended December 31, 2011. During the year ended December 31, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling
+by $40.9 million. We recorded an impairment charge of $63.5 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $22.6 million. The increase in our deferred tax assets as a result of the
+impairment charges recorded during the year ended December 31, 2012 caused our deferred tax assets to exceed our deferred tax liabilities, resulting in the establishment of a valuation allowance of $10.3 million due to uncertainties regarding
+the future realization of our deferred tax assets. As a result, we recorded an income tax benefit of $1.4 million for the year ended December 31, 2012. The total income tax benefit for the year ended December 31, 2011 reflected deferred
+income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. We had a net loss for the years ended December 31, 2012 and 2011. 
+Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 
+Production taxes and marketing. Our production taxes and marketing expenses increased by $4.3 million to $6.3 million, or an
+increase of approximately 217% for the year ended December 31, 2011, as compared to the year ended December 31, 2010. The increase in our production taxes and marketing expenses reflects the increases in both our oil and natural gas
+production and revenues by 79% and 97%, respectively, during the year ended December 31, 2011, as compared to the year ended December 31, 2010. The majority of this increase was due to higher marketing, transportation and compression
+charges on portions of our non-operated Haynesville shale production in 2011 as compared to 2010. Some of this increase was also due to Haynesville shale wells completed in 2011, several of which were turned to sales or produced their first
+significant production volumes during 2011. Although we or outside operators applied for exemptions from initial production taxes on these Haynesville shale wells, some of these wells had not been approved for production tax exemptions at
+December 31, 2011. Thus, we paid or accrued for the associated production taxes on these wells during the year ended December 31, 2011, although these production taxes were refunded to us in future periods as expected. We adjusted our
+production taxes and marketing expenses accordingly during the future periods when these production tax exemptions were approved. The remainder of the increase in production taxes and marketing expenses for the year ended December 31, 2011 was
+due to production taxes paid on production from our initial Eagle Ford shale wells in South Texas. 
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+Table of Contents 
+Lease operating expenses. Our lease operating expenses increased by $2.0 million to
+$7.2 million, or an increase of about 37%, for the year ended December 31, 2011, as compared to the year ended December 31, 2010. During these respective periods, however, our oil and natural gas production increased 79% from
+1.4 million BOE to 2.6 million BOE. As a result, our lease operating expenses per unit of production decreased by 23% to $2.82 per BOE for the year ended December 31, 2011, as compared to $3.69 per BOE for the year ended
+December 31, 2010. During the year ended December 31, 2011, both our total Haynesville shale production, as well as the percentage of our Haynesville production for which we were the operator, increased as compared to the year ended
+December 31, 2010. The per unit lease operating expenses associated with the Haynesville production were much less than those associated with our Cotton Valley natural gas production, primarily due to the greater salt water disposal costs
+associated with the Cotton Valley production and given the early stages of production then associated with many of these Haynesville wells. 
+Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $16.2 million to $31.8 million, or an increase of about 104%, for the year ended
+December 31, 2011, as compared to the year ended December 31, 2010. The increase in our depletion, depreciation and amortization expenses was due primarily to an increase of approximately 79% in our oil and natural gas production from
+1.4 million BOE to 2.6 million BOE during the respective time periods. Our depletion, depreciation and amortization expenses on a unit-of-production basis increased to $12.34 per BOE for the year ended December 31, 2011, or an
+increase of about 14%, from $10.89 per BOE for the year ended December 31, 2010. This per unit increase reflected increases in drilling and completion costs for wells drilled to the Haynesville shale during 2011, as well as higher drilling and
+completion costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas. 
+Accretion
+of asset retirement obligations . Our accretion of asset retirement obligations expenses increased by approximately $54,000 to approximately $209,000, or an increase of about 35%, for the year ended December 31, 2011, as compared to the year
+ended December 31, 2010. The increase in the accretion of asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although,
+on the whole, this item is an insignificant component of our overall expenses. 
+Full-cost ceiling impairment. During
+the quarter ended March 31, 2011, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million. As a result, we recorded an impairment charge of $35.7
+million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million, which is reflected in our expenses for the year ended December 31, 2011. No impairment to the net carrying value of
+our oil and natural gas properties on the balance sheet resulting from the full-cost ceiling limitation was recorded for the year ended December 31, 2010. 
+General and administrative. Our general and administrative expenses increased by $3.7 million to $13.4 million, or an increase of about 38%, for the year ended December 31, 2011, as compared
+to the year ended December 31, 2010. The increase in our general and administrative expenses was due primarily to increased cash and non-cash compensation expenses and increased accounting expenses for the year ended December 31, 2011, as
+compared to the year ended December 31, 2010. We recorded approximately $2.4 million in non-cash compensation expense for the year ended December 31, 2011, as compared to approximately $0.9 million recorded for the year ended
+December 31, 2010. This increase was primarily due to a change in accounting method for valuing our outstanding stock options. We awarded no new stock options during 2011. As a result of our increased oil and natural gas production, however,
+our general and administrative expenses decreased by 27% on a unit-of-production basis to $5.21 per BOE for the year ended December 31, 2011, as compared to $6.77 per BOE for the year ended December 31, 2010. 
+82 
+Table of Contents 
+Net gain (loss) on asset sales and inventory impairment . We incurred a loss on asset
+sales and inventory impairment of approximately $154,000 for the year ended December 31, 2011, as compared to a loss of approximately $224,000 for the year ended December 31, 2010. During the year ended December 31, 2011, this loss
+was primarily related to the sale of pipe and other equipment and the impairment of certain equipment held in inventory, consisting primarily of drilling rig parts. During the year ended December 31, 2010, we wrote off the Boise South pipeline
+asset in Orange County, Texas and recognized a net loss of approximately $174,000. We also recognized an impairment of approximately $50,000 to some of our equipment held in inventory following a determination that the market value of the equipment,
+consisting primarily of drilling rig parts, was less than the cost. 
+Interest expense. For the year ended
+December 31, 2011, we incurred total interest expense of approximately $2.0 million. We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2011 and expensed the
+remaining $0.7 million to operations. During the year ended December 31, 2011, we incurred incremental net borrowings of $88.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital
+expenditures. Our total outstanding borrowings at December 31, 2011 were $113.0 million, and the interest rate on these borrowings was approximately 5.3% per annum. In early January 2012, we converted this $113.0 million base rate advance
+to a Eurodollar-based advance, which then bore interest at 3.5% per annum. In December 2010, we borrowed $25.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures, which remained
+outstanding at December 31, 2010. We incurred interest expense of approximately $3,000 for the year ended December 31, 2010. 
+Interest and other income. Our interest and other income decreased by approximately $0.1 million to approximately $0.3 million, or a decrease of about 14%, for the year ended December 31, 2011
+as compared to the year ended December 31, 2010. The decrease in our interest and other income was due primarily to a decrease in the average balances of our cash and cash equivalents and certificates of deposit on which we received interest
+income between the two periods. Our cash and cash equivalents and certificates of deposit decreased to approximately $11.6 million at December 31, 2011 from approximately $23.4 million at December 31, 2010, as we used cash and incremental
+borrowings to acquire additional leasehold acreage in the Eagle Ford shale play in South Texas and in the core area of the Haynesville shale play in Northwest Louisiana and to fund our operated and non-operated drilling and completion activities in
+both areas. 
+Total income tax provision (benefit) . We recorded a total income tax benefit of approximately
+$5.5 million for the year ended December 31, 2011, as compared to a total income tax provision of approximately $3.5 million for the year ended December 31, 2010. The total income tax benefit for the year ended December 31, 2011
+reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. We recorded a total income tax provision of approximately $3.5 million for the year
+ended December 31, 2010. The total income tax provision for the year ended December 31, 2010 included a deferred income tax provision of approximately $4.9 million and a current income tax benefit of approximately $1.4 million, which was
+attributable to a refund of U.S. federal income taxes received by us. For the year ended December 31, 2010, the deferred income tax provision was consistent with our income before income taxes, which included approximately $3.1 million in
+unrealized hedging gains. We had a net loss for the year ended December 31, 2011, and our effective tax rate for the year ended December 31, 2010 was 35.57%. 
+83 
+Table of Contents 
+Liquidity and Capital Resources 
+Prior to the consummation of our Initial Public Offering on February 7, 2012, our primary sources of liquidity were capital
+contributions from private investors, our cash flows from operations, borrowings under our Credit Agreement and the proceeds from a significant sale of a portion of our assets in the Haynesville shale in 2008. Our primary use of capital has been,
+and will continue to be during 2013 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including equity and debt financings,
+additional borrowings and joint ventures, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of
+capital and to continue to grow our operating cash flows. 
+At December 31, 2012, we had cash and certificates of deposit
+totaling approximately $2.3 million, the borrowing base under our Credit Agreement was $215.0 million and we had $150.0 million of outstanding long-term borrowings and approximately $1.1 million in outstanding letters of credit. These borrowings
+bore interest at an effective interest rate of approximately 3.3% per annum. From January 1 through March 14, 2013, we borrowed an additional $30.0 million under our Credit Agreement to finance a portion of our working capital
+requirements and capital expenditures. At March 14, 2013, we had $180.0 million of outstanding long-term borrowings and approximately $1.3 million in outstanding letters of credit. 
+On September 28, 2012, we entered into the third amended and restated Credit Agreement which increased the maximum facility amount
+to $500.0 million from $400.0 million and increased the borrowing base from $125.0 million to $200.0 million as a result of our lenders’ review of our proved oil and natural gas reserves at June 30, 2012. The borrowing base under the
+Credit Agreement is scheduled to be redetermined automatically on May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at June 30 and December 31 of each year. Both
+we and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination dates. During the fourth quarter of 2012, we requested one such unscheduled redetermination, and on December 20,
+2012, the borrowing base was increased from $200.0 million to $215.0 million as a result of our lenders’ review of our proved oil and natural gas reserves at September 30, 2012. In addition, during the first quarter of 2013, our lenders
+completed their review of our proved oil and natural gas reserves at December 31, 2012, and as a result, on March 11, 2013, the borrowing base under our Credit Agreement was increased to $255.0 million. This most recent redetermination
+constitutes the regularly scheduled May 1 redetermination. We expect to request an unscheduled redetermination of our borrowing base between each scheduled redetermination date during 2013, which should result in approximately quarterly
+redeterminations of the borrowing base under our Credit Agreement throughout 2013. We expect additional increases to the borrowing base throughout 2013, primarily as a result of anticipated increases in our proved oil and natural gas reserves, and
+particularly our proved developed oil and natural gas reserves. As a result of this anticipated increase in borrowing capacity, together with our anticipated increases in oil production and related revenues, we expect to have sufficient cash flows
+from operations and future borrowing capacity under our Credit Agreement to fund our capital expenditure requirements for 2013. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and
+natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. However, should our drilling activities be less successful than we anticipate or result in less growth in
+our proved oil and natural gas reserves or less cash flows than we anticipate in 2013, or should oil prices decline substantially, we may require additional sources of financing, including through potential joint ventures and potential issuances of
+equity or debt securities, which may not be available on terms reasonably acceptable to us or at all. To the extent such sources of financing are not available on terms reasonably acceptable to us, we may need to reduce our capital spending and rate
+of growth. 
+84 
+Table of Contents 
+Although a majority of our anticipated increase in cash flows from operations during the
+year ending December 31, 2013, as compared to our cash flows from operations in prior periods, is expected to come from development activities on proved properties in the Eagle Ford shale play at December 31, 2012, these development
+activities may be less successful than we anticipate. Further, a portion of our anticipated increase in cash flows from operations during the year ending December 31, 2013 is expected to come from exploration activities on currently unproved
+properties in the Eagle Ford shale in South Texas and in the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas, and these exploration activities may or may not be as successful as we anticipate. Additionally, any anticipated
+increases in our cash flows from operations are based upon current expectations of oil and natural gas prices for 2013 and the hedges we currently have in place. If our exploration and development activities result in less cash flows than
+anticipated, we may seek additional sources of capital, including through additional borrowings under our Credit Agreement, the sale of debt securities, the sale of assets or acreage or entering into one or more joint ventures, none of which may be
+available. In addition to future borrowings under our Credit Agreement, we may also seek to raise additional funds by selling shares of our common stock or securities convertible or exercisable into our common stock (including debt securities or
+other preferential securities) in the public markets or otherwise. It is likely that any such sales would dilute the ownership interest of our existing shareholders. There is no guarantee that we would be able to sell such debt or equity securities
+on terms acceptable to us. It is also possible that, to the extent we are not able to obtain additional sources of capital, we may modify our planned capital expenditure budget for 2013 accordingly or enter into one or more joint ventures or other
+alternative financings. Exploration and development activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our Credit
+Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed
+Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties
+That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled Out over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of
+Their Drilling.” 
+Our cash flows for the years ended December 31, 2012, 2011 and 2010 are presented below:
+Year Ended December 31, 
+2012 
+2011 
+2010 
+(In thousands) 
+Net cash provided by operating activities 
+$ 
+124,228 
+$ 
+61,868 
+$ 
+27,273 
+Net cash used in investing activities 
+(306,916 
+) 
+(160,088 
+) 
+(147,334 
+) 
+Net cash provided by financing activities 
+174,499 
+87,444 
+36,891 
+Net change in cash and cash equivalents 
+$ 
+(8,189 
+) 
+$ 
+(10,776 
+) 
+$ 
+(83,170 
+) 
+Cash Flows Provided by Operating Activities 
+Net cash provided by operating activities increased by $62.3 million to $124.2 million for the year ended December 31, 2012, as
+compared to net cash provided by operating activities of $61.9 million for the year ended December 31, 2011. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $114.9
+million for the year ended December 31, 2012 from $49.3 million for the year ended December 31, 2011. This increase is primarily attributable to the almost eight-fold increase in our oil production to just over 1.2 million Bbl from
+approximately 154,000 Bbl during the respective periods. A portion of the increase in net cash provided by operating activities also reflects the 
+85 
+Table of Contents 
+higher weighted average oil price of $101.86 per Bbl realized during 2012, as compared to a weighted average oil price of $93.80 per Bbl realized during 2011. Changes in our operating assets and
+liabilities between December 31, 2011 and December 31, 2012 also resulted in a net decrease of approximately $3.3 million in net cash provided by operating activities for the year ended December 31, 2012, as compared to the year ended
+December 31, 2011. Our accounts payable and accrued liabilities increased to approximately $87.3 million at December 31, 2012 from approximately $44.3 million at December 31, 2011 due to our increased operating activity in South
+Texas. Our accounts receivable increased to $29.5 million at December 31, 2012, as compared to $13.2 million at December 31, 2011, due primarily to the increase in our oil production and associated revenues. 
+Net cash provided by operating activities increased by $34.6 million to $61.9 million for the year ended December 31, 2011, as
+compared to net cash provided by operating activities of $27.3 million for the year ended December 31, 2010. Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $49.3
+million for the year ended December 31, 2011 from $25.0 million for the year ended December 31, 2010. This increase reflects primarily the 79% increase in our oil and natural gas production to 2.6 million BOE from 1.4 million BOE
+between the respective periods. A portion of the increase in net cash provided by operating activities also reflects the approximate five-fold increase in our oil production for the year ended December 31, 2011, as compared to the year ended
+December 31, 2010, as well as a higher weighted average oil price of $93.80 per Bbl realized during 2011, as compared to a weighted average oil price of $76.39 per Bbl realized during 2010. Some of this increase in net cash provided by
+operating activities is also due to changes in our operating assets and liabilities totaling approximately $10.3 million between December 31, 2010 and December 31, 2011. Our accounts payable and accrued liabilities increased to
+approximately $44.3 million at December 31, 2011 from approximately $27.0 million at December 31, 2010 due to our increased operating activity in South Texas. Our accounts receivable increased to $13.2 million at December 31, 2011, as
+compared to $11.6 million at December 31, 2010, due primarily to the increase in our oil and natural gas production and associated revenues. 
+Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic
+activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial
+instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service agreements in order to minimize ongoing future commitments. For additional information on the
+impact of changing prices on our financial position, see “Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or
+Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+Cash Flows Used in Investing Activities 
+Net cash used in investing activities increased by $146.8 million to $306.9 million for the year ended December 31, 2012 from $160.1 million for the year ended December 31, 2011. This increase
+in net cash used in investing activities reflected an increase of $144.3 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2012, as compared to the year ended December 31, 2011, and an
+increase of approximately $2.7 million in expenditures for other property and equipment, which includes new pipeline infrastructure associated with our initial wells in the Eagle Ford shale. 
+86 
+Table of Contents 
+Approximately 91% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 9% to the acquisition of additional acreage for the year ended
+December 31, 2012, as compared to approximately 75% allocated to drilling and completion operations and associated infrastructure and 25% allocated to acquisition of additional acreage for the year ended December 31, 2011. Our oil and
+natural gas properties capital expenditures for the year ended December 31, 2012 were primarily due to expenditures associated with our operated drilling and completion activities and acreage acquisitions in the Eagle Ford shale, non-operated
+drilling and completion activities in the Eagle Ford and Haynesville shale plays and our acreage acquisitions in the Delaware Basin in West Texas. 
+Net cash used in investing activities increased by $12.8 million to $160.1 million for the year ended December 31, 2011 from $147.3 million for the year ended December 31, 2010. This increase in
+net cash used in investing activities reflected a decrease of $2.6 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2011, as compared to the year ended December 31, 2010, offset by an
+increase of approximately $3.0 million in expenditures for other property and equipment, which included new pipeline infrastructure associated with our initial wells in the Eagle Ford shale. Although our capital expenditures were relatively flat
+year-over-year, approximately 75% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 25% to the acquisition of additional acreage for the year ended December 31, 2011, as compared
+to approximately 43% allocated to drilling and completion operations and associated infrastructure and 57% allocated to acquisition of additional acreage for the year ended December 31, 2010. Our oil and natural gas properties capital
+expenditures for the year ended December 31, 2011 were primarily due to expenditures associated with our operated and non-operated drilling and completion activities in the Eagle Ford shale and Haynesville shale plays and our acquisition of
+acreage prospective for the Eagle Ford shale in DeWitt, Gonzales, Karnes and Wilson Counties, Texas. 
+Expenditures for the
+acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing approximately $310.0 million in capital for acquisition, exploration and development activities in 2013
+as follows: 
+Amount 
+(in 
+millions) 
+Exploration, development drilling and completion costs 
+$ 
+260.0 
+Pipeline and infrastructure expenditures 
+25.0 
+Leasehold acquisition and 2-D and 3-D seismic data 
+25.0 
+Total 
+$ 
+310.0 
+For further information regarding our anticipated capital expenditure budget in 2013, see “Business
+— General.” 
+Our 2013 capital expenditures may be adjusted as business conditions warrant. The amount, timing and
+allocation of our capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later
+periods to conserve cash or to focus on those projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices,
+availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual
+obligations and other factors both within and outside our control. 
+87 
+Table of Contents 
+Cash Flows Provided by Financing Activities 
+Net cash provided by financing activities was $174.5 million for the year ended December 31, 2012, as compared to net cash provided
+by financing activities of $87.4 million for the year ended December 31, 2011. The net cash provided by financing activities for the year ended December 31, 2012 was principally due to the total proceeds from the Initial Public Offering of
+$146.5 million and total incremental borrowings of $160.0 million under our Credit Agreement to fund a portion of our working capital requirements during the period, offset by the costs of the Initial Public Offering of $11.6 million incurred during
+the period and by the repayment of $123.0 million in borrowings during the period. We also received approximately $2.7 million from the exercise of stock options during the year ended December 31, 2012. 
+Net cash provided by financing activities was $87.4 million for the year ended December 31, 2011, as compared to net cash provided
+by financing activities of $36.9 million for the year ended December 31, 2010. The net cash provided by financing activities for the year ended December 31, 2011 was due almost entirely to additional borrowings of $88.0 million under our
+Credit Agreement to fund a portion of our working capital requirements as well as our acquisition of acreage prospective for the Eagle Ford shale play in DeWitt, Gonzales, Karnes and Wilson Counties, Texas. In January 2011, we sold 53,772 shares of
+our Class A common stock in a private placement and received net proceeds of approximately $0.6 million. During 2011, we also received proceeds from the exercise of stock options totaling approximately $0.8 million. For the year ended
+December 31, 2011, we also incurred cash expenditures related to preparation for our Initial Public Offering of approximately $1.7 million. 
+Net cash provided by financing activities was $36.9 million for the year ended December 31, 2010. For the year ended December 31, 2010, the most significant financing activities occurred in the
+fourth quarter of 2010. During that time, we sold approximately 1.9 million shares of our Class A common stock in a private placement and received net proceeds of approximately $21.0 million, and we borrowed $25.0 million under our Credit
+Agreement to fund a portion of our working capital requirements. In addition, in April 2010, we repurchased 1,000,000 shares of Class A common stock from five shareholders, all advised by Wellington Management Company, for a total of $9.0
+million. We also received proceeds of approximately $2.0 million from the periodic exercise of stock options during the year ended December 31, 2010. 
+Credit Agreement 
+In December 2011, we entered into our second amended and
+restated senior secured revolving Credit Agreement for which Comerica Bank served as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company, a
+wholly-owned subsidiary of Matador Resources Company, was the borrower under the amended Credit Agreement. Borrowings were secured by mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC
+Energy Company’s wholly-owned subsidiaries, which were also guarantors. In addition, all obligations under the Credit Agreement were guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with one
+of the lenders under the Credit Agreement (or an affiliate thereof) were also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. 
+The amount of the borrowings under the second amended and restated Credit Agreement were limited to the lesser of $400.0 million or the borrowing base, which was determined by the lenders based primarily
+on the estimated value of our proved oil and natural gas reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which we have no control. At
+December 31, 2011, the borrowing base was $125.0 million and we had $113.0 million in 
+88 
+Table of Contents 
+outstanding borrowings under the Credit Agreement. In January 2012, we borrowed an additional $10.0 million to finance a portion of our working capital requirements, bringing the
+then-outstanding indebtedness under the Credit Agreement to $123.0 million. Following the completion of our Initial Public Offering, we used a portion of the net proceeds to repay the then-outstanding $123.0 million under our Credit Agreement in
+February 2012, at which time the borrowing base was reduced to $100.0 million. On February 28, 2012, the borrowing base was increased to $125.0 million pursuant to a special borrowing base redetermination made at our request. This borrowing
+base increase was determined by our lenders based upon, among other items, the increase in our proved oil and natural gas reserves at December 31, 2011. 
+On September 28, 2012, we entered into our third amended and restated senior secured revolving Credit Agreement, which matures in December 2016. Among other things, this amendment increased the
+maximum facility amount from $400.0 million to $500.0 million, increased the borrowing base from $125.0 million to $200.0 million and named RBC as administrative agent. In addition, the amendment provided for a conforming borrowing base of $165
+million. The borrowing base will automatically be reduced to the conforming borrowing base on the earlier of (i) December 31, 2013 or (ii) the closing of a secondary public offering of equity interests that results in net cash
+proceeds to us in an amount greater than or equal to $25.0 million. MRC Energy Company is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of our oil and natural gas properties and by the equity
+interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity
+hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. 
+The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based
+primarily on the estimated value of our proved oil and natural gas reserves at June 30 and December 31 of each year. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled
+redetermination dates. During the fourth quarter of 2012, we requested one such unscheduled redetermination, and on December 20, 2012, the borrowing base was increased from $200.0 million to $215.0 million as a result of our lenders’
+review of our proved oil and natural gas reserves at September 30, 2012. In connection with this borrowing base redetermination, the conforming borrowing base was increased to $180.0 million at December 20, 2012. In addition, during the
+first quarter of 2013, our lenders completed their review of our proved oil and natural gas reserves at December 31, 2012, and as a result, on March 11, 2013, the borrowing base was increased to $255.0 million and the conforming borrowing
+base was increased to $220.0 million. This most recent redetermination constitutes the regularly scheduled May 1 redetermination. In the event of a borrowing base increase, we are required to pay a fee to the lenders equal to a percentage of
+the amount of the increase, which will be determined based on market conditions at the time of the borrowing base increase. If the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, we would be
+required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.
+Between March 1, 2012 and December 31, 2012, we borrowed $150.0 million under the Credit Agreement to finance a
+portion of our working capital requirements and capital expenditures. At December 31, 2012, we had $150.0 million in borrowings outstanding under the Credit Agreement, approximately $1.1 million in outstanding letters of credit issued pursuant
+to the Credit Agreement and approximately $63.9 million available for additional borrowings. At December 31, 2012, our outstanding borrowings bore interest at an effective interest rate of approximately 3.3% per annum. 
+89 
+Table of Contents 
+We expect to access future borrowings under our Credit Agreement to fund a portion of our
+2013 capital expenditure requirements in excess of amounts available from our operating cash flows. We also intend to seek additional redeterminations of our borrowing base as a result of, among other items, any increases to our proved oil and
+natural gas reserves, and particularly our proved developed oil and natural gas reserves, primarily attributable to our ongoing drilling operations in the Eagle Ford shale. From January 1 through March 14, 2013, we borrowed an additional
+$30.0 million under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At March 14, 2013, we had $180.0 million in borrowings outstanding under the Credit Agreement, approximately $1.3
+million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $73.7 million available for additional borrowings. 
+If we borrow funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate on such day,
+plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 2.25% of such outstanding loan depending on the level of borrowings under the agreement. If we borrow funds as a Eurodollar loan, such
+borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to
+maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.75% to 3.25% of such outstanding loan depending on the level of borrowings under the
+Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by us. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in
+arrears. We include this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees as interest expense and in our interest rate calculations and related
+disclosures. 
+Key financial covenants under the third amended and restated Credit Agreement require us to maintain (1) a
+current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at the end of each fiscal quarter beginning
+March 31, 2013 and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less. In connection with the March 11, 2013 borrowing base redetermination, the
+Credit Agreement was amended to delay first measurement of the current ratio until March 31, 2014. 
+Subject to certain
+exceptions, our Credit Agreement contains various covenants that limit our, along with our subsidiaries’, ability to take certain actions, including, but not limited to, the following: 
+• 
+incur indebtedness or grant liens on any of our assets; 
+• 
+enter into commodity hedging agreements; 
+• 
+declare or pay dividends, distributions or redemptions; 
+• 
+merge or consolidate; 
+• 
+make any loans or investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+engage in certain asset dispositions, including a sale of all or substantially all of our assets. 
+90 
+Table of Contents 
+If an event of default exists under the Credit Agreement, the lenders will be able to
+accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: 
+• 
+failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount
+within certain grace periods; 
+• 
+failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain
+instances, to certain grace periods; 
+• 
+bankruptcy or insolvency events involving us or our subsidiaries; and 
+• 
+a change of control, as defined in the Credit Agreement. 
+At December 31, 2012, we believe that we were in compliance with the terms of our Credit Agreement. 
+Off-Balance Sheet Arrangements 
+At December 31, 2012, we did not have
+any off-balance sheet arrangements. 
+Obligations and Commitments 
+We had the following material contractual obligations and commitments at December 31, 2012: 
+Payments Due by Period 
+Total 
+Less Than 
+1 Year 
+1-3 Years 
+3-5 
+Years 
+More Than 
+5
+Years 
+(in thousands) 
+Contractual Obligations: 
+Revolving credit borrowings, including letters of
+credit (1) 
+$ 
+151,100 
+$ 
+1,100 
+$ 
+– 
+$ 
+150,000 
+$ 
+– 
+Office lease 
+5,956 
+575 
+1,164 
+1,222 
+2,995 
+Drilling rig contracts (2 ) 
+5,119 
+5,119 
+– 
+– 
+– 
+Asset retirement obligations 
+5,770 
+660 
+374 
+467 
+4,269 
+Natural gas processing and transportation agreement. 
+16,703 
+5,985 
+7,723 
+2,995 
+– 
+Total contractual cash obligations 
+$ 
+184,648 
+$ 
+13,439 
+$ 
+9,261 
+$ 
+154,684 
+$ 
+7,264 
+(1) 
+At December 31, 2012, we had $150.0 million in revolving borrowings outstanding under our third amended and restated Credit Agreement and approximately $1.1
+million in outstanding letters of credit issued pursuant to the Credit Agreement. These borrowings mature in December 2016. These amounts do not include estimated interest on the obligations, because our revolving borrowings had short-term interest
+periods, and we are unable to determine what our borrowing costs may be in future periods. 
+(2) 
+At December 31, 2012, we were party to two drilling rig contracts to explore and develop our Eagle Ford acreage in South Texas. The two rigs began drilling on our
+acreage in March 2012 and December 2012, respectively. The rig that began drilling in March 2012 is under contract for one year. This contract was renegotiated for an additional six-month term effective March 2013 (See “Note 18 –
+Subsequent Events ” to the consolidated financial statements in this Annual Report on Form 10-K). The rig that began drilling in December 2012 is under contract for nine months. Should we elect to terminate one or both contracts and if
+the drilling contractor were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we
+would incur termination obligations. Our maximum outstanding aggregate termination obligations under these contracts were approximately $5.1 million at December 31, 2012. 
+General Outlook and Trends 
+For the year ended December 31, 2012, oil
+prices ranged from a high of approximately $109.77 per Bbl in late February to a low of approximately $77.69 per Bbl in late June, based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. Oil prices
+remained near or above $100 per Bbl for much of the first four months of 2012, but began declining in early May and throughout 
+91 
+Table of Contents 
+the remainder of the second quarter. During the third and fourth quarters, oil prices rebounded somewhat, ranging from a low of $83.75 per Bbl in early July to a high of $99.00 per Bbl in
+mid-September, before declining somewhat to $91.82 per Bbl at December 31, 2012. We realized a weighted average oil price of $101.86 per Bbl ($103.55 per Bbl including realized gains from oil derivatives) for our oil production for the year ended
+December 31, 2012 as compared to $93.80 per Bbl for the year ended December 31, 2011. At March 14, 2013, the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date closed at $93.03 per Bbl, as compared to
+$105.43 per Bbl at March 14, 2012. 
+For the year ended December 31, 2012, natural gas prices ranged from a low of
+approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices declined during most of
+the first three to four months of 2012, reaching their lowest levels in many years, before increasing to $3.90 per MMBtu in late November. We realized a weighted average natural gas price of $2.59 per Mcf ($3.55 per Mcf including realized gains from
+natural gas derivatives) for our natural gas production for the year ended December 31, 2012, as compared to $3.62 per Mcf ($4.11 per Mcf including realized gains from natural gas derivatives) for the year ended December 31, 2011. Natural
+gas prices had declined since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date, as compared to $2.28 per MMBtu at
+March 14, 2012. 
+The prices we receive for oil, natural gas and natural gas liquids heavily influence our revenue,
+profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and natural gas liquids are commodities and, therefore, their prices are subject to wide fluctuations in response to
+relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or natural gas
+liquids prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and natural gas liquids we can produce economically. From time to time, we use derivative financial instruments to mitigate our exposure to commodity
+price risk associated with oil, natural gas and natural gas liquids prices. Even so, decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural
+gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. Should oil, natural gas or natural gas liquids prices decrease to economically unattractive levels and remain there for an extended period of time, we may
+elect to delay some of our exploration and development plans for our prospects, or cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a
+material adverse effect on our business, financial condition, results of operations and reserves. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets.
+Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their
+nature, our wells in the Eagle Ford shale and Austin Chalk in South Texas, the Haynesville shale and Cotton Valley in Northwest Louisiana and East Texas and the Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas will experience
+rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural
+gas and natural gas liquids price declines, however, we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could
+materially impact our production volumes, revenues, reserves and cash flows. 
+92 
+Table of Contents 
+We must focus our efforts on increasing oil and natural gas reserves and production while
+controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development
+costs are subject to changes in the costs of acquiring, drilling and completing our prospects. 
+Critical Accounting Policies and Estimates
+We have outlined below certain accounting policies that are of particular importance to the presentation of our financial
+condition and results of operations and require the application of significant judgment or estimates by our management. 
+The
+preparation of financial statements requires us to make other estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and
+assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and
+uncertainties could cause the actual results to differ materially from our estimates. 
+Property and Equipment
+We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of
+accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center
+representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and
+non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to exploration and development activities, but do not include any costs related to production, selling or general corporate
+administrative activities. 
+The net capitalized costs of oil and natural gas properties are limited to the lower of
+unamortized costs less related deferred income taxes or the cost center ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. The cost center ceiling is defined as the sum of (a) the
+present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and
+unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated
+costs of developing these reserves. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. 
+The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the
+commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are
+estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. 
+Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property
+93 
+Table of Contents 
+costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for impairment on a periodic basis based upon changes in operating or
+economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results.
+Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive.
+Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss
+recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred.
+Significant workovers that increase the properties’ reserves are capitalized. 
+Other property and equipment are stated at
+cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life (five to ten years) using the straight-line method. Support equipment and facilities include the pipelines and salt water disposal systems owned
+by Longwood Gathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the
+lease. 
+Derivative Financial Instruments 
+From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of
+put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the
+call proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract,
+a floating price is exchanged for a fixed price over a specified period, providing downside price protection. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have
+elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statement of operations. The fair
+value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized
+gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in our consolidated statement of operations. 
+Revenue Recognition 
+We follow the sales method of accounting for our oil, natural gas and natural gas liquids revenue, whereby we recognize revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to
+purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural gas and natural gas liquids are produced and sold, and we accrue for revenue earned
+but not yet received. 
+94 
+Table of Contents 
+Stock-based Compensation 
+We account for stock based compensation in accordance with ASC 718. During 2012, all stock option awards were granted under our 2012
+Long-Term Stock and Incentive Plan and were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these
+awards have been accounted for as liability instruments. We used the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our
+equity-based stock options. Stock options typically vest over four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a
+period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, we estimated the future volatility of our stock using the
+historical volatility of the common stock of a group of companies we consider to be a representative peer group. Management believes that these average historical volatility rates are currently the best available indicator of future volatility.
+We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the
+expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. 
+Assumptions are reviewed each time new equity based option awards are granted and quarterly for outstanding liability option awards. The
+assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity based option awards and outstanding
+liability based option awards and impacts the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte
+Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards are recognized based on the fair value of our stock on the date of the grant. 
+All 2012 stock option awards were granted as non-qualified options for which we will realize a tax benefit upon the exercise of the
+options. Historically, the majority of the stock option awards we granted were awarded as incentive stock options (“ISOs”) for which we were unable to realize a tax benefit upon the exercise of the options. We may grant future stock option
+awards as ISOs. 
+In 2012, we granted for the first time, restricted stock and restricted stock unit awards that contain a
+market condition. We refer to these awards as performance-based awards in Note 8 to our consolidated financial statements. Because these awards vest based on both a market condition and a service condition, the compensation expense for these awards
+will be recognized if the service condition is met, regardless of whether the market condition is met. 
+Prior to
+November 22, 2010, all of our then-outstanding stock options were classified as equity instruments, with the fair value of the awards measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, we
+changed our method of accounting for our then-outstanding stock options, reclassifying all then-outstanding stock options from equity to liability instruments. This change was made as a result of purchasing shares from certain of our employees to
+assist them in the exercise of then-outstanding options of our Class A common stock. At December 31, 2012, we continue to account for all stock options granted under our 2003 Stock and Incentive Plan as liability instruments. 
+95 
+Table of Contents 
+Income Taxes 
+We account for income taxes using the asset and liability approach for financial accounting and reporting. We evaluate the probability of realizing the future benefits of our deferred tax assets and
+provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. 
+We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that
+the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50
+percent likelihood of being realized upon ultimate settlement with the relevant tax authority. 
+We have evaluated all tax
+positions for which the statute of limitations remained open, and we believe that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2012, we had not established any reserves for, nor
+recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, we include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on our
+consolidated statement of operations. 
+Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net
+Revenue 
+Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net
+revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved reserves in this Annual Report on Form 10-K. The SEC’s rules define proved reserves as the quantities of oil and
+natural gas, 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 economic 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our engineers and technical staff must make many subjective
+assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated at least annually and consider recent production levels and other technical information about each well. Estimating oil and natural gas
+reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and
+reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital
+expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly,
+reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial position, results of
+operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may
+be material. 
+Recent Accounting Pronouncements 
+Balance Sheet. In January 2013, the FASB issued Accounting Standards Update, or ASU, 2013-01, Balance Sheet. The ASU clarifies the scope of ASU 2011-11 to limit the application of ASU
+2011-11 to 
+96 
+Table of Contents 
+derivatives accounted for in accordance with Accounting Standards Codification, or ASC, 815, Derivatives and Hedging , including bifurcated embedded derivatives, repurchase agreements and
+reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The
+adoption of ASU 2013-01 is not expected to have a material effect on our consolidated financial statements, but may require certain additional disclosures. 
+Balance Sheet. In December 2011, the FASB issued ASU 2011-11, Balance Sheet . The requirements amend the disclosure requirements to offsetting in ASC 210-20-50. The amendments require
+enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master
+netting agreement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The adoption of ASU 2011-11 is not expected to have a material effect on our consolidated financial statements,
+but may require certain additional disclosures. The amendments in ASU 2011-11 are to be applied for annual reporting periods beginning on or after January 1, 2013 and are to be applied retrospectively for all reporting periods presented.
+Fair Value . In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and
+Disclosure Requirements in U.S. GAAP and IFRS . ASU 2011-04 amends ASC 820, Fair Value Measurements , providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and
+International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair
+value measurements. We adopted ASU 2011-04 effective January 1, 2012; adoption did not have a material impact on our consolidated financial statements, but did require certain additional disclosures. 
+Item 7A. 
+Quantitative and Qualitative Disclosures about Market Risk. 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the
+use of derivative financial instruments. 
+Commodity price exposure. We are exposed to market risk as the prices of oil,
+natural gas and natural gas liquids fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and
+expect to enter into derivative financial instruments in the future to cover a significant portion of our future anticipated production. 
+We use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide us with downside price
+protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the
+case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. 
+We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using
+purchase and sale information available for similarly traded securities. At December 31, 2012, Comerica Bank and RBC (or affiliates thereof) were the counterparties for all of our derivative instruments. We have evaluated the credit standing of
+the counterparties in determining the fair value of our derivative financial instruments. 
+97 
+Table of Contents 
+In November 2011, we began entering into various costless collar transactions for the first
+time to mitigate our exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these oil hedging
+transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below
+the price floor established by these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price
+ceiling established by these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. 
+In November 2012, we also entered into various swap contracts to mitigate our exposure to fluctuations in oil prices on a portion of our
+future anticipated oil production, each with an established fixed price. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these oil hedging transactions is the arithmetic average of
+the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the fixed price established by these swaps,
+we receive from our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by these swaps, we pay to our
+counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. 
+The following table is a summary of our open oil costless collar contracts at December 31, 2012. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Bbl/month) 
+Price 
+Floor 
+($/Bbl) 
+Price 
+Ceiling 
+($/Bbl) 
+Fair Value of 
+Asset 
+(thousands) 
+Oil 
+01/01/2013 — 03/31/2013 
+20,000 
+90.00 
+110.00 
+$ 
+122 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+85.00 
+102.25 
+96 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+90.00 
+115.00 
+980 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+85.00 
+110.40 
+471 
+Oil 
+01/01/2013 — 12/31/2013 
+20,000 
+85.00 
+108.80 
+418 
+Oil 
+01/01/2013 — 06/30/2014 
+8,000 
+90.00 
+114.00 
+666 
+Oil 
+01/01/2013 — 06/30/2014 
+12,000 
+90.00 
+115.50 
+1,036 
+Total open oil costless collar contracts 
+$ 
+3,789 
+All of the above oil costless collar contracts will expire at varying times during 2013 and 2014.
+The following table is a summary of our open oil price swap contracts at December 31, 2012. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Bbl/month) 
+Fixed 
+Price 
+($/Bbl) 
+Fair Value 
+of 
+Liability 
+(thousands) 
+Oil 
+01/01/2013 — 12/31/2013 
+10,000 
+90.20 
+$ 
+(362 
+) 
+Oil 
+01/01/2013 — 12/31/2013 
+10,000 
+90.65 
+(308 
+) 
+Total open oil swap contracts 
+$ 
+(670 
+) 
+All of the above oil price swap contracts will expire at varying times during 2013. 
+At December 31, 2012, 2011 and 2010, we used costless collars to mitigate our exposure to fluctuations in natural gas prices, each
+with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these 
+98 
+Table of Contents 
+transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the last day of
+that contract period. When the settlement price is below the price floor established by these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract
+natural gas volume. When the settlement price is above the price ceiling established by these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural
+gas volume. 
+The following is a summary of our open natural gas costless collar contracts at December 31, 2012.
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(MMBtu/month)
+Price 
+Floor 
+($/MMBtu) 
+Price 
+Ceiling 
+($/MMBtu) 
+Fair Value of 
+Asset 
+(Liability) 
+(thousands) 
+Natural Gas 
+01/01/2013 — 07/31/2013 
+150,000 
+4.50 
+5.75 
+$ 
+1,154 
+Natural Gas 
+01/01/2013 — 12/31/2013 
+100,000 
+3.00 
+3.83 
+(146 
+) 
+Natural Gas 
+01/01/2013 — 12/31/2013 
+100,000 
+3.00 
+4.95 
+40 
+Natural Gas 
+01/01/2013 — 12/31/2013 
+100,000 
+3.00 
+4.96 
+41 
+Natural Gas 
+01/01/2014 — 12/31/2014 
+100,000 
+3.25 
+5.37 
+19 
+Natural Gas 
+01/01/2014 — 12/31/2014 
+100,000 
+3.25 
+5.42 
+27 
+Total open natural gas costless collar contracts 
+$ 
+1,135 
+All of the above natural gas costless collar contracts will expire at varying times during 2013 and 2014.
+In August 2012, we began entering into various swap contracts to mitigate our exposure to fluctuations in NGL prices on a
+portion of our future anticipated NGL production, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to us pursuant to any of these transactions is the arithmetic average
+of any current month for delivery on the nearby month futures contracts of the underlying commodity as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET prop” on the pricing date. When the settlement price is below the
+fixed price established by these swaps, we receive from our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price
+established by these swaps, we pay to our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. 
+The following is a summary of our open natural gas liquids swap contracts at December 31, 2012. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Gal/month) 
+Fixed 
+Price 
+($/Gal) 
+Fair Value 
+of 
+Asset 
+(Liability) 
+(thousands) 
+Purity Ethane 
+01/01/2013 — 12/31/2013 
+110,000 
+0.335 
+$ 
+106 
+Purity Ethane 
+01/01/2013 — 12/31/2013 
+110,000 
+0.355 
+133 
+Propane 
+01/01/2013 — 12/31/2013 
+53,000 
+0.953 
+13 
+Propane 
+01/01/2013 — 12/31/2013 
+53,000 
+1.001 
+43 
+Normal Butane 
+01/01/2013 — 12/31/2013 
+14,700 
+1.455 
+(29 
+) 
+Normal Butane 
+01/01/2013 — 12/31/2013 
+14,700 
+1.560 
+(10 
+) 
+Isobutane 
+01/01/2013 — 12/31/2013 
+7,000 
+1.515 
+(18 
+) 
+Isobutane 
+01/01/2013 — 12/31/2013 
+7,000 
+1.625 
+(9 
+) 
+Natural Gasoline 
+01/01/2013 — 12/31/2013 
+12,000 
+2.025 
+1 
+Natural Gasoline 
+01/01/2013 — 12/31/2013 
+12,000 
+2.085 
+3 
+Natural Gasoline 
+01/01/2013 — 12/31/2013 
+12,000 
+2.102 
+(8 
+) 
+Total open NGL swap contracts 
+$ 
+225 
+All of the above NGL price swap contracts will expire at varying times during 2013. 
+99 
+Table of Contents 
+Effect of Recent Derivatives Legislation 
+On July 21, 2010, President Obama signed into law the Dodd-Frank Act, which is intended to modernize and protect the integrity of the
+U.S. financial system. The Dodd-Frank Act, among other things, sets forth a framework for regulating certain derivative products including the commodity hedges of the type used by us, but many aspects of this law are subject to further rulemaking
+and will take effect over several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based
+upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In
+particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this
+legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on
+Our Ability to Hedge Risks Associated with Our Business.” 
+Interest rate risk. We do not and have not used
+interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2012 we had $150.0
+million in revolving borrowings outstanding under our third amended and restated Credit Agreement at an interest rate of approximately 3.3% per annum. If we incur additional indebtedness in the future and at higher interest rates, we may use
+interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. 
+Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily
+based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant
+customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial position, results of operations and cash flows. In addition, our oil, natural gas
+and natural gas liquids derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. 
+While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit
+standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation
+may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record, the financial ability of the customer’s parent company to make
+payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative instruments in place at March 14, 2013 were RBC, Comerica Bank and The Bank of Nova
+Scotia (or affiliates thereof) and we are likely to enter into any future derivative instruments with RBC, Comerica Bank, The Bank of Nova Scotia or other lenders (or affiliates thereof) party to the Credit Agreement. 
+100
+Table of Contents 
+Impact of Inflation . Inflation in the United States has been relatively low in recent
+years and did not have a material impact on our results of operations for the years ended December 31, 2012, 2011 and 2010. Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S.
+economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Eagle
+Ford shale and Haynesville shale plays. See “Business — General.” See also “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic
+Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of
+Operations and Cash Flows.” 
+Item 8. 
+Financial Statements and Supplementary Data. 
+Our financial statements appear at the end of this Annual Report on Form 10-K. See the index to the financial statements in Item 15. 
+Item 9. 
+Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. 
+Not applicable. 
+Item 9A. 
+Controls and Procedures. 
+Evaluation of Disclosure Controls and Procedures 
+As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in
+Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief
+Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2012 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange
+Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the
+Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. 
+Changes in Internal Control over Financial Reporting 
+During the quarter
+ended December 31, 2012, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. 
+Management’s Report on Internal Control over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules
+13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control
+over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in “Internal 
+101
+Table of Contents 
+Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief
+Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes
+in accordance with U.S. generally accepted accounting principles. 
+Grant Thornton LLP, our independent registered public
+accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2012 as included herein. 
+Important Considerations 
+The effectiveness of our disclosure controls and
+procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems,
+the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the
+degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful
+in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. 
+102
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Matador
+Resources Company 
+We have audited the internal control over financial reporting of Matador Resources Company (a Texas corporation) and
+subsidiaries (collectively 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 March 18, 2013 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas 
+March 18, 2013 
+103
+Table of Contents 
+Item 9B. 
+Other Information. 
+None.
+PART III 
+Item 10. 
+Directors, Executive Officers and Corporate Governance. 
+The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 11. 
+Executive Compensation. 
+The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be
+filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 12. 
+Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption
+“Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report on Form 10-K and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by
+reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence. 
+The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 14. 
+Principal Accounting Fees and Services. 
+The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+104
+Table of Contents 
+PART IV 
+Item 15. 
+Exhibits and Financial Statement Schedules. 
+The following documents are filed as part of this Annual Report on Form 10-K: 
+1.
+Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2012 and 2011, Consolidated Statements of Operations for the years ended December 31, 2012,
+2011 and 2010, Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2012, 2011 and 2010 and Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010. 
+2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual
+Report on Form 10-K. 
+105
+Table of Contents 
+EXHIBIT INDEX 
+Exhibit 
+Number 
+Description 
+2.1 
+Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador
+Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011). 
+3.1 
+Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration
+Statement on Form S-1 filed on August 12, 2011). 
+3.2 
+Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13,
+2012). 
+3.3 
+Amended and Restated Bylaws of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on February 13, 2012). 
+4.1 
+Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012). 
+10.1† 
+Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1
+filed on November 14, 2011). 
+10.2† 
+Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1
+filed on November 14, 2011). 
+10.3† 
+Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1
+filed on November 14, 2011). 
+10.4† 
+Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form
+S-1 filed on November 14, 2011). 
+10.5† 
+Independent Contractor Agreement between Matador Resources Company and David F. Nicklin (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement
+on Form S-1 filed on November 14, 2011). 
+10.6† 
+First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration
+Statement on Form S-1 filed on November 14, 2011). 
+10.7† 
+First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our
+Registration Statement on Form S-1 filed on November 14, 2011). 
+10.8† 
+First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration
+Statement on Form S-1 filed on November 14, 2011). 
+10.9† 
+First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our
+Registration Statement on Form S-1 filed on November 14, 2011). 
+10.10† 
+Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our
+Registration Statement on Form S-1 filed on December 30, 2011). 
+10.11† 
+Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our
+Registration Statement on Form S-1 filed on December 30, 2011). 
+10.12† 
+Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our
+Registration Statement on Form S-1 filed on December 30, 2011). 
+Table of Contents 
+10.13† 
+Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our
+Registration Statement on Form S-1 filed on December 30, 2011). 
+10.14† 
+First Amendment to the Independent Contractor Agreement between Matador Resources Company and David F. Nicklin (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to our
+Registration Statement on Form S-1 filed on December 30, 2011). 
+10.15† 
+2012 Long-Term Incentive Plan of Matador Resources Company (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December
+30, 2011). 
+10.16† 
+First Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated April 16, 2012 (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form
+10-Q for the quarter ended March 31, 2012). 
+10.17† 
+Second Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated March 8, 2013 (filed herewith). 
+10.18† 
+Matador Resources Company Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form
+S-1 filed on December 30, 2011). 
+10.19† 
+Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to
+our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.20† 
+First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.21† 
+Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.22† 
+Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.23† 
+Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.24† 
+Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.25† 
+Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to
+Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.26† 
+Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26
+to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.27† 
+Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (filed herewith). 
+10.28† 
+Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment
+No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+Table of Contents 
+10.29 
+Participation Agreement, by and among MRC Rockies Company, Matador Resources Company (now known as MRC Energy Company), Matador Production Company, Roxanna Rocky Mountains, LLC,
+Roxanna Oil, Inc., Alliance Capital Real Estate, Inc. and AllianceBernstein L.P., dated at May 14, 2010 (incorporated by reference to Exhibit 10.23 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14,
+2011). 
+10.30 
+Amendment, dated as of September 11, 2012, to Participation Agreement dated May 14, 2010, by and among MRC Rockies Company, Matador Resources Company (now known as MRC Energy
+Company), Matador Production Company, Roxanna Rocky Mountains, LLC, Roxanna Oil, Inc., Alliance Capital Real Estate, Inc. and Kimmeridge Energy Exploration Fund, L.P. (successor in interest to AllianceBernstein L.P.) (incorporated by reference to
+Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2012). 
+10.31 
+Assignment, Bill of Sale and Conveyance, by and among Winn Exploration Co., Inc., Pinion Exploration, LLP, McDay Oil & Gas, Inc. and Matador Resources Company (now known as MRC
+Energy Company), dated effective at December 1, 2010 (incorporated by reference to Exhibit 10.24 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.32 
+Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011
+(incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.33† 
+Employment Agreement between Matador Resources Company and Wade Massad (incorporated by reference to Exhibit 10.34 to Amendment No. 3 to our Registration Statement on Form S-1 filed
+on January 13, 2012). 
+10.34† 
+Nonqualified Stock Option Agreement, dated February 1, 2012, by and between Matador Resources Company and Wade Massad (incorporated by reference to Exhibit 10.1 to the Current
+Report on Form 8-K filed on February 7, 2012). 
+10.35† 
+Separation Agreement and Release by and between Matador Resources Company and Wade I. Massad, dated as of August 10, 2012 (incorporated by reference to Exhibit 10.9 to the Quarterly
+Report on Form 10-Q for the quarter ended June 30, 2012). 
+10.36† 
+Consulting Agreement by and between Matador Resources Company and Wade I. Massad, dated as of August 10, 2012 (incorporated by reference to Exhibit 10.10 to the Quarterly Report on
+Form 10-Q for the quarter ended June 30, 2012). 
+10.37† 
+Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by
+reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.38† 
+Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference
+to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.39† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report
+on Form 10-K for the year ended December 31, 2011). 
+10.40† 
+Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual
+Report on Form 10-K for the year ended December 31, 2011). 
+10.41† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to the Annual Report on
+Form 10-K for the year ended December 31, 2011). 
+10.42† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by
+reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+Table of Contents 
+10.43† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by
+reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.44† 
+Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without
+employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.45† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by
+reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.46† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference
+to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.47† 
+Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment
+agreements (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.48 
+Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as
+Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). 
+10.49 
+Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as
+Administrative Agent, dated as of September 28, 2012 (filed herewith). 
+10.50 
+Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal
+Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (filed herewith). 
+10.51 
+First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of
+Canada, as Administrative Agent (filed herewith). 
+21.1 
+List of Subsidiaries of Matador Resources Company (filed herewith). 
+23.1 
+Consent of Grant Thornton LLP (filed herewith). 
+23.2 
+Consent of Netherland, Sewell & Associates, Inc. (filed herewith). 
+31.1 
+Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+31.2 
+Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+32.1 
+Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed
+herewith). 
+32.2 
+Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed
+herewith). 
+99.1 
+Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). 
+Table of Contents 
+101* 
+The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2012, formatted in XBRL (eXtensible
+Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statement of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the
+Notes to Consolidated Financial Statements (submitted electronically herewith). 
+† 
+* 
+Indicates a management contract or compensatory plan or arrangement. 
+In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101
+to this Annual Report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of that section, and
+shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such
+filing. 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the
+undersigned, thereunto duly authorized. 
+MATADOR RESOURCES COMPANY 
+March 18, 2013 
+By: 
+/s/ Joseph Wm. Foran 
+Joseph Wm. Foran 
+Chairman, President and Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K
+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/ Joseph Wm.
+Foran 
+Joseph Wm. Foran 
+Chairman, President and Chief Executive Officer (Principal Executive Officer) 
+March 18, 2013 
+/s/ David E.
+Lancaster 
+David E. Lancaster 
+Executive Vice President, Chief Operating Officer and Chief Financial Officer 
+(Principal Financial Officer) 
+March 18, 2013 
+/s/ Kathryn L.
+Wayne 
+Kathryn L. Wayne 
+Controller and Treasurer (Principal Accounting Officer) 
+March 18, 2013 
+/s/ Stephen A.
+Holditch 
+Stephen A. Holditch 
+Director 
+March 18, 2013 
+/s/ David M.
+Laney 
+David M. Laney 
+Director 
+March 18, 2013 
+/s/ Gregory E.
+Mitchell 
+Gregory E. Mitchell 
+Director 
+March 18, 2013 
+/s/ Steven W.
+Ohnimus 
+Steven W. Ohnimus 
+Director 
+March 18, 2013 
+/s/ Michael C.
+Ryan 
+Michael C. Ryan 
+Director 
+March 18, 2013 
+/s/ Margaret B.
+Shannon 
+Margaret B. Shannon 
+Director 
+March 18, 2013 
+Table of Contents 
+GLOSSARY OF OIL AND NATURAL GAS TERMS 
+The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K.
+Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report on Form 10-K in reference to
+crude oil or other liquid hydrocarbons. 
+Bcf . One billion cubic feet. 
+BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf
+of natural gas. 
+BOE/d. BOE per day. 
+Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. 
+Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations,
+stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reserve. 
+Conventional resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily
+flow to the wellbore. 
+Coring . The act of taking a core. A core is a solid column of rock, usually from two to four
+inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the
+formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. 
+Developed acreage . The number of acres that are allocated or assignable to productive wells. 
+Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such
+production exceed production-related expenses and taxes. 
+Exploratory well . A well drilled to find and produce oil or
+natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. 
+Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working
+interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a
+royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” 
+Table of Contents 
+FERC . Federal Energy Regulatory Commission. 
+Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological
+structural feature and/or stratigraphic condition. 
+Gross acres or gross wells . The total acres or wells in which a
+working interest is owned. 
+Held by production . An oil and natural gas property under lease in which the lease
+continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. 
+Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a
+horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage
+and limiting surface disruption. 
+Hydraulic fracturing . The technique of improving a well’s production or
+injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that
+fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. 
+Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane and pentane resulting from the further processing of liquefiable hydrocarbons separated
+from raw natural gas by a natural gas processing facility. 
+MBbl . One thousand barrels of crude oil or other liquid
+hydrocarbons. 
+MBOE. One thousand BOE’s. 
+Mcf . One thousand cubic feet of natural gas. 
+Mcfe . One thousand
+cubic feet of natural gas equivalents, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. 
+MMBtu . One million British thermal units. 
+MMcf . One million cubic
+feet of natural gas. 
+NGL . Natural gas liquids. 
+Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. 
+Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil,
+natural gas and/or natural gas liquids that are produced from the well. 
+NYMEX . New York Mercantile Exchange.
+Table of Contents 
+Overriding royalty interest . A fractional interest in the gross production of oil and
+natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced
+from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. 
+Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. 
+Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are
+retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. 
+Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping
+mechanism and hydrocarbon type. 
+Possible reserves . Additional reserves that are less certain to be recognized than
+probable reserves. 
+Probable reserves . Additional reserves that are less certain to be recognized than proved reserves
+but which, in sum with proved reserves, are as likely as not to be recovered. 
+Producing well, or productive well . A
+well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. 
+Properties . Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee,
+leasehold and related interests. 
+Prospect . A specific geographic area which, based on supporting geological,
+geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. 
+Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which
+has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved but non-producing reserves.
+Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities
+and by existing operating methods. 
+Proved reserves . Reserves of oil and natural gas that have been proved to a high
+degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. 
+Proved undeveloped reserves . 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. 
+Recompletion . Completing in the same wellbore to reach a new reservoir after production from the
+original reservoir has been abandoned. 
+Repeatability . The potential ability to drill multiple wells within a prospect
+or trend. 
+Table of Contents 
+Reservoir . A porous and permeable underground formation containing a natural
+accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Royalty interest . An interest in an oil and natural gas 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. 
+2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. 
+3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of
+reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production.
+Spud. The act of beginning to drill an oil or natural gas well. 
+Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having
+geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. 
+Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further
+exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. 
+Undeveloped acreage . Lease 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. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. 
+Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such property
+to be classified as proved. 
+Vertical well . A hole drilled vertically into the earth from which oil, natural gas or
+water flows or is pumped. 
+Visualization . An exploration technique in which the size and shape of subsurface features
+are mapped and analyzed based upon information derived from well logs, seismic data and other well information. 
+Volumetric
+reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and
+recovery factor. 
+Wellbore . The hole made by a well. 
+Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the
+property and receive a share of production. 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED FINANCIAL STATEMENTS 
+December 31, 2012, 2011 and 2010 
+Contents
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Consolidated Financial Statements 
+Consolidated Balance Sheets as of December 31, 2012 and 2011 
+F-3 
+Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and
+2010 
+F-4 
+Consolidated Statements of Changes in Shareholders’ Equity for the years
+ended December 31, 2012, 2011 and 2010 
+F-5 
+Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and
+2010 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 
+F-1
+Table of Contents 
+Report of Independent Registered Public Accounting Firm
+Board of Directors and Shareholders 
+Matador Resources Company 
+We have audited the accompanying consolidated balance sheets of
+Matador Resources Company (a Texas corporation) and subsidiaries (collectively the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, changes in shareholders’ 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 Matador Resources Company 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 March 18, 2013 expressed an unqualified opinion thereon. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas 
+March 18, 2013 
+F-2
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except par value and share data) 
+December 31, 
+2012 
+2011 
+ASSETS 
+Current assets 
+Cash 
+$ 
+2,095 
+$ 
+10,284 
+Certificates of deposit 
+230 
+1,335 
+Accounts receivable 
+Oil and natural gas revenues 
+24,422 
+9,237 
+Joint interest billings 
+4,118 
+2,488 
+Other 
+974 
+1,447 
+Derivative instruments 
+4,378 
+8,989 
+Lease and well equipment inventory 
+877 
+1,343 
+Prepaid expenses 
+1,103 
+1,153 
+Total current assets 
+38,197 
+36,276 
+Property and equipment, at cost 
+Oil and natural gas properties, full-cost method 
+Evaluated 
+763,527 
+423,945 
+Unproved and unevaluated 
+149,675 
+162,598 
+Other property and equipment 
+27,258 
+18,764 
+Less accumulated depletion, depreciation and amortization 
+(349,370 
+) 
+(205,442 
+) 
+Net property and equipment 
+591,090 
+399,865 
+Other assets 
+Derivative instruments 
+771 
+847 
+Deferred income taxes 
+411 
+1,594 
+Other assets 
+1,560 
+887 
+Total other assets 
+2,742 
+3,328 
+Total assets 
+$ 
+632,029 
+$ 
+439,469 
+LIABILITIES AND SHAREHOLDERS’ EQUITY 
+Current liabilities 
+Accounts payable 
+$ 
+28,120 
+$ 
+18,841 
+Accrued liabilities 
+59,179 
+25,439 
+Royalties payable 
+6,541 
+1,855 
+Borrowings under Credit Agreement 
+– 
+25,000 
+Derivative instruments 
+670 
+171 
+Advances from joint interest owners 
+1,515 
+– 
+Deferred income taxes 
+411 
+3,024 
+Dividends payable — Class B 
+– 
+69 
+Other current liabilities 
+56 
+177 
+Total current liabilities 
+96,492 
+74,576 
+Long-term liabilities 
+Borrowings under Credit Agreement 
+150,000 
+88,000 
+Asset retirement obligations 
+5,109 
+3,935 
+Derivative instruments 
+– 
+383 
+Other long-term liabilities 
+1,324 
+1,060 
+Total long-term liabilities 
+156,433 
+93,378 
+Commitments and contingencies (Note 13) 
+Shareholders’ equity 
+Common stock — Class A, $0.01 par value, 80,000,000 shares authorized; 56,778,718 and 42,916,668 shares issued; and
+55,577,667, and 41,737,493 shares outstanding, respectively 
+568 
+429 
+Common stock— Class B, $0.01 par value, zero and 2,000,000 shares authorized, respectively; zero and 1,030,700 shares issued
+and outstanding, respectively 
+– 
+10 
+Additional paid-in capital 
+404,311 
+263,562 
+Retained (deficit) earnings 
+(15,010 
+) 
+18,279 
+Treasury stock, at cost, 1,201,051 and 1,179,175 shares, respectively 
+(10,765 
+) 
+(10,765 
+) 
+Total shareholders’ equity 
+379,104 
+271,515 
+Total liabilities and shareholders’ equity 
+$ 
+632,029 
+$ 
+439,469 
+The accompanying notes are an integral part of these financial statements. 
+F-3
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(In thousands, except per share data) 
+For the years ended December 31, 
+2012 
+2011 
+2010 
+Revenues 
+Oil and natural gas revenues 
+$ 
+155,998 
+$ 
+67,000 
+$ 
+34,042 
+Realized gain on derivatives 
+13,960 
+7,106 
+5,299 
+Unrealized (loss) gain on derivatives 
+(4,802 
+) 
+5,138 
+3,139 
+Total revenues 
+165,156 
+79,244 
+42,480 
+Expenses 
+Production taxes and marketing 
+11,672 
+6,278 
+1,982 
+Lease operating 
+28,184 
+7,244 
+5,284 
+Depletion, depreciation and amortization 
+80,454 
+31,754 
+15,596 
+Accretion of asset retirement obligations 
+256 
+209 
+155 
+Full-cost ceiling impairment 
+63,475 
+35,673 
+– 
+General and administrative 
+14,543 
+13,394 
+9,702 
+Total expenses 
+198,584 
+94,552 
+32,719 
+Operating (loss) income 
+(33,428 
+) 
+(15,308 
+) 
+9,761 
+Other income (expense) 
+Net loss on asset sales and inventory impairment 
+(485 
+) 
+(154 
+) 
+(224 
+) 
+Interest expense 
+(1,002 
+) 
+(683 
+) 
+(3 
+) 
+Interest and other income 
+224 
+315 
+364 
+Total other (expense) income 
+(1,263 
+) 
+(522 
+) 
+137 
+(Loss) income before income taxes 
+(34,691 
+) 
+(15,830 
+) 
+9,898 
+Income tax (benefit) provision 
+Current 
+– 
+(46 
+) 
+(1,411 
+) 
+Deferred 
+(1,430 
+) 
+(5,475 
+) 
+4,932 
+Total income tax (benefit) provision 
+(1,430 
+) 
+(5,521 
+) 
+3,521 
+Net (loss) income 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Class B 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+Diluted 
+Class A 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Class B 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+Weighted average common shares outstanding 
+Basic 
+Class A 
+53,852 
+41,687 
+40,007 
+Class B 
+105 
+1,031 
+1,031 
+Total 
+53,957 
+42,718 
+41,038 
+Diluted 
+Class A 
+53,852 
+41,687 
+40,103 
+Class B 
+105 
+1,031 
+1,031 
+Total 
+53,957 
+42,718 
+41,134 
+The accompanying notes are an integral part of these financial statements. 
+F-4
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY 
+For the years ended December 31, 2012, 2011 and 2010 
+(In thousands) 
+Common stock 
+Additional 
+paid-in 
+capital 
+Retained 
+earnings 
+(deficit) 
+Total 
+Class A 
+Class B 
+Treasury stock 
+Shares 
+Amount 
+Shares 
+Amount 
+Shares 
+Amount 
+Balance at January 1, 2010 
+40,443 
+$ 
+404 
+1,031 
+$ 
+10 
+$ 
+241,664 
+$ 
+22,761 
+68 
+$ 
+(517 
+) 
+$ 
+264,322 
+Issuance of Class A common stock 
+1,879 
+19 
+– 
+– 
+20,633 
+– 
+– 
+– 
+20,652 
+Cost to issue equity 
+– 
+– 
+– 
+– 
+(531 
+) 
+– 
+(531 
+) 
+Issuance of Class A common stock to Board members and advisors 
+20 
+– 
+– 
+– 
+198 
+– 
+– 
+– 
+198 
+Stock options granted 
+– 
+– 
+– 
+– 
+414 
+– 
+– 
+– 
+414 
+Stock options exercised 
+393 
+4 
+– 
+– 
+1,974 
+– 
+– 
+– 
+1,978 
+Stock options modified 
+– 
+– 
+– 
+– 
+(1,086 
+) 
+– 
+– 
+– 
+(1,086 
+) 
+Restricted stock issued 
+15 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Restricted stock vested 
+– 
+– 
+– 
+– 
+74 
+– 
+– 
+– 
+74 
+Class B dividends declared 
+– 
+– 
+– 
+– 
+– 
+(275 
+) 
+– 
+– 
+(275 
+) 
+Current period net income 
+– 
+– 
+– 
+– 
+– 
+6,377 
+– 
+– 
+6,377 
+Issuance of treasury stock 
+– 
+– 
+– 
+– 
+2 
+– 
+(6 
+) 
+45 
+47 
+Purchases of treasury stock 
+– 
+– 
+– 
+– 
+– 
+– 
+1,117 
+(10,293 
+) 
+(10,293 
+) 
+Balance at December 31, 2010 
+42,750 
+427 
+1,031 
+10 
+263,342 
+28,863 
+1,179 
+(10,765 
+) 
+281,877 
+Issuance of Class A common stock 
+54 
+1 
+– 
+– 
+591 
+– 
+– 
+– 
+592 
+Cost to issue equity 
+– 
+– 
+– 
+– 
+(1,667 
+) 
+– 
+– 
+– 
+(1,667 
+) 
+Issuance of Class A common stock to Board members and advisors 
+20 
+– 
+– 
+– 
+230 
+– 
+– 
+– 
+230 
+Stock options exercised 
+93 
+1 
+– 
+– 
+1,022 
+– 
+– 
+– 
+1,023 
+Restricted stock vested 
+– 
+– 
+– 
+– 
+44 
+– 
+– 
+– 
+44 
+Class B dividends declared 
+– 
+– 
+– 
+– 
+– 
+(275 
+) 
+– 
+– 
+(275 
+) 
+Current period net loss 
+– 
+– 
+– 
+– 
+– 
+(10,309 
+) 
+– 
+– 
+(10,309 
+) 
+Balance at December 31, 2011 
+42,917 
+429 
+1,031 
+10 
+263,562 
+18,279 
+1,179 
+(10,765 
+) 
+271,515 
+Issuance of Class A common stock 
+12,209 
+122 
+– 
+– 
+146,388 
+– 
+– 
+– 
+146,510 
+Cost to issue equity 
+– 
+– 
+– 
+– 
+(11,268 
+) 
+– 
+– 
+– 
+(11,268 
+) 
+Conversion of Class B common stock to Class A common stock 
+1,031 
+10 
+(1,031 
+) 
+(10 
+) 
+– 
+– 
+– 
+– 
+– 
+Issuance of Class A common stock to Board members and advisors 
+7 
+– 
+– 
+– 
+71 
+– 
+– 
+– 
+71 
+Stock options expense related to equity based awards 
+– 
+– 
+– 
+– 
+432 
+– 
+– 
+– 
+432 
+Stock options exercised 
+296 
+3 
+– 
+– 
+3,541 
+– 
+– 
+– 
+3,544 
+Liability based stock option awards forfeited or expired 
+– 
+– 
+– 
+– 
+216 
+– 
+– 
+– 
+216 
+Changes in fair value for liability based awards for which grant date fair value is in excess of fair value 
+– 
+– 
+– 
+– 
+620 
+– 
+– 
+– 
+620 
+Restricted stock issued 
+319 
+4 
+– 
+– 
+(4 
+) 
+– 
+– 
+– 
+– 
+Restricted stock forfeited 
+– 
+– 
+– 
+– 
+(29 
+) 
+– 
+22 
+– 
+(29 
+) 
+Restricted stock and restricted stock units expense 
+– 
+– 
+– 
+– 
+758 
+– 
+– 
+– 
+758 
+Swing sale profit contribution 
+– 
+– 
+– 
+– 
+24 
+– 
+– 
+– 
+24 
+Class B dividends declared 
+– 
+– 
+– 
+– 
+– 
+(28 
+) 
+– 
+– 
+(28 
+) 
+Current period net loss 
+– 
+– 
+– 
+– 
+– 
+(33,261 
+) 
+– 
+– 
+(33,261 
+) 
+Balance at December 31, 2012 
+56,779 
+$ 
+568 
+– 
+$ 
+– 
+$ 
+404,311 
+$ 
+(15,010 
+) 
+1,201 
+$ 
+(10,765 
+) 
+$ 
+379,104 
+The accompanying notes are an integral part of these financial statements. 
+F-5
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+For the years ended December 31, 
+2012 
+2011 
+2010 
+Operating activities 
+Net (loss) income 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+Adjustments to reconcile net (loss) income to net cash provided by operating activities 
+Unrealized loss (gain) on derivatives 
+4,802 
+(5,138 
+) 
+(3,139 
+) 
+Depletion, depreciation and amortization 
+80,454 
+31,754 
+15,596 
+Accretion of asset retirement obligations 
+256 
+209 
+155 
+Full-cost ceiling impairment 
+63,475 
+35,673 
+– 
+Stock option and grant expense 
+(589 
+) 
+2,362 
+824 
+Restricted stock grants 
+729 
+44 
+74 
+Deferred income tax (benefit) provision 
+(1,430 
+) 
+(5,476 
+) 
+4,932 
+Loss on asset sales and inventory impairment 
+485 
+154 
+224 
+Changes in operating assets and liabilities 
+Accounts receivable 
+(16,342 
+) 
+(1,523 
+) 
+(386 
+) 
+Lease and well equipment inventory 
+50 
+22 
+(8 
+) 
+Prepaid expenses 
+50 
+650 
+(580 
+) 
+Other assets 
+(673 
+) 
+(814 
+) 
+33 
+Accounts payable, accrued liabilities and other current liabilities 
+19,740 
+13,497 
+2,488 
+Royalties payable 
+4,685 
+873 
+309 
+Advances from joint interest owners 
+1,515 
+(723 
+) 
+273 
+Other long-term liabilities 
+282 
+613 
+101 
+Net cash provided by operating activities 
+124,228 
+61,868 
+27,273 
+Investing activities 
+Oil and natural gas properties capital expenditures 
+(300,689 
+) 
+(156,431 
+) 
+(159,050 
+) 
+Expenditures for other property and equipment 
+(7,332 
+) 
+(4,671 
+) 
+(1,610 
+) 
+Purchases of certificates of deposit 
+(496 
+) 
+(4,298 
+) 
+(3,739 
+) 
+Sales of certificates of deposit 
+1,601 
+5,312 
+17,065 
+Net cash used in investing activities 
+(306,916 
+) 
+(160,088 
+) 
+(147,334 
+) 
+Financing activities 
+Repayments of borrowings under Credit Agreement 
+(123,000 
+) 
+(103,000 
+) 
+– 
+Borrowings under Credit Agreement 
+160,000 
+191,000 
+25,000 
+Proceeds from issuance of common stock 
+146,510 
+592 
+20,652 
+Swing sale profit contribution 
+24 
+– 
+– 
+Cost to issue equity 
+(11,599 
+) 
+(1,710 
+) 
+(172 
+) 
+Proceeds from stock options exercised 
+2,660 
+837 
+1,978 
+Payment of dividends — Class B 
+(96 
+) 
+(275 
+) 
+(275 
+) 
+Purchases of treasury stock 
+– 
+– 
+(10,292 
+) 
+Net cash provided by financing activities 
+174,499 
+87,444 
+36,891 
+Decrease in cash and cash equivalents 
+(8,189 
+) 
+(10,776 
+) 
+(83,170 
+) 
+Cash and cash equivalents at beginning of year 
+10,284 
+21,060 
+104,230 
+Cash and cash equivalents at end of year 
+$ 
+2,095 
+$ 
+10,284 
+$ 
+21,060 
+Supplemental disclosures of cash flow information (Note 15) 
+The accompanying notes are an integral part of these financial statements. 
+F-6
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+December 31, 2012, 2011 and 2010 
+NOTE 1 — NATURE OF OPERATIONS 
+Matador Resources Company (“Matador” or the “Company”) is an independent energy company engaged in
+the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Matador’s current operations
+are focused primarily in the oil and liquids rich Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. In addition to these primary operating areas, Matador has a growing acreage position in Southeast New
+Mexico and West Texas where the Company plans to begin exploring the Wolfcamp and Bone Spring plays during 2013. Matador also has a large exploratory position in Southwest Wyoming and adjacent areas in Utah and Idaho where the Company is testing the
+Meade Peak shale. 
+On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation
+founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of a corporate reorganization that was completed on August 9, 2011, the former Matador Resources Company became a wholly-owned subsidiary
+of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company. 
+MRC Energy Company holds the primary assets of the Company and has four wholly-owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal
+Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts oil and natural gas exploration and development activities in Southeast New Mexico. MRC Rockies Company conducts oil and
+natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal
+Systems, LP which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations and also transports limited quantities of third-party natural gas. 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Basis of Presentation 
+The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned subsidiary, MRC Energy
+Company, as well as the accounts of MRC Energy Company’s four wholly-owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts of Longwood
+Gathering and Disposal Systems, LP. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The Company’s operations are
+conducted in the one segment generally referred to as the oil and natural gas exploration and production industry. All significant intercompany balances and transactions have been eliminated in consolidation. 
+Reclassifications 
+Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These
+reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. 
+F-7
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the
+amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and
+expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.
+The Company’s consolidated financial statements are based on a number of significant estimates, including oil and
+natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and
+future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves
+estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by
+the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. 
+Cash and Cash Equivalents 
+The Company considers all highly liquid investments with an original maturity of thirty (30) days or less as cash equivalents, and
+cash equivalents are recorded at market. Except for small cash balances held in the Company’s operating accounts to conduct its ongoing business, the remainder of the Company’s cash equivalents during the year ended December 31, 2010
+was held in money market accounts composed of United States Treasury securities offering daily liquidity. The Company had no cash equivalents as of December 31, 2012 or 2011. 
+Certificates of Deposit 
+Certificates of deposit (“CD’s”) are highly liquid, short-term investments with an original maturity of more than 30 days
+but not more than one year. Each CD is recorded at market and is fully insured by the Federal Deposit Insurance Corporation. 
+Accounts Receivable 
+The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see Note 14). Due to the nature
+of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling,
+completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the
+Company serves 
+F-8
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date, respectively, and are stated at amounts due from purchasers and industry
+partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. 
+The Company reviews its need for an allowance for doubtful accounts on a periodic basis, and determines the allowance, if any, by considering the length of time past due, previous loss history, future net
+revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its
+accounts receivable for any reporting period presented. 
+The Company wrote off receivables of $24,229 in 2011; there were no
+receivables written off in 2012 or 2010. When necessary, the Company accounts for a write off by recording the loss as a reduction of accounts receivable once the specific account has been determined to be uncollectible. 
+Lease and Well Equipment Inventory 
+Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future
+well operations or equipment held for sale. 
+Property and Equipment 
+The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of
+accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center
+representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both
+productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production,
+selling or general corporate administrative activities. The Company capitalized $2.6 million, $2.0 million and $1.6 million of its general and administrative costs in 2012, 2011 and 2010, respectively. The Company capitalized $1.6 million and $1.3
+million of its interest expense for the years ended December 31, 2012 and 2011, respectively. The Company recorded only $3,235 in interest expense for the year ended December 31, 2010. As a result, the Company capitalized no interest
+expense for the year ended December 31, 2010. 
+The net capitalized costs of oil and natural gas properties are limited to
+the lower of unamortized costs less related deferred income taxes or the cost ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. Beginning January 1, 2011, the need for a full-cost
+ceiling impairment is assessed on a quarterly basis. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and
+unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income
+F-9
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs for developing these reserves. The
+fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. 
+The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the
+commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are
+estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on
+unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period January through December 2012, these average oil and natural gas prices were $91.21 per barrel and $2.757 per
+MMBtu, respectively. For the period January through December 2011, these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. For the period January through December 2010, these average oil and natural gas
+prices were $75.96 per barrel and $4.376 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality,
+transportation fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation fees and regional price differentials. 
+During the second quarter ended June 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded
+the full-cost ceiling by $21.3 million. The Company recorded an impairment charge of $33.2 million to its net capitalized costs and a deferred income tax credit of $11.9 million related to the full-cost ceiling limitation. During the third quarter
+ended September 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $2.3 million. The Company recorded an impairment charge of $3.6 million to its net capitalized costs and a
+deferred income tax credit of $1.3 million related to the full-cost ceiling limitation. During the fourth quarter ended December 31, 2012, the Company’s net capitalized costs exceeded the cost center ceiling by $17.3 million. The Company
+recorded an impairment charge of $26.7 million to its net capitalized costs and a deferred income tax credit of $9.4 million related to the full-cost ceiling limitation. These charges for the second, third and fourth quarters of 2012 are reflected
+in the Company’s consolidated statement of operations for the year ended December 31, 2012. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will
+determine the Company’s actual ceiling test computation and impairment analyses in future periods. 
+During the first
+quarter ended March 31, 2011, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $23.0 million. The Company recorded an impairment charge of $35.7 million to its net capitalized costs
+and a deferred income tax credit of $12.7 million related to the full-cost ceiling limitation. These charges are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2011. The Company recorded no
+impairment to its net capitalized costs and no corresponding charge to its consolidated statement of operations for the year ended December 31, 2010. 
+F-10
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion
+and the net carrying value of the Company’s assets on its balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. 
+Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates
+of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon
+changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling
+activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well
+is not productive. 
+Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no
+gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed
+as incurred. Significant workovers that increase the properties’ reserves are capitalized. 
+Other property and equipment
+are stated at cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life (5 to 10 years) using the straight-line method. Support equipment and facilities include the pipelines and salt water disposal
+systems owned by Longwood Gathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the
+term of the lease. 
+Asset Retirement Obligations 
+The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of
+fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet.
+Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statement of operations. In general, the Company’s future asset retirement obligations relate to future costs associated with
+plugging and abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including
+future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in its estimate or if federal
+or state regulators enact new plugging and abandonment requirements. At the time of actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the
+extent that the actual costs are different from the estimated liability. 
+F-11
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Derivative Financial Instruments 
+From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil,
+natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide the Company with downside price protection through the purchase
+of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless
+collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. The Company’s derivative
+financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company
+recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations (see Note 11). The fair value of the Company’s derivative financial instruments is determined using purchase and sale
+information available for similarly traded securities. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and losses from valuation changes in the remaining unsettled derivative financial
+instruments are reported under “Revenues” in our consolidated statement of operations. 
+Revenue Recognition 
+The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes
+revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas
+and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. 
+Stock-Based Compensation 
+Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”).
+The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. During 2012, all stock option awards granted under the 2012 Incentive Plan were non-qualified options and the
+associated compensation expense is recognized over the vesting period, which is typically four years. All stock option awards granted in 2012 are classified as equity instruments due to the methods of exercise specified in the 2012 Incentive Plan.
+Compensation expense for restricted stock and restricted stock unit grants awarded in 2012 was recognized immediately or over the vesting period, which is typically three to four years. 
+The Company did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under the 2003 Stock and
+Incentive Plan (the “2003 Plan”), and since November 22, 2010, these awards have been accounted for as liability instruments. No additional stock-based compensation will be awarded under the 2003 Plan. Non-qualified stock option
+grants awarded under the 2003 Plan typically vested upon issuance, while incentive stock option grants awarded under the 2003 Plan typically vest over 
+F-12
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Compensation expense for restricted stock grants awarded under the 2003 Plan
+was recognized immediately or over the vesting period, which was typically three years. 
+At December 31, 2012 and 2011,
+the Company used the fair value method to measure and recognize the liability and equity associated with its outstanding stock options. At December 31, 2010, the Company measured and recognized the liability associated with its outstanding
+stock options using the intrinsic value method. 
+Prior to November 22, 2010, all of the Company’s then-outstanding
+stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, the Company changed its method of accounting for
+its then-outstanding stock options, reclassifying all of its then-outstanding stock options from equity to liability instruments. This change was made as a result of the Company purchasing shares from certain of its employees to assist them in the
+exercise of outstanding options of the Company’s Class A common stock. At December 31, 2012, we continue to account for all stock options granted under the 2003 Plan as liability instruments. 
+The Company’s consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 include a stock-based
+compensation (non-cash) expense of $0.1 million, $2.4 million and $0.9 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.1 million, $0.2 million and $0.2
+million in 2012, 2011 and 2010, respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company. 
+Income Taxes 
+The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates
+the probability of realizing the future benefits of its deferred tax assets and provides a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more
+likely than not criteria for recognition. 
+The Company recognizes the tax benefit of an uncertain tax position only if it is
+more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the
+financial statements is the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. Management believes that the material positions taken by the Company would more likely than
+not be sustained by examination. At December 31, 2012 and 2011, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. 
+When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related
+to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income tax for the years ended December 31, 2012, 2011 and 2010. 
+F-13
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Earnings Per Common Share 
+The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings
+per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. 
+Prior to consummation of the Company’s initial public offering (the “Initial Public Offering,” see Note 10) in
+February 2012, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for
+the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during 2012 totaled $27,643. Dividends declared during 2011 and 2010 totaled $274,853 in each year. Class B dividends declared during the fourth quarter of
+2011 and the first quarter of 2012 were paid during the first quarter of 2012 totaling $96,356. As of December 31, 2012, the Company has not paid any dividends to holders of the Class A shares. Concurrent with the completion of the Initial
+Public Offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. The Class A common stock is now referred to as the “common stock.” 
+The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted distributed and
+undistributed earnings per common share as reported for the years ended December 31, 2012, 2011 and 2010 (in thousands, except per share data). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Net income (loss) — numerator 
+Net (loss) income 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+Less dividends to Class B shareholders — distributed earnings 
+(28 
+) 
+(275 
+) 
+(275 
+) 
+Undistributed (loss) earnings 
+$ 
+(33,289 
+) 
+$ 
+(10,584 
+) 
+$ 
+6,102 
+Weighted average common shares outstanding — denominator 
+Basic 
+Class A 
+53,852 
+41,687 
+40,007 
+Class B 
+105 
+1,031 
+1,031 
+Total 
+53,957 
+42,718 
+41,038 
+Diluted 
+Class A 
+Weighted average common shares outstanding for basic earnings (loss) per share 
+53,852 
+41,687 
+40,007 
+Dilutive effect of options 
+– 
+– 
+96 
+Class A weighted average common shares outstanding — diluted 
+53,852 
+41,687 
+40,103 
+Class B 
+Weighted average common shares outstanding — no associated dilutive shares 
+105 
+1,031 
+1,031 
+Total diluted weighted average common shares outstanding 
+53,957 
+42,718 
+41,134 
+F-14
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Earnings (loss) per common share 
+Basic 
+Class A 
+Distributed earnings 
+$ 
+– 
+$ 
+– 
+$ 
+– 
+Undistributed (loss) earnings 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Total 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Class B 
+Distributed earnings 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+Undistributed (loss) earnings 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Total 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+Diluted 
+Class A 
+Distributed earnings 
+$ 
+– 
+$ 
+– 
+$ 
+– 
+Undistributed (loss) earnings 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Total 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Class B 
+Distributed earnings 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+Undistributed (loss) earnings 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+Total 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+A total of 1,067,069 and 1,024,500 options to purchase shares of the Company’s Class A common stock and
+162,368 and zero restricted stock units were excluded from the calculations above for the years ended December 31, 2012 and 2011, respectively, because their effects were anti-dilutive. Additionally, 305,807 restricted shares, which are
+participating securities, were excluded from the calculations above for the year ended December 31, 2012 as the security holders do not have the obligation to share in the losses of the Company. There were no participating securities at
+December 31, 2011. 
+Fair Value Measurements 
+The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is the price that would be received to
+sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company follows FASB guidance establishing a fair value hierarchy that prioritizes the inputs to valuation
+methods used to measure fair value. 
+F-15
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Credit Risk 
+The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility.
+These transactions expose the Company to potential credit risk from its counterparties. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company believes that any credit risk
+posed is insignificant and is offset by the creditworthiness of its customer base and industry partners. 
+Risks and Uncertainties 
+As an oil and natural gas exploration and production company focused on finding and developing its own prospects and reserves, the
+Company’s success is highly dependent on the results of its exploration and development program. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reserves will be discovered.
+In addition, there are uncertainties as to the future costs or timing of drilling, completing and producing wells. Poor results from the Company’s exploration and development activities could limit the Company’s ability to replace and grow
+reserves and materially and adversely affect the Company’s financial position, results of operations and cash flows. 
+As
+a result of the Company’s sale of certain assets to Chesapeake Louisiana, L.P. (“Chesapeake”) in 2008, the Company does not operate its most significant natural gas asset, that being the deep rights to explore for and develop the
+Haynesville shale formation (underlying its existing Cotton Valley production) on the Company’s Elm Grove/Caspiana leasehold in Northwest Louisiana. Although the Company has reserved the right to participate for a proportionately reduced 25%
+working interest in all wells that Chesapeake drills or participates in to develop the Haynesville on this acreage, and although the Company has the right to propose the drilling of Haynesville wells on these properties, the Company may have limited
+influence on when, how and at what pace these properties are developed. This could impact the Company’s ability to replace and grow reserves and materially and adversely affect the Company’s financial position, results of operations and
+cash flows. In addition, in 2012, 2011 and 2010, the Company acquired other non-operated acreage positions in Northwest Louisiana that it believes to be prospective for the Haynesville shale. The Company has, or will have, small, non-operated
+working interests in the Haynesville units including these properties, and as a result, the Company will have limited influence on when, how and at what pace these properties are developed. 
+Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The
+process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also
+requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes,
+development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. Any significant variance could materially and adversely affect the Company’s future reserves
+estimates, financial position, results of operations and cash flows. 
+F-16
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Historically, the market for oil, natural gas and natural gas liquids has experienced
+significant price fluctuations, and this has been particularly evident in recent years. Oil, natural gas and natural gas liquids prices are impacted by supply and demand, both domestic and international, seasonal variations caused by changing
+weather conditions, political conditions, governmental regulations, the availability, proximity and capacity of gathering, processing and transportation systems for natural gas and natural gas liquids and numerous other factors. Increases or
+decreases in prices received could have a significant and material impact on the Company’s future reserves estimates, financial position, results of operations and cash flows. 
+To mitigate its exposure to fluctuations in oil, natural gas and natural gas liquids prices, the Company, from time to time, enters into
+hedging arrangements with respect to a portion of its oil, natural gas and natural gas liquids production. Decisions as to whether and at what production volumes to hedge are difficult and depend on market conditions and the Company’s forecast
+of future production and commodity prices, and the Company may not always employ the optimal hedging strategy. 
+The federal,
+state and local governments in the areas in which the Company operates or has assets impose taxes on the oil and natural gas products sold, and sales and use taxes are charged on significant portions of the Company’s drilling, completion and
+operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators
+and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like Matador. Among
+other issues, President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could materially and adversely affect the
+Company’s future financial position, results of operations and cash flows. 
+Recent Accounting Pronouncements 
+Balance Sheet. In January 2013, the FASB issued Accounting Standards Update, or ASU, 2013-01, Balance Sheet. The ASU
+clarifies the scope of ASU 2011-11 to limit the application of ASU 2011-11 to derivatives accounted for in accordance with Accounting Standards Codification, or ASC, 815, Derivatives and Hedging , including bifurcated embedded derivatives,
+repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or
+similar agreement. The adoption of ASU 2013-01 is not expected to have a material effect on our consolidated financial statements, but may require certain additional disclosures. 
+Balance Sheet. In December 2011, the FASB issued ASU 2011-11 , Balance Sheet. The requirements amend the disclosure
+requirements related to offsetting in ASC 210-20-50 . The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with
+either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The adoption of ASU
+2011-11 is 
+F-17
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+not expected to have a material effect on the Company’s consolidated financial statements, but may require certain additional disclosures. The amendments in ASU 2011-11 are to be applied for
+annual reporting periods beginning on or after January 1, 2013 and are to be applied retrospectively for all periods presented. 
+Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS . ASU 2011-04 amends ASC 820,
+Fair Value Measurements , providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value
+measurement principles, clarifies the application of existing fair value measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. The Company adopted ASU 2011-04 on January 1, 2012;
+adoption did not have a material effect on the Company’s consolidated financial statements, but did require additional disclosures (see Note 12). 
+NOTE 3 — PROPERTY AND EQUIPMENT 
+The following table presents a summary of the Company’s property and equipment balances as of December 31,
+2012 and 2011 (in thousands). 
+December 31, 
+2012 
+2011 
+Oil and natural gas properties 
+Evaluated (subject to amortization) 
+$ 
+763,527 
+$ 
+423,945 
+Unproved and unevaluated (not subject to amortization) 
+Incurred in 2012 
+36,488 
+– 
+Incurred in 2011 
+24,138 
+60,934 
+Incurred in 2010 
+70,417 
+80,593 
+Incurred in 2009 and prior 
+18,632 
+21,071 
+Total unproved and unevaluated 
+149,675 
+162,598 
+Total oil and natural gas properties 
+913,202 
+586,543 
+Accumulated depletion 
+(344,609 
+) 
+(201,543 
+) 
+Net oil and natural gas properties 
+568,593 
+385,000 
+Other property and equipment 
+Computer equipment 
+834 
+787 
+Furniture 
+793 
+458 
+Software 
+1,355 
+1,111 
+Other equipment 
+196 
+194 
+Leasehold improvements 
+644 
+627 
+Support equipment and facilities 
+23,436 
+15,587 
+Total other property and equipment 
+27,258 
+18,764 
+Accumulated depreciation 
+(4,761 
+) 
+(3,899 
+) 
+Net other property and equipment 
+22,497 
+14,865 
+Net property and equipment 
+$ 
+591,090 
+$ 
+399,865 
+F-18
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 3 — PROPERTY AND EQUIPMENT — Continued 
+The following table provides a breakdown of the Company’s unproved and unevaluated
+property costs not subject to amortization as of December 31, 2012 and the year in which these costs were incurred (in thousands). 
+Description 
+2012 
+2011 
+2010 
+2009 and 
+prior 
+Total 
+Costs incurred for 
+Property acquisition 
+$ 
+29,165 
+$ 
+21,748 
+$ 
+70,417 
+$ 
+18,632 
+$ 
+139,962 
+Exploration wells 
+4,680 
+1,932 
+– 
+– 
+6,612 
+Development wells 
+2,573 
+– 
+– 
+– 
+2,573 
+Capitalized interest 
+70 
+458 
+– 
+– 
+528 
+Total 
+$ 
+36,488 
+$ 
+24,138 
+$ 
+70,417 
+$ 
+18,632 
+$ 
+149,675 
+Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may
+also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization
+base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating
+or economic conditions. 
+Property acquisition costs incurred in 2012 were related primarily to the Company’s leasing and
+acquisition activities in the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Delaware Basin in West Texas. 
+Property acquisition costs incurred in 2011 were related primarily to the Company’s leasing and acquisition activities in the Eagle Ford shale play in South Texas. The 2010 property acquisition costs
+were related primarily to the Company’s leasing activities in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. These costs are associated with acreage for which proved reserves have yet to be
+assigned. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base.
+The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within three to five years. 
+Property acquisition costs incurred in 2009 and prior years were related primarily to the Company’s leasing activities in the
+Haynesville shale play in Northwest Louisiana and in Southwest Wyoming, Northeast Utah and Southeast Idaho. During 2011, the Company drilled its first exploration well on its acreage in Southwest Wyoming. We re-entered this vertical well in late
+2012 and drilled a horizontal lateral that will be completed in 2013. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within two to four years.
+F-19
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 3 — PROPERTY AND EQUIPMENT — Continued 
+Costs excluded from amortization also include those costs associated with exploration
+and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis, as these wells are completed and proved reserves are established or confirmed. These costs totaled $7.3
+million at December 31, 2012. Of this total, $4.7 million was associated with exploration wells and $2.6 million was associated with development wells. The Company anticipates that the entire $7.3 million associated with these wells in progress
+at December 31, 2012 will be transferred to the amortization base during 2013. At December 31, 2012, there were $1.9 million in exploratory well costs excluded from amortization that were incurred in years prior to 2012, all associated
+with the exploration well in Southwest Wyoming. The Company plans to complete and test this well in 2013 and anticipates that the entire $1.9 million incurred in 2011 will also be transferred to the amortization base during 2013. 
+NOTE 4 — ASSET RETIREMENT OBLIGATIONS 
+The following table summarizes the changes in the Company’s asset retirement obligations for the years ended
+December 31, 2012 and 2011 (in thousands). 
+Year ended December 31, 
+2012 
+2011 
+Beginning asset retirement obligations 
+$ 
+4,270 
+$ 
+3,695 
+Liabilities incurred during period 
+1,243 
+187 
+Revisions in estimated cash flows 
+– 
+312 
+Liabilities settled during period 
+– 
+(133 
+) 
+Accretion expense 
+256 
+209 
+Ending asset retirement obligations 
+$ 
+5,769 
+$ 
+4,270 
+At December 31, 2012 and 2011, $660,303 and $334,500, respectively, of the Company’s asset retirement
+obligations were classified as current liabilities and included in “accrued liabilities” in the Company’s consolidated balance sheets, based on the expected timing of payments. 
+NOTE 5 — ASSET SALES AND IMPAIRMENT 
+In December 2012, the Company recorded an impairment to reduce the remaining balance of its drilling rig parts held in
+inventory to zero following a determination that there was no current market for these parts. The carrying value of the inventory was reduced to zero and a charge of $425,000 was recorded to the consolidated statement of operations. In addition, the
+Company recorded a loss of approximately $60,000 on certain other equipment that was sold during 2012. 
+In December 2011, the
+Company recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the
+inventory was reduced by $17,500 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In December 2011, the Company also recorded an impairment to some of its equipment held in inventory
+following a determination that the current market value of the equipment, consisting primarily of pipe and other 
+F-20
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 5 — ASSET SALES AND IMPAIRMENT — Continued 
+equipment, was less than the cost. The carrying value of the inventory was reduced by $22,276 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of
+operations. In addition, the Company recorded a loss of $113,757 on certain other equipment that was sold during 2011. 
+In
+December 2010, the Company wrote off the Boise South Pipeline asset in Orange County, Texas from its Longwood Gathering and Disposal Systems, LP subsidiary and recorded a net loss of $173,690. The decision to write off this asset resulted from the
+fact that natural gas was no longer being put through this pipeline, nor was natural gas expected to be put through this pipeline in the future. In December 2010, the Company also recorded an impairment to some of its equipment held in inventory
+following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the inventory was reduced by $50,000 on the balance sheet, and a corresponding charge
+was recorded to the consolidated statement of operations. 
+NOTE 6 — REVOLVING CREDIT AGREEMENT 
+In December 2011, the Company entered into its second amended and restated senior secured revolving Credit Agreement
+for which Comerica Bank served as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company, a wholly-owned subsidiary of Matador Resources Company, was
+the borrower under the amended Credit Agreement. Borrowings were secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned
+subsidiaries, which were also guarantors. In addition, all obligations under the Credit Agreement were guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with one of the lenders under the Credit
+Agreement (or an affiliate thereof) were also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. 
+The amount of the borrowings under the second amended and restated Credit Agreement were limited to the lesser of $400.0 million or the borrowing base, which was determined by the lenders based primarily
+on the estimated value of the Company’s proved oil and natural gas reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which the Company
+has no control. At December 31, 2011, the borrowing base was $125.0 million and the Company had $113.0 million in outstanding borrowings under the Credit Agreement. In January 2012, the Company borrowed an additional $10.0 million to finance a
+portion of its working capital requirements, bringing the then-outstanding indebtedness under the Credit Agreement to $123.0 million. Following the completion of the Initial Public Offering, the Company used a portion of the net proceeds to repay
+the then-outstanding $123.0 million under its Credit Agreement in February 2012, at which time the borrowing base was reduced to $100.0 million. On February 28, 2012, the borrowing base was increased to $125.0 million pursuant to a special
+borrowing base redetermination made at the Company’s request. This borrowing base increase was determined by the lenders based upon, among other items, the increase in the Company’s proved oil and natural gas reserves at December 31,
+2011. 
+On September 28, 2012, the Company entered into its third amended and restated senior secured revolving Credit
+Agreement. Among other things, this amendment increased the maximum facility amount 
+F-21
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+from $400.0 million to $500.0 million, increased the borrowing base from $125.0 million to $200.0 million and named Royal Bank of Canada (“RBC”) as the administrative agent. In
+addition, the amendment provided for a conforming borrowing base of $165.0 million. The borrowing base will automatically be reduced to the conforming borrowing base on the earlier of (i) December 31, 2013 or (ii) the closing of a
+secondary public offering of equity interests that results in net cash proceeds to the Company in an amount greater than or equal to $25.0 million. The Credit Agreement matures December 29, 2016. MRC Energy Company is the borrower under the
+Credit Agreement. Borrowings are secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In
+addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also
+secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. 
+The borrowing base under the
+Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at June 30 and December 31 of each year. Both
+the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the fourth quarter of 2012, the Company requested one such unscheduled redetermination, and on
+December 20, 2012, the borrowing base was increased from $200.0 million to $215.0 million as a result of the lenders’ review of the Company’s proved oil and natural gas reserves at September 30, 2012. In connection with this
+borrowing base redetermination, the conforming borrowing base was increased to $180.0 million at December 20, 2012. In addition, during the first quarter of 2013, the lenders completed their review of the Company’s proved oil and natural
+gas reserves at December 31, 2012, and as a result, on March 11, 2013, the borrowing base was increased to $255.0 million and the conforming borrowing base was increased to $220.0 million (see Note 18). This most recent redetermination
+constitutes the regularly scheduled May 1 redetermination. In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which will be determined based on
+market conditions at the time of the borrowing base increase. If the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory
+in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months. 
+The Company incurred $0.8 million of additional deferred loan costs in connection with the amendment and restatement of the Credit
+Agreement in September 2012 and approximately $0.1 million of additional deferred loan costs in connection with the borrowing base increase in December 2012. These costs were included with the remaining unamortized portion of the deferred loan costs
+of $0.8 million incurred when the Company entered into the Credit Agreement in March 2008 as well as the second amended and restated Credit Agreement on December 30, 2011. As a result, total deferred loan costs are $1.6 million at
+December 31, 2012, and these costs are being amortized over the term of the agreement, which approximates the amortization of these costs using the effective interest method. 
+F-22
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+Between March 1, 2012 and December 31, 2012, the Company borrowed $150.0
+million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures. At December 31, 2012, the Company had $150.0 million in borrowings outstanding under the Credit Agreement, approximately $1.1
+million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $63.9 million available for additional borrowings. At December 31, 2012, the outstanding borrowings bore interest at an effective interest rate
+of approximately 3.3% per annum. 
+From January 1 through March 14, 2013, the Company borrowed an additional
+$30.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures. At March 14, 2013, the Company had $180.0 million in borrowings outstanding under the Credit Agreement, approximately
+$1.3 million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $73.7 million available for additional borrowings (see Note 18). 
+If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate on
+such day, plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 2.25% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrows funds as a
+Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which
+RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.75% to 3.25% of such outstanding loan depending on the level of
+borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is
+also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees as interest expense and in its interest
+rate calculations and related disclosures. 
+Key financial covenants under the third amended and restated Credit Agreement
+require the Company to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at
+the end of each fiscal quarter beginning March 31, 2013 and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less. In connection with the March 11,
+2013 borrowing base redetermination, the Credit Agreement was amended to delay first measurement of the current ratio until March 31, 2014 (see Note 18). 
+Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s, along with its subsidiaries’, ability to take certain actions, including, but not limited
+to, the following: 
+• 
+incur indebtedness or grant liens on any of its assets; 
+• 
+enter into commodity hedging agreements; 
+F-23
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+• 
+declare or pay dividends, distributions or redemptions; 
+• 
+merge or consolidate; 
+• 
+make any loans or investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+engage in certain asset dispositions, including a sale of all or substantially all of its assets. 
+If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and
+exercise other rights and remedies. Events of default include, but are not limited to, the following events: 
+• 
+failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount
+within certain grace periods; 
+• 
+failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain
+instances, to certain grace periods; 
+• 
+bankruptcy or insolvency events involving the Company or its subsidiaries; and 
+• 
+a change of control, as defined in the Credit Agreement. 
+At December 31, 2012, the Company believes that it was in compliance with the terms of its Credit Agreement. 
+F-24
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 7 — INCOME TAXES 
+Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying
+values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2012 and 2011, respectively, is as follows (in thousands). 
+December 31, 
+2012 
+2011 
+Current deferred tax assets 
+Property and equipment 
+$ 
+233 
+$ 
+113 
+Other 
+869 
+Net operating loss carryforwards 
+– 
+13 
+Total current deferred tax assets 
+1,102 
+126 
+Valuation allowance on current deferred tax assets 
+(202 
+) 
+– 
+Total current deferred tax assets, net of valuation allowance 
+900 
+126 
+Current deferred tax liabilities 
+Unrealized gain on derivatives 
+(1,311 
+) 
+(2,998 
+) 
+Other 
+– 
+(152 
+) 
+Total current deferred tax liabilities 
+(1,311 
+) 
+(3,150 
+) 
+Net current deferred tax liability 
+$ 
+(411 
+) 
+$ 
+(3,024 
+) 
+Non-current deferred tax assets 
+Net operating loss carryforwards 
+$ 
+44,654 
+$ 
+24,034 
+Alternative minimum tax carryforward 
+6,660 
+6,660 
+Total non-current deferred tax assets 
+51,314 
+30,694 
+Valuation allowance on non-current deferred tax assets 
+(10,058 
+) 
+– 
+Total non-current deferred tax assets, net of valuation allowance 
+41,256 
+30,694 
+Non-current deferred tax liabilities 
+Unrealized gain on derivatives 
+(262 
+) 
+(324 
+) 
+Property and equipment 
+(36,363 
+) 
+(27,070 
+) 
+Other 
+(4,220 
+) 
+(1,706 
+) 
+Total non-current deferred tax liabilities 
+(40,845 
+) 
+(29,100 
+) 
+Net non-current deferred tax asset 
+$ 
+411 
+$ 
+1,594 
+At December 31, 2012, the Company had net operating loss carryforwards of $123.3 million for federal income tax
+purposes and $30.3 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss
+carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the state of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards
+expire beginning in 2027. 
+F-25
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 7 — INCOME TAXES — Continued 
+At June 30, 2012, the net capitalized costs of the Company’s oil and natural
+gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million. As a result, the Company recorded an impairment charge of $33.2 million to the net capitalized costs of its oil and natural gas properties and a
+deferred income tax credit of $11.9 million. At September 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million. As a result,
+the Company recorded an impairment charge of $3.6 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $1.3 million. This deferred income tax credit exceeded the Company’s deferred tax
+liabilities at September 30, 2012. As a result, the Company established a valuation allowance of $2.4 million at September 30, 2012 due to uncertainties regarding the future realization of its deferred tax assets. At December 31,
+2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million. As a result, the Company recorded an impairment charge of $26.7 million to the
+net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $9.4 million. This deferred income tax credit exceeded the Company’s deferred tax liabilities at December 31, 2012. As a result, the Company
+increased the previously established valuation allowance by $7.9 million to maintain a full valuation allowance of $10.3 million against the Company’s net deferred tax assets. 
+The Company also recorded an impairment charge of $23.0 million to its net capitalized costs, net of a deferred income tax credit of
+$12.7 million related to the full-cost ceiling limitation during the first quarter ended March 31, 2011. This deferred income tax credit exceeded the Company’s deferred tax liabilities at March 31, 2011. As a result, the Company
+established a valuation allowance at March 31, 2011 and retained a valuation allowance until the fourth quarter of the year ended December 31, 2011 due to uncertainties regarding the future realization of its deferred tax assets. At
+December 31, 2011, the Company assessed the valuation allowance and determined that the allowance was no longer required. 
+F-26
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 7 — INCOME TAXES — Continued 
+The income tax expense reconciled to the tax computed at the statutory federal rate for
+the years ended December 31, 2012, 2011 and 2010, respectively, is as follows (in thousands). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Current income tax (benefit) provision 
+State income tax 
+$ 
+– 
+$ 
+(46 
+) 
+$ 
+– 
+Federal alternative minimum tax 
+– 
+– 
+(1,411 
+) 
+Net current income tax benefit 
+– 
+(46 
+) 
+(1,411 
+) 
+Deferred income tax provision (benefit) 
+Federal tax expense at statutory rate (34%) 
+(11,767 
+) 
+(5,319 
+) 
+3,365 
+Statutory depletion carryforward 
+– 
+231 
+(157 
+) 
+State income tax 
+(819 
+) 
+(435 
+) 
+– 
+Change in state rate applied 
+– 
+– 
+275 
+Nondeductible expense 
+(122 
+) 
+48 
+38 
+Permanent differences (1) 
+1,018 
+– 
+– 
+Federal alternative minimum tax 
+– 
+– 
+1,411 
+Change in valuation allowance 
+10,260 
+– 
+– 
+Net deferred income tax (benefit) provision 
+(1,430 
+) 
+(5,475 
+) 
+4,932 
+Total income tax (benefit) provision 
+$ 
+(1,430 
+) 
+$ 
+(5,521 
+) 
+$ 
+3,521 
+(1) 
+Amount is primarily attributable to stock-based compensation. 
+The Company files a United States federal income tax return and several state tax returns, a number of which remain
+open for examination. The tax years open for examination for the federal tax return are 2009, 2010, 2011 and 2012. The tax years open for examination by the state of Texas are 2008, 2009, 2010, 2011 and 2012. The tax years open for examination by
+the state of New Mexico are 2009, 2010, 2011 and 2012. The tax years open for examination by the state of Louisiana are 2009, 2010, 2011 and 2012. 
+NOTE 8 — STOCK-BASED COMPENSATION 
+Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards 
+In 2003 the Company’s Board of Directors and shareholders approved the Matador Resources Company 2003 Stock and Incentive Plan (the
+“2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of Class A common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under
+the 2003 Plan included employees, directors, contractors or advisors of the Company. 
+Effective January 1, 2012, the Board
+of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. The 2012 Incentive
+Plan provides for a maximum of 
+F-27
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+4,000,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or
+other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key
+employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all
+awards outstanding under that plan have been settled. 
+The 2003 Plan and the 2012 Incentive Plan are administered by the
+independent members of the Board of Directors, which determines the number of options or restricted shares to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common
+stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted during 2012 were granted under the 2012 Incentive Plan, while all stock-based compensation awards granted prior to January 1, 2012 were
+granted under the 2003 Plan. 
+Stock Options 
+Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair
+market value on the date of grant, a typical vesting period of four years and a typical maximum term of five or ten years. 
+On
+November 22, 2010, the Company changed its method of accounting for its then-outstanding stock options granted under the 2003 Plan, reclassifying all then-outstanding stock options from equity to liability instruments (see Note 2). At
+December 31, 2010, the Company measured and recognized the liability associated with its outstanding stock options using the intrinsic value method and an estimated fair value of $11.00 per share for the Company’s common stock. The fair
+value of equity stock option awards granted during the year ended December 31, 2010, prior to the reclassification, under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2010. 
+Stock option pricing model 
+Binomial Lattice 
+Expected option life 
+5.41 years 
+Risk-free interest rate 
+2.58% 
+Volatility 
+46.17% 
+Dividend yield 
+0.0% 
+Estimated forfeiture rate 
+11.15% 
+Weighted average fair value of stock option awards granted during the year 
+$3.02 
+Effective upon filing its initial Registration Statement with the SEC in August 2011, the Company adopted the fair
+value method and used an estimated fair value of $12.00 per share to measure and recognize the liability associated with its outstanding stock options. The Company recorded $1.1 million in additional general and administrative expenses during 2011
+due to this change in the valuation method from the intrinsic value method to the fair value method. 
+F-28
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+The Company granted no stock option awards during the year ended December 31, 2011.
+The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2012 and 2011. 
+2012 
+2011 
+Stock option pricing model 
+Black Scholes Merton 
+Black Scholes Merton 
+Expected option life 
+0.89 years 
+1.04 years 
+Risk-free interest rate 
+0.25% 
+0.37% 
+Volatility 
+54.28% 
+61.41% 
+Dividend yield 
+0.00% 
+0.00% 
+Estimated forfeiture rate 
+0.70% 
+1.04% 
+During 2012, the Company began granting stock-based compensation awards under the 2012 Incentive Plan. Stock option
+awards granted under this plan are accounted for as equity instruments. The weighted average grant date fair value was estimated using the following weighted average assumptions during the year ended December 31, 2012. 
+Stock option pricing model 
+Black Scholes Merton 
+Expected option life 
+4.44 years 
+Risk-free interest rate 
+0.71% 
+Volatility 
+71.16% 
+Dividend yield 
+0.00% 
+Estimated forfeiture rate 
+5.46% 
+Weighted average fair value of stock option awards granted during the year 
+$5.95 
+The Company estimated the future volatility of its common stock using the historical value of its peer group for a
+period of time commensurate with the expected term of the stock option due to the lack of historical trading data available for its common stock. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic
+14. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. 
+Summarized information about stock options outstanding at December 31, 2012 under the Company’s 2003 Plan and the 2012 Incentive Plan is as follows (in thousands, except price data). 
+Number of 
+options 
+Weighted 
+average 
+exercise price 
+Options outstanding at December 31, 2011 
+1,025 
+$ 
+9.75 
+Options granted 
+656 
+10.79 
+Options exercised 
+(296 
+) 
+9.00 
+Options forfeited 
+(248 
+) 
+11.43 
+Options expired 
+(70 
+) 
+9.95 
+Options outstanding at December 31, 2012 
+1,067 
+$ 
+10.19 
+F-29
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+Options outstanding
+at 
+December 31, 2012 
+Options exercisable at 
+December 31, 2012 
+Range of exercise prices 
+Shares 
+outstanding 
+Weighted 
+average 
+remaining 
+contractual 
+life 
+Weighted 
+average 
+exercise 
+price 
+Shares 
+exercisable 
+Weighted 
+average 
+exercise 
+price 
+$7.50-$9.00 
+139 
+6.34 years 
+$ 
+8.77 
+66 
+$ 
+8.75 
+$10.00-$13.33 
+928 
+2.37 years 
+$ 
+10.41 
+459 
+$ 
+10.32 
+At December 31, 2012, the aggregate intrinsic value was zero for both the outstanding options and the exercisable
+options, based on our quoted closing market price of $8.20 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2012 was 1.06 years. 
+The total intrinsic value of options exercised during the years ended December 31, 2012, 2011 and 2010 was $0.9 million, $0.2
+million and $2.2 million, respectively. The tax related benefit realized from the exercise of stock options totaled zero, zero and $0.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. 
+During the years ended December 31, 2012, 2011 and 2010, the Company recognized $(0.7) million, $2.1 million and $0.6 million,
+respectively, in stock compensation expense attributable to stock options. At December 31, 2012 and 2011, the Company had recorded $0.3 million and $0.3 million of long-term liabilities and $0.1 million and $2.9 million of current liabilities,
+respectively, related to its outstanding liability based stock options. The Company paid zero, $0.1 million and $0.4 million in settlement of liability based awards for the years ended December 31, 2012, 2011 and 2010, respectively. 
+At December 31, 2012, the total remaining unrecognized compensation expense related to unvested stock options was approximately $2.3
+million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was approximately 2.83 years. 
+The fair value of option shares vested during 2012, 2011 and 2010 was $0.3 million, $1.0 million and $2.4 million, respectively. 
+Restricted Stock, Restricted Stock Units and Common Stock 
+The
+Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the
+restrictions being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a term no longer than two years after vesting. No such elections were made with respect to the
+2012 restricted stock unit awards. The 2012 restricted stock awards included 116,841 performance based awards. These shares vest based on the outcome of the Company’s total shareholder return over a three-year period beginning March 19,
+2012 and ending April 15, 2015 as compared to a designated peer group. This award may result in the vesting of an aggregate of up to 116,841 restricted stock units in addition to the restricted stock grants. If the performance conditions are
+not met, however, this award may result in no performance based restricted stock being vested and no restricted stock units being vested. The fair value of this award was 
+F-30
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+estimated based on the most likely outcome of the award as determined by the Monte Carlo method. A total of 13,833 shares of restricted stock awards granted in 2012 vested immediately upon grant,
+and the remaining 2012 restricted stock and restricted stock units awards vest over the service period, which ranges from one year to a maximum of four years. 
+A summary of the non-vested restricted stock and restricted stock units as of December 31, 2012 is presented below (in thousands, except fair value). 
+Restricted Stock 
+Restricted Stock Units 
+Service Based 
+Performance Based 
+Service Based 
+Performance Based 
+Non-vested restricted stock and 
+restricted stock units 
+Shares 
+Weighted 
+average 
+fair 
+value 
+Shares 
+Weighted 
+average 
+fair 
+Value (1) 
+Shares 
+Weighted 
+average 
+fair 
+value 
+Shares 
+Weighted 
+average 
+fair 
+Value (1) 
+Non-vested at 
+January 1, 2012 
+8 
+$ 
+11.00 
+– 
+$ 
+– 
+– 
+$ 
+– 
+– 
+$ 
+– 
+Granted 
+207 
+9.66 
+117 
+13.24 
+54 
+10.04 
+117 
+– 
+Vested 
+(18 
+) 
+8.72 
+– 
+– 
+– 
+– 
+– 
+– 
+Forfeited 
+(15 
+) 
+10.76 
+(7 
+) 
+13.24 
+(2 
+) 
+11.02 
+(7 
+) 
+– 
+Non-vested at December 31, 2012 
+182 
+$ 
+9.72 
+110 
+$ 
+13.24 
+52 
+$ 
+10.00 
+110 
+$ 
+– 
+(1) 
+The fair value of these restricted stock units is reflected in the fair value of the performance based restricted stock, which was estimated based on
+the most likely outcome of the award as determined by the Monte Carlo method. 
+At December 31, 2012, the aggregate intrinsic value for the restricted stock and restricted stock units
+outstanding was $3.7 million as calculated based on the maximum number of shares of restricted stock, performance based restricted stock and restricted stock units vesting, using the stock price on December 31, 2012. 
+During the years ended December 31, 2012, 2011 and 2010, the Company recognized $0.7 million, approximately $44,000 and $0.1
+million, respectively, in stock compensation expense attributable to restricted stock and restricted stock units. 
+At
+December 31, 2012, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $3.0 million and the weighted average remaining requisite service period (vesting period)
+of all non-vested restricted stock and restricted stock units was approximately 2.23 years. 
+The fair value of restricted
+stock and restricted stock units vested during 2012, 2011 and 2010 was $44,000, $44,000 and $46,330, respectively. 
+The total
+tax benefit recognized for stock-based compensation was $0.3 million, $0.9 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. 
+F-31
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+In February 2013, options to purchase 408,000 shares of the Company’s common stock
+at $10.00 per share expired unexercised or were forfeited (see Note 18). 
+During the years ended December 31, 2012, 2011
+and 2010, the Company issued shares of common stock to certain members of its Board of Directors. The Company also issued shares of common stock to certain outside advisors who do not meet the definition of employees under ASC 718. The Company used
+the fair value of the stock issued on the grant date to recognize the expense related to these awards. The Company recognized $0.1 million, $0.2 million and $0.2 million in stock compensation expense attributable to these awards for the years ended
+December 31, 2012, 2011 and 2010, respectively. 
+In October 2008, the Company’s Board of Directors approved the
+adoption of the Employee Share Repurchase Program (“Repurchase Program”) authorizing the Company to repurchase shares of its Class A common stock from its employees, directors and officers, subject to certain conditions and
+restrictions. In 2010, the Company repurchased 117,505 shares of Class A common stock at $11.00 per share from thirteen employees (including the Executive Vice President, Chief Financial Officer and Chief Operating Officer, the Executive Vice
+President — Operations and the Vice President — Reservoir Engineering). No director nor the Company’s Chairman and Chief Executive Officer has ever participated in the Repurchase Program. The Company’s Board of Directors
+terminated the Repurchase Program in April 2011, and the Company is no longer authorized to repurchase shares of common stock from its employees, directors and officers. No shares were repurchased in 2011 prior to the termination of the Repurchase
+Program by the Board of Directors. 
+In October 2008, the Company’s Board of Directors approved the adoption of the
+Employee Option Exercise Loan Program (“Loan Program”), authorizing the Company to establish a loan program with a financial institution to assist its employees, directors and officers in the exercise of their outstanding options to
+purchase shares of Class A common stock, subject to certain conditions and restrictions outlined in the Loan Program. As part of the Loan Program, the Company provides the financial institution with a guaranty of repayment of the loan and makes
+deposits of funds in certificates of deposit to secure its guaranty. Notwithstanding the guaranty, these loans are fully recourse obligations of each loan recipient, and each loan recipient agrees to indemnify and reimburse the Company in full for
+all liabilities incurred by the Company in the event of the recipient’s default on the loan. Each loan recipient also pledges all shares purchased from the Company with the loan proceeds to further secure his or her obligations to the Company
+in return for its guaranty. No director nor the Company’s Chairman and Chief Executive Officer has ever participated in the Loan Program. 
+As of December 31, 2012, the Company had secured the loans of four employees pursuant to this Loan Program in the aggregate amount of $0.2 million. The Company considers the fair value of this
+aggregate guaranty to be minimal and has recorded no liability provision associated with this guaranty on its consolidated balance sheets in any reporting period presented. The Company’s Board of Directors terminated the Loan Program in April
+2011, and the Company is no longer authorized to provide financial guaranties for additional loans. No new loans were guaranteed in 2011 prior to the termination of the Loan Program by the Board of Directors. 
+F-32
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 9 — EMPLOYEE BENEFIT PLANS 
+401(k) Plan 
+Effective July 3, 2003, the Company established a defined contribution retirement plan. All full-time Company employees are eligible to join the plan the first day of the calendar month immediately
+following their date of employment. Each Participant may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation,
+referred to as the Employer’s Safe Harbor Non-Elective Contribution. The Company’s Safe Harbor match was approximately $0.2 million in each of 2012, 2011 and 2010. In addition, each year, the Company may determine and make a discretionary
+matching contribution as well as additional contributions. The Company’s discretionary matching contributions totaled $0.3 million, $0.2 million and $0.2 million in 2012, 2011 and 2010, respectively. The Company made no additional discretionary
+contributions in any reporting period presented. 
+NOTE 10 — COMMON STOCK 
+Dividends 
+At December 31, 2011 and 2010, the Company had issued two classes of common stock, Class A and Class B. In February 2012, upon the consummation of the Company’s Initial Public Offering, the
+Class B shares were converted to Class A shares, which are now referred to as common stock. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available
+for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared and paid during 2012 were $27,643. Dividends declared during 2011 and 2010 totaled $0.3 million in each year. Dividends for the fourth quarter of 2011
+were accrued and paid in January 2012. Dividends for the fourth quarter of 2010 and 2009 were accrued and paid in January 2011 and 2010, respectively. As of December 31, 2012, the Company has not paid any dividends to holders of the
+Class A shares. 
+Stock Offerings, Retirement and Issuances 
+On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the Initial
+Public Offering. The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC;
+Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc.; and Comerica Securities, Inc. On
+February 2, 2012, shares of the Company’s common stock began trading on the New York Stock Exchange under the symbol “MTDR” at an initial offering price of $12.00 per share. 
+Pursuant to its Prospectus dated February 1, 2012, the Company and the selling shareholders offered 13,333,334 shares of the
+Company’s common stock for sale. The Company offered 11,666,667 shares of its common stock, and the selling shareholders offered 1,550,000 shares. On February 7, 2012, the Company closed the Initial Public Offering and issued 11,666,667
+shares of its common stock pursuant to the Initial Public Offering. 
+F-33
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 10 — COMMON STOCK — Continued 
+The Company and the selling shareholders granted the underwriters the right to purchase
+up to an additional 2,000,000 shares of the Company’s common stock at the initial offering price of $12.00 per share, less the underwriters’ discounts and commissions, for a period of 30 days following the Initial Public Offering to cover
+over-allotments, with the Company offering 700,000 shares and the selling shareholders offering 1,300,000 shares. On March 2, 2012, the underwriters exercised their option to purchase an additional 1,550,000 shares, including the purchase of
+542,500 shares from the Company and the purchase of 1,007,500 shares from the selling shareholders. On March 7, 2012, the Company closed this transaction and issued 542,500 shares of its common stock pursuant to the underwriters’ exercise
+of the over-allotment. 
+Pursuant to the Initial Public Offering and the over-allotment, the Company issued a total of
+12,209,167 shares of its common stock at $12.00 per share and received estimated net proceeds of approximately $133.6 million after deducting the underwriters’ discounts and commissions and the estimated legal, accounting and other fees
+associated with the offering. The Company did not receive any proceeds from the sale of shares of its common stock by the selling shareholders. On February 8, 2012, the Company used the net proceeds of the offering to repay the $123.0 million
+in borrowings then outstanding under its Credit Agreement in full. The Company used the remaining net proceeds of the offering to fund a portion of its 2012 capital expenditures. 
+Concurrent with the completion of the Initial Public Offering, all 1,030,700 outstanding shares of the Company’s Class B common
+stock were converted to Class A common stock on a one-for-one basis. In addition, in February 2012, the Company issued an additional 295,500 shares of its Class A common stock pursuant to the exercise of stock options and received net
+proceeds of $2.7 million. The Class A common stock is now referred to as the common stock. 
+In October 2010, the Board of
+Directors approved and authorized the private offering and sale of additional shares of the Company’s Class A common stock at $11.00 per share in the period from October 2010 through January 2011. As of December 31, 2010, the Company
+sold approximately 1.9 million shares and received net proceeds of $20.5 million. In January 2011, the Company sold an additional 53,772 shares as part of this offering and received net proceeds of approximately $0.6 million. The Company also
+sold 11,000 shares of Class A common stock at $9.00 per share to an accredited investor and received gross and net proceeds of $99,000 in May 2010. 
+Treasury Stock 
+The increase of 21,876 shares in treasury stock
+outstanding during 2012 represents forfeitures of non-vested restricted stock awards. During 2010, the Company issued 6,000 shares of Class A common stock valued at $7.50-$9.00 per share from treasury stock. The Company also purchased
+1.1 million shares of Class A common stock for $9.00-$11.00 per share. These purchases included 1,000,000 shares of Class A common stock purchased from five shareholders, all advised by Wellington Management Company, in April 2010 at
+$9.00 per share, for a total of $9.0 million. 
+F-34
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS 
+From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk
+associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless collars and swap contracts. The Company records derivative financial instruments on its balance sheet as
+either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting
+periods currently in its consolidated statement of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using purchase and sale information available for similarly traded
+securities. Comerica Bank and RBC (or affiliates thereof) were the counterparties for our commodity derivatives at December 31, 2012. We have considered the credit standings of the counterparties in determining the fair value of our derivative
+financial instruments. 
+During 2012 and 2011, the Company entered into various costless collar contracts to mitigate its
+exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions is the arithmetic average of
+the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by these
+collars, the Company receives from its counterparties an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by these
+collars, the Company pays to its counterparties an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. 
+During 2012, the Company entered into various swap contracts to mitigate its exposure to fluctuations in oil prices, each with an established fixed price. For each calculation period, the specified price
+for determining the realized gain or loss pursuant to any of these transactions is the arithmetic average of the settlement prices for NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation
+period’s calendar month. When the settlement price is below the fixed price established by these swaps, the Company receives from its counterparties an amount equal to the difference between the settlement price and the fixed price multiplied
+by the contract oil volume. When the settlement price is above the fixed price established by these swaps the Company pays to its counterparties an amount equal to the difference between the settlement and the fixed price multiplied by the contract
+oil volume. 
+During 2012, 2011, and 2010, the Company entered into various costless collar transactions for natural gas, each
+with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to the Company pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas
+futures contract for the delivery month corresponding to the calculation period’s calendar month for the last day of that contract period. When the settlement price is below the price floor established by these collars, the Company receives
+from its counterparties an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by these collars, the Company
+pays to its counterparties an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. 
+F-35
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+During 2012, the Company entered into various swap contracts to mitigate its exposure to
+fluctuations in natural gas liquids (“NGL”) prices on a portion of its future anticipated NGL production, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to
+the Company pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET
+prop” on the pricing date. When the settlement price is below the fixed price established by these swaps, the Company receives from its counterparties an amount equal to the difference between the settlement price and the fixed price multiplied
+by the contract NGL volume. When the settlement price is above the fixed price established by these swaps, the Company pays to its counterparties an amount equal to the difference between the settlement price and the fixed price multiplied by the
+contract NGL volume. 
+At December 31, 2012, the Company had various costless collar contracts open and in place to
+mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2013 and 2014.
+At December 31, 2012, the Company had various swap contracts open and in place to mitigate its exposure to oil and NGL
+price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and fixed price. Each contract is set to expire at varying times during 2013. 
+F-36
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following is a summary of the Company’s open costless collar contracts for oil
+and natural gas and open swap contracts for oil and natural gas liquids at December 31, 2012. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Bbl/month) 
+Price 
+Floor 
+($/Bbl) 
+Price 
+Ceiling 
+($/Bbl) 
+Fair Value 
+of
+Asset 
+(thousands) 
+Oil 
+01/01/2013 - 03/31/2013 
+20,000 
+90.00 
+110.00 
+$ 
+122 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+85.00 
+102.25 
+96 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+90.00 
+115.00 
+980 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+85.00 
+110.40 
+471 
+Oil 
+01/01/2013 - 12/31/2013 
+20,000 
+85.00 
+108.80 
+418 
+Oil 
+01/01/2013 - 06/30/2014 
+8,000 
+90.00 
+114.00 
+666 
+Oil 
+01/01/2013 - 06/30/2014 
+12,000 
+90.00 
+115.50 
+1,036 
+Total open oil costless collar contracts 
+3,789 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(MMBtu/month) 
+Price 
+Floor 
+($/MMBtu) 
+Price 
+Ceiling 
+($/MMBtu) 
+Fair Value 
+of
+Asset 
+(Liability) 
+(thousands) 
+Natural Gas 
+01/01/2013 - 07/31/2013 
+150,000 
+4.50 
+5.75 
+1,154 
+Natural Gas 
+01/01/2013 - 12/31/2013 
+100,000 
+3.00 
+3.83 
+(146 
+) 
+Natural Gas 
+01/01/2013 - 12/31/2013 
+100,000 
+3.00 
+4.95 
+40 
+Natural Gas 
+01/01/2013 - 12/31/2013 
+100,000 
+3.00 
+4.96 
+41 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.37 
+19 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.42 
+27 
+Total open natural gas costless collar contracts 
+1,135 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Bbl/month) 
+Fixed 
+Price 
+($/Bbl) 
+Fair Value 
+of 
+Liability 
+(thousands) 
+Oil 
+01/01/2013 - 12/31/2013 
+10,000 
+90.20 
+(362 
+) 
+Oil 
+01/01/2013 - 12/31/2013 
+10,000 
+90.65 
+(308 
+) 
+Total open oil swap contracts 
+(670 
+) 
+F-37
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Gal/month) 
+Fixed 
+Price 
+($/Gal) 
+Fair Value 
+of 
+Asset 
+(Liability) 
+(thousands) 
+Purity Ethane 
+01/01/2013 - 12/31/2013 
+110,000 
+0.335 
+106 
+Purity Ethane 
+01/01/2013 - 12/31/2013 
+110,000 
+0.355 
+133 
+Propane 
+01/01/2013 - 12/31/2013 
+53,000 
+0.953 
+13 
+Propane 
+01/01/2013 - 12/31/2013 
+53,000 
+1.001 
+43 
+Normal Butane 
+01/01/2013 - 12/31/2013 
+14,700 
+1.455 
+(29 
+) 
+Normal Butane 
+01/01/2013 - 12/31/2013 
+14,700 
+1.560 
+(10 
+) 
+Isobutane 
+01/01/2013 - 12/31/2013 
+7,000 
+1.515 
+(18 
+) 
+Isobutane 
+01/01/2013 - 12/31/2013 
+7,000 
+1.625 
+(9 
+) 
+Natural Gasoline 
+01/01/2013 - 12/31/2013 
+12,000 
+2.025 
+(8 
+) 
+Natural Gasoline 
+01/01/2013 - 12/31/2013 
+12,000 
+2.085 
+1 
+Natural Gasoline 
+01/01/2013 - 12/31/2013 
+12,000 
+2.102 
+3 
+Total open NGL swap contracts 
+$ 
+225 
+Total open derivative financial instruments 
+$ 
+4,479 
+The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded
+in the consolidated balance sheets for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. 
+Type of Instrument 
+Location in Balance Sheet 
+December 31, 
+2012 
+December 31, 
+2011 
+Derivative Instrument 
+Oil 
+Current assets: Derivative instruments 
+$ 
+3,064 
+$ 
+– 
+Oil 
+Other assets: Derivative instruments 
+725 
+– 
+Oil 
+Current liabilities: Derivative instruments 
+(670 
+) 
+(171 
+) 
+Oil 
+Long-term liabilities: Derivative instruments 
+– 
+(383 
+) 
+Natural Gas 
+Current assets: Derivative instruments 
+1,089 
+8,989 
+Natural Gas 
+Other assets: Derivative instruments 
+46 
+847 
+Natural Gas 
+Long-term liabilities: Derivative instruments 
+– 
+– 
+NGL’s 
+Current assets: Derivative instruments 
+225 
+– 
+NGL’s 
+Long-term liabilities: Derivative instruments 
+– 
+– 
+Total 
+$ 
+4,479 
+$ 
+9,282 
+F-38
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following table summarizes the location and aggregate fair value of all derivative
+financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. 
+Type of Instrument 
+Location in 
+Statement of Operations 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+Derivative Instrument 
+Oil 
+Revenues: Realized gain on derivatives 
+$ 
+2,047 
+$ 
+– 
+$ 
+– 
+Natural Gas 
+Revenues: Realized gain on derivatives 
+11,892 
+7,106 
+5,299 
+NGL’s 
+Revenues: Realized gain on derivatives 
+21 
+– 
+– 
+Realized gain on derivatives 
+13,960 
+7,106 
+5,299 
+Oil 
+Revenues: Unrealized gain (loss) on derivatives 
+3,673 
+(554 
+) 
+– 
+Natural Gas 
+Revenues: Unrealized (loss) gain on derivatives 
+(8,700 
+) 
+5,692 
+3,139 
+NGL’s 
+Revenues: Unrealized gain on derivatives 
+225 
+– 
+– 
+Unrealized (loss) gain on derivatives 
+(4,802 
+) 
+5,138 
+3,139 
+Total 
+$ 
+9,158 
+$ 
+12,244 
+$ 
+8,438 
+NOTE 12 — FAIR VALUE MEASUREMENTS 
+The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair
+value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the
+following categories. 
+Level 1 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to
+be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. 
+Level 2 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category
+includes those derivative instruments that are valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or
+supported by observable levels at which transactions are executed in the marketplace. 
+Level 3 
+Unobservable inputs that are not corroborated by market data. This
+category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based on internally developed models or methodologies using significant inputs that are generally less readily observable from objective
+sources. 
+Financial and non-financial assets and liabilities are classified based on the lowest level of input that
+is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement
+within the fair value hierarchy levels. 
+F-39
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 12 — FAIR VALUE MEASUREMENTS — Continued 
+At December 31, 2012 and 2011, the carrying values reported on the consolidated balance
+sheets for cash, accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, income taxes payable, advances from joint interest owners and other current liabilities approximate their fair values due to their
+short-term maturities and are classified at Level 1. 
+At December 31, 2012 and 2011, the carrying value of borrowings under
+the Credit Agreement approximates fair value as it is subject to short-term floating interest rates that reflect market rates available to the Company at the time and is classified at Level 2. 
+The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value
+on a recurring basis in accordance with the classifications provided above as of December 31, 2012 and 2011 (in thousands). 
+Description 
+Fair Value Measurements
+at 
+December 31, 2012 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Certificates of deposit 
+$ 
+– 
+$ 
+230 
+$ 
+– 
+$ 
+230 
+Oil, natural gas and NGL derivatives 
+– 
+5,149 
+– 
+5,149 
+Oil, natural gas and NGL derivatives 
+– 
+(670 
+) 
+– 
+(670 
+) 
+Total 
+$ 
+– 
+$ 
+4,709 
+$ 
+– 
+$ 
+4,709 
+Description 
+Fair Value Measurements at 
+December 31,
+2011 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Certificates of deposit 
+$ 
+– 
+$ 
+1,335 
+$ 
+– 
+$ 
+1,335 
+Oil and natural gas derivatives 
+– 
+9,836 
+– 
+9,836 
+Oil and natural gas derivatives 
+– 
+(554 
+) 
+– 
+(554 
+) 
+Total 
+$ 
+– 
+$ 
+10,617 
+$ 
+– 
+$ 
+10,617 
+The Company’s accounting policies for certificates of deposit and derivative financial instruments are discussed
+in Note 2; additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that certificates of deposit and derivative financial instruments (e.g., oil,
+natural gas and NGL derivatives) should be classified at Level 2. 
+F-40
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 12 — FAIR VALUE MEASUREMENTS — Continued 
+The Company accounts for additions to asset retirement obligations and impairment of
+lease and well equipment inventory at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis as of
+December 31, 2012 and 2011 (in thousands). 
+Description 
+Fair Value Measurements
+at 
+December 31, 2012 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Asset retirement obligations 
+$ 
+– 
+$ 
+– 
+$ 
+(1,243 
+) 
+$ 
+(1,243 
+) 
+Lease and well equipment inventory 
+– 
+– 
+34 
+34 
+Total 
+$ 
+– 
+$ 
+– 
+$ 
+(1,209 
+) 
+$ 
+(1,209 
+) 
+Description 
+Fair Value Measurements at December 31, 
+2011 using 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Asset retirement obligations 
+$ 
+– 
+$ 
+– 
+$ 
+(187 
+) 
+$ 
+(187 
+) 
+Lease and well equipment inventory 
+– 
+– 
+1,343 
+1,343 
+Total 
+$ 
+– 
+$ 
+– 
+$ 
+1,156 
+$ 
+1,156 
+The Company’s accounting policies for asset retirement obligations are discussed in Note 2; reconciliations of the
+Company’s asset retirement obligations are provided in Note 4 for the periods presented. For purposes of fair value measurement, the Company determined that the additions to asset retirement obligations should be classified at Level 3. The
+Company recorded additions to asset retirement obligations of approximately $1.2 million and $0.2 million in 2012 and 2011, respectively. 
+The Company’s accounting policies for lease and well equipment inventory are discussed in Note 2. For purposes of fair value measurement, the Company determined that lease and well equipment
+inventory should be classified at Level 3. The Company recorded an impairment to some of its equipment held in inventory, consisting primarily of drilling rig parts, of $425,000 and $17,500 in 2012 and 2011, respectively. The Company recorded an
+impairment to some of its equipment held in inventory, consisting primarily of pipe and other equipment, of $60,464 and $22,276 in 2012 and 2011, respectively. The Company periodically obtains estimates of the market value of its equipment held in
+inventory from an independent third-party contractor or seller of similar equipment and uses these estimates as a basis for its measurement of the fair value of this equipment. 
+F-41
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES 
+Office Lease 
+The Company’s corporate headquarters are located in 28,743 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The office lease commencement date was
+September 25, 2003 with an expiration date of June 30, 2011. In April 2011, the Company entered into a restated third amendment to its office lease agreement in which the office space was increased to 28,743 square feet and the term of the
+lease was extended to June 30, 2022. The effective base rent over the term of the new lease extension is $19.75 per square foot per year. The base rate escalates several times during the course of the lease, specifically in July 2015, July
+2017, July 2019 and July 2020. This lease was amended subsequent to December 31, 2012 (see Note 18). 
+The following
+is a schedule of future minimum lease payments required under the office lease agreement as of December 31, 2012 (in thousands). 
+Year ending December 31, 
+Amount 
+2013 
+$ 
+575 
+2014 
+575 
+2015 
+589 
+2016 
+604 
+2017 
+618 
+Thereafter 
+2,995 
+Total 
+$ 
+5,956 
+Rent expense, including fees for operating expenses and consumption of electricity, was $0.6 million, $0.5 million and
+$0.4 million for 2012, 2011 and 2010, respectively. 
+Other Commitments 
+At December 31, 2012, the Company had entered into two drilling rig contracts to explore and develop its Eagle Ford acreage in South
+Texas. The two rigs began drilling on the Company’s acreage in March and December 2012, respectively. The first contract is for a term of 365 days and the second is for a term of 270 days. Should the Company elect to terminate one or both
+contracts and if the drilling contractor were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to the Company prior to the end of their
+respective contract terms, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under these contracts were approximately $5.1 million at December 31, 2012. The contract for
+the first rig was renegotiated in March 2013 (see Note 18). 
+Natural Gas and NGL Processing and Transportation
+Commitments 
+Effective September 1, 2012, the Company entered into a firm five-year natural gas processing and
+transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s
+F-42
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant
+downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its firm natural gas transportation agreements. The arrangement contains
+fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period. 
+Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a
+contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the
+natural gas deficiency. The Company believes that its current and anticipated production from the wells covered by this agreement is sufficient to meet 80% of the maximum thermal quantity transportation and processing commitments under this
+agreement. The Company paid approximately $0.3 million in processing and transportation fees under this agreement during the year ended December 31, 2012. 
+The aggregate undiscounted minimum commitments under this agreement at December 31, 2012 are as follows (in thousands). 
+Year ending December 31, 2012 
+Amount 
+2013 
+$ 
+5,985 
+2014 
+4,731 
+2015 
+2,992 
+2016 
+1,800 
+2017 
+1,195 
+Total 
+$ 
+16,703 
+Legal Proceedings 
+Cynthia Fry Peironnet, et al. v. Matador Resources Company. The Company is involved in a dispute over a mineral rights lease involving certain acreage in Louisiana. The dispute regards an extension
+of the term of a lease in Caddo Parish, Louisiana (the “Lease”) where the Company has drilled or participated in the drilling of both Cotton Valley and Haynesville shale wells. At issue are the deep rights below the Cotton Valley formation
+on approximately 1,805 gross acres where the Company has the right to participate for up to a 25% working interest, and also retains a small overriding royalty interest, in Haynesville shale wells drilled in units that include portions of the
+acreage. The Company’s total net revenue and overriding royalty interests in several non-operated Haynesville shale wells previously drilled on this acreage range from approximately 2% to 23%, and only portions of these interests are
+attributable to this acreage. The sum of the Company’s overriding royalty and net revenue interests attributable to this acreage from Haynesville wells previously drilled on this acreage comprises less than one net well. 
+F-43
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+The plaintiffs brought this claim against the Company on
+May 15, 2008 in the First Judicial District Court, Caddo Parish, Louisiana (the “Trial Court”). The plaintiffs sought (i) reformation or rescission of the lease extension, (ii) an accounting for additional royalty,
+(iii) monetary damages and (iv) attorney’s fees. During the pendency of the case in the Trial Court, the Company settled with one lessor who owned a 1/6 th undivided interest in the minerals. Since May 2008, the Trial Court has rendered multiple rulings in the favor of the
+Company, including a unanimous jury verdict in favor of the Company in the fall of 2010. Final judgment of the Trial Court was rendered in favor of Matador on June 6, 2011. On August 1, 2012, the Louisiana Second Circuit of Appeal (the
+“Court of Appeal”) affirmed in part and reversed in part the judgment of the Trial Court and remanded the case to the Trial Court for determination of damages. The Court of Appeal affirmed the Trial Court with respect to the 1/6 th royalty owner that settled and also affirmed that the Company’s
+lease extension was unambiguous. Nonetheless, the Court of Appeal reformed the lease extension to cover only approximately 169 gross acres, holding that the deep rights covering the remaining 1,636 gross acres had expired. The Court of Appeal denied
+the Company’s motion for rehearing, and the Company and certain other defendants filed an appeal with the Louisiana Supreme Court. The Louisiana Supreme Court has granted the requests to hear an appeal of the Court of Appeal’s decision.
+The Company believes that the facts of the case and the applicable law do not support the Court of Appeal’s judgment and
+it intends to vigorously pursue its rights to have the Trial Court’s judgment reinstated. Although the Company does not consider a loss resulting from this dispute to be probable, it is reasonably possible that the Company could incur a loss as
+a result of the continuing litigation of this matter. The Company currently estimates that a reasonable range of potential loss is zero to $6 million. 
+The Company is a defendant in several other lawsuits encountered in the ordinary course of its business. In the opinion of management, it is remote that these lawsuits will have a material adverse impact
+on the Company’s financial position, results of operations or cash flows. 
+General Federal and State Regulations
+Oil and natural gas exploration, development, production and related operations are subject to extensive federal,
+state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry
+increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable state and federal regulations. Because these rules and regulations are frequently amended or reinterpreted,
+however, the Company is unable to predict the future cost or impact of complying with these regulations. 
+Environmental
+Regulations 
+The exploration, development and production of oil and natural gas, including the operation of salt water
+injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. The
+Company’s activities are subject to a variety of environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or 
+F-44
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA, the Safe Drinking Water
+Act, or SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. The Company is also subject to regulations governing the handling, transportation, storage and disposal of waste generated by
+its activities and of naturally occurring radioactive materials, or NORM, that may result from its oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws
+and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species,
+and require investigation and cleanup of pollution. The Company has no outstanding material environmental remediation liabilities and believes that it is in compliance with currently applicable environmental laws and regulations and that these laws
+and regulations will not have a material adverse impact on the financial position, results of operations or cash flows of the Company. 
+Changes in environmental laws and regulations occur frequently, however, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements
+could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations and cash flows, as well as those of the oil and natural gas industry in general. Because these rules and regulations are
+frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as
+“greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such
+legislation has not been enacted. Any future federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require the Company to incur increased operating costs
+adversely affecting its financial position, results of operations and cash flows. 
+The Company’s activities involve the
+use of hydraulic fracturing. Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) at the federal
+level. At the federal level and in some states, there have been efforts to place additional regulatory burdens on hydraulic fracturing activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of
+the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to
+assess their adequacy to address hydraulic fracturing activities. Additional burdens on hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will result in additional expense and
+delay the Company’s operations adversely affecting its financial position, results of operations and cash flows. 
+Oil and
+natural gas exploration and production, operations and other activities have been conducted at some of the Company’s properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some
+instances, may require remediation. In addition, the Company occasionally 
+F-45
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+must agree to indemnify sellers of producing properties the Company acquires against some or all of the liability for environmental claims associated with these properties. While the Company does
+not believe that the costs it incurs for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, the Company cannot provide assurances that these costs will not result in
+material expenditures that adversely affect its financial position, results of operations and cash flows. 
+The Company
+maintains insurance against some, but not all, potential risks and losses associated with the oil and natural gas industry and operations. The Company does not carry business interruption insurance. For some risks, the Company may not obtain
+insurance if it believes the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully
+covered by insurance, it could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations and cash flows. 
+NOTE 14 — MAJOR CUSTOMERS 
+For the years ended December 31, 2012, 2011 and 2010, the Company had three significant purchasers that accounted
+for approximately 74%, 60% and 70%, respectively, of its total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one
+purchaser would have a material adverse impact on the Company’s financial position, results of operations or cash flows for any significant period of time. At December 31, 2012, 2011 and 2010, approximately 67%, 52% and 56%, respectively,
+of the Company’s accounts receivable, including joint interest billings, related to these purchasers. 
+NOTE 15 — SUPPLEMENTAL DISCLOSURES 
+Accrued Liabilities 
+The following table summarizes the Company’s current accrued liabilities at December 31, 2012 and 2011 (in thousands). 
+December 31, 
+2012 
+2011 
+Accrued evaluated and unproved and unevaluated property costs 
+$ 
+45,592 
+$ 
+18,185 
+Accrued support equipment and facilities costs 
+1,382 
+216 
+Accrued cost to issue equity 
+– 
+332 
+Accrued stock-based compensation 
+65 
+2,860 
+Accrued lease operating expenses 
+5,218 
+575 
+Accrued interest on borrowings under Credit Agreement 
+255 
+34 
+Accrued asset retirement obligations 
+660 
+334 
+Accrued partners’ share of joint interest charges 
+3,597 
+51 
+Other 
+2,410 
+2,852 
+Total accrued liabilities 
+$ 
+59,179 
+$ 
+25,439 
+F-46
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 15 — SUPPLEMENTAL DISCLOSURES — Continued 
+Supplemental Cash Flow Information 
+The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2012, 2011 and 2010
+(in thousands). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Cash paid (refunded) for income taxes 
+$ 
+– 
+$ 
+– 
+$ 
+(2,156 
+) 
+Cash paid for interest expense, net of amounts capitalized 
+780 
+634 
+– 
+Asset retirement obligations related to mineral properties 
+1,195 
+488 
+862 
+Asset retirement obligations related to support equipment and facilities 
+49 
+12 
+126 
+Increase in liabilities for oil and natural gas properties capital expenditures 
+24,847 
+1,864 
+15,531 
+Increase in liabilities for support equipment and facilities 
+1,112 
+175 
+40 
+Issuance of treasury stock for Board and advisor services 
+– 
+– 
+47 
+Issuance of restricted stock units for Board and advisor services 
+73 
+– 
+– 
+Issuance of common stock for Board and advisor services 
+71 
+230 
+198 
+(Decrease) increase in liabilities for accrued cost to issue equity 
+(332 
+) 
+(27 
+) 
+359 
+Stock based compensation expense recognized as liability 
+(1,092 
+) 
+2,102 
+164 
+Transfer of inventory to oil and natural gas properties 
+69 
+96 
+353 
+NOTE 16 — TRANSACTIONS WITH RELATED PARTIES 
+In January 2007, the Company entered into a joint venture with Marlan Downey and Julie Downey Garvin of Roxanna Oil
+Company (“Roxanna”) to assemble acreage for and to market a new natural gas shale prospect in Southwest Wyoming, Northeast Utah and Southeast Idaho. Mr. Downey is a special advisor to the Company’s Board of Directors and a
+shareholder in the Company. Ms. Garvin is President of Roxanna, which is also a shareholder in Matador. Mr. Downey and Ms. Garvin developed the prospect concept independently and sought the Company’s expertise in assembling a
+large acreage position across the prospect. The Company actively marketed this prospect in conjunction with Mr. Downey and Ms. Garvin. In May 2010, the Company, Roxanna and its subsidiary, Roxanna Rocky Mountains, LLC, entered into
+participation and joint operating agreements with an industry partner for the joint exploration and development of this opportunity. Under these agreements, Roxanna Rocky Mountains, LLC reserves a 2.5% overriding royalty interest in the leases and
+has the opportunity to earn up to a 10% working interest in all wells drilled. The industry partner has a 50% working interest in the project, and the Company retains a working interest equal to the difference between 50% and the working interest
+participation elected by Roxanna Rocky Mountains, LLC. The Company, as operator, drilled the initial test well for this prospect located in Lincoln County, Wyoming during 2011 and suspended operations. The Company re-entered this vertical well in
+late 2012 and drilled a horizontal lateral wellbore in the Meade Peak shale. This well was awaiting completion of the horizontal lateral at December 31, 2012. 
+F-47
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) 
+Costs Incurred 
+The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration, and development of oil and natural gas properties for the years ended December 31, 2012,
+2011 and 2010 (in thousands). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Property acquisition costs 
+Proved 
+$ 
+– 
+$ 
+– 
+$ 
+– 
+Unproved and unevaluated 
+28,672 
+41,497 
+100,730 
+Exploration costs 
+115,084 
+108,662 
+60,719 
+Development costs 
+190,891 
+12,511 
+14,348 
+Total costs incurred 
+$ 
+334,647 
+$ 
+162,670 
+$ 
+175,797 
+Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties,
+including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2012, 2011 and 2010, respectively, essentially all of the Company’s property acquisition costs resulted from the
+acquisition of unproved and unevaluated leasehold positions. 
+Exploration costs are costs incurred in identifying areas of
+these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and
+geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. 
+Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering
+and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and
+installing production facilities. 
+Costs incurred also include new asset retirement obligations established, as well as
+changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $1.2 million, $0.5 million and $1.0 million for the years ended
+December 31, 2012, 2011 and 2010, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $2.6
+million, $2.0 million and $1.6 million of these internal costs in 2012, 2011 and 2010, respectively. Capitalized interest expense for qualifying projects are also included in the table above. The Company capitalized $1.6 million and $1.3 million of
+its interest expense for the years ended December 31, 2012 and 2011, respectively. The Company recorded only $3,235 in interest expense for the year ended December 31, 2010. As a result, the Company capitalized no interest expense for the
+year ended December 31, 2010. 
+F-48
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+Oil and Natural Gas Operating Results 
+The following table provides the results of operations from oil and natural gas producing activities, excluding corporate overhead and
+interest costs, for the years ended December 31, 2012, 2011 and 2010 (in thousands, except per BOE amounts). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Oil and natural gas revenues 
+$ 
+155,998 
+$ 
+67,000 
+$ 
+34,042 
+Production taxes and marketing expenses 
+11,672 
+6,278 
+1,982 
+Lease operating expenses 
+28,184 
+7,244 
+5,284 
+Depletion, depreciation and amortization 
+79,592 
+31,619 
+15,423 
+Accretion of asset retirement obligations 
+256 
+209 
+155 
+Full-cost ceiling impairment 
+63,475 
+35,673 
+– 
+Net operating (loss) income 
+(27,181 
+) 
+(14,023 
+) 
+11,198 
+Income tax (benefit) provision 
+(9,595 
+) 
+(5,019 
+) 
+3,983 
+Results of oil and natural gas operations 
+$ 
+(17,586 
+) 
+$ 
+(9,004 
+) 
+$ 
+7,215 
+Depletion, depreciation and amortization per BOE 
+$ 
+24.16 
+$ 
+12.29 
+$ 
+10.76 
+Oil and Natural Gas Reserves 
+Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using
+existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical,
+petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil
+and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable
+oil and natural gas most likely will vary from the Company’s estimates. 
+Oil and natural gas reserves are estimated using
+then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted,
+arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period January through December 2012, these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu,
+respectively. For the period January through December 2011, these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. For the period January through December 2010, these average oil and natural gas prices
+were $75.96 per barrel and $4.376 per MMBtu, respectively. 
+The Company’s oil and natural gas reserves estimates are
+prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and 
+F-49
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers, for the years ended December 31, 2012, 2011 and 2010. 
+The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are
+summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved
+reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been
+estimated. The Company does not report its natural gas liquids production and reserves separately. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil, condensate or natural
+gas liquids to 6 Mcf of natural gas. 
+Net Proved Reserves 
+Oil 
+Gas 
+Oil 
+Equivalent 
+(MBbl) 
+(MMcf) 
+(MBOE) 
+Total at December 31, 2009 
+103 
+63,929 
+10,758 
+Revisions of prior estimates 
+66 
+874 
+211 
+Extensions and discoveries 
+16 
+71,009 
+11,851 
+Production 
+(33 
+) 
+(8,400 
+) 
+(1,433 
+) 
+Total at December 31, 2010 
+152 
+127,412 
+21,387 
+Revisions of prior estimates 
+51 
+(646 
+) 
+(57 
+) 
+Extensions and discoveries 
+3,745 
+58,164 
+13,439 
+Production 
+(154 
+) 
+(14,512 
+) 
+(2,573 
+) 
+Total at December 31, 2011 
+3,794 
+170,418 
+32,196 
+Revisions of prior estimates 
+(782 
+) 
+(103,375 
+) 
+(18,010 
+) 
+Extensions and discoveries 
+8,687 
+25,443 
+12,927 
+Production 
+(1,214 
+) 
+(12,479 
+) 
+(3,294 
+) 
+Total at December 31, 2012 
+10,485 
+80,007 
+23,819 
+Proved Developed Reserves 
+December 31, 2009 
+103 
+25,369 
+4,331 
+December 31, 2010 
+152 
+43,143 
+7,342 
+December 31, 2011 
+1,419 
+56,547 
+10,843 
+December 31, 2012 
+4,764 
+54,040 
+13,771 
+Proved Undeveloped Reserves 
+December 31, 2009 
+– 
+38,560 
+6,427 
+December 31, 2010 
+– 
+84,269 
+14,045 
+December 31, 2011 
+2,375 
+113,871 
+21,353 
+December 31, 2012 
+5,721 
+25,967 
+10,048 
+F-50
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+The following is a discussion of the changes in the Company’s proved oil and
+natural gas reserves estimates for the years ended December 31, 2012, 2011 and 2010. 
+The Company’s proved oil and
+natural gas reserves decreased to 23,819 MBOE at December 31, 2012 from 32,196 MBOE at December 31, 2011. The Company’s proved oil and natural gas reserves decreased by 5,083 MBOE and the Company produced 3,294 MBOE during the year
+ended December 31, 2012, resulting in a net decrease of 8,377 MBOE. An increase of 12,927 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling
+operations in the Eagle Ford shale play in South Texas. The Company’s oil and natural gas reserves decreased by 18,010 MBOE during the year as a result of revisions to previous estimates, primarily resulting from lower natural gas prices in
+2012. The Company’s proved developed oil and natural gas reserves increased to 13,771 MBOE at December 31, 2012 from 10,843 MBOE at December 31, 2011, primarily due to proved developed reserves added as a result of drilling operations
+in the Eagle Ford shale. At December 31, 2012, the Company’s proved reserves were made up of approximately 44% oil and 56% natural gas. 
+The Company’s proved oil and natural gas reserves increased to 32,196 MBOE at December 31, 2011 from 21,387 MBOE at December 31, 2010. The Company increased its proved oil and natural gas
+reserves by 13,382 MBOE and produced 2,573 MBOE during the year ended December 31, 2011, resulting in a net gain of 10,809 MBOE. A total of 13,439 MBOE of the increase in proved oil and natural gas reserves was a result of extensions and
+discoveries during the year, all of which was attributable to drilling operations in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. The Company’s oil and natural gas reserves decreased by 57 MBOE
+during the year as a result of revisions to previous estimates, representing the net impact of small changes in prior estimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to
+10,843 MBOE at December 31, 2011 from 7,342 MBOE at December 31, 2010, primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford and Haynesville shale plays. At December 31, 2011, the
+Company’s proved reserves were made up of approximately 12% oil and 88% natural gas. 
+The Company’s proved oil and
+natural gas reserves increased to 21,387 MBOE at December 31, 2010 from 10,758 MBOE at December 31, 2009. The Company increased its proved oil and natural gas reserves by 12,062 MBOE and produced 1,433 MBOE during the year ended December 31, 2010,
+resulting in a net gain of 10,629 MBOE. A total of 11,851 MBOE of the increase in proved oil and natural gas reserves was a result of extensions and discoveries during the year, almost all of which was attributable to drilling operations in the
+Haynesville shale play in Northwest Louisiana. A total of 211 MBOE of the increase in proved oil and natural gas reserves was attributable to revisions of previous estimates, representing the net impact of small changes in prior estimates of proved
+reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to 7,342 MBOE at December 31, 2010 from 4,331 MBOE at December 31, 2009, primarily due to proved developed reserves added as a result of
+drilling operations in the Haynesville shale play. At December 31, 2010, the Company’s proved reserves were made up of approximately 1% oil and 99% natural gas. 
+F-51
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
+Relating to Proved Oil and Natural Gas Reserves 
+The standardized measure of discounted future net cash flows relating
+to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among
+other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps
+different discount rates. 
+As noted previously, for the period January through December 2012, average oil and natural gas
+prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period January through December 2011, average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. For the period January through December
+2010, average oil and natural gas prices were $75.96 per barrel and $4.376 per MMBtu, respectively. 
+Future net cash flows
+were computed by applying these oil and natural gas prices, adjusted for all associated transportation costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting
+for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. 
+Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties.
+Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the
+standardized measure of discounted future net cash flows. 
+The following table presents the standardized measure of discounted
+future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2012, 2011 and 2010 (in thousands). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Future cash inflows 
+$ 
+1,273,882 
+$ 
+924,796 
+$ 
+470,386 
+Future production costs 
+(325,413 
+) 
+(194,538 
+) 
+(107,183 
+) 
+Future development costs 
+(244,283 
+) 
+(235,469 
+) 
+(107,277 
+) 
+Future income tax expense 
+(77,821 
+) 
+(83,840 
+) 
+(35,352 
+) 
+Future net cash flows 
+626,365 
+410,949 
+220,574 
+10% annual discount for estimated timing of cash flows 
+(231,729 
+) 
+(195,476 
+) 
+(109,497 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+394,636 
+$ 
+215,473 
+$ 
+111,077 
+F-52
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) — Continued
+The following table summarizes the changes in the standardized measure of discounted
+future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2012, 2011 and 2010 (in thousands). 
+Year ended December 31, 
+2012 
+2011 
+2010 
+Balance, beginning of period 
+$ 
+215,473 
+$ 
+111,077 
+$ 
+65,061 
+Net change in sales and transfer prices and in production (lifting) costs related to future production 
+(60,892 
+) 
+53,903 
+7,632 
+Changes in estimated future development costs 
+16,937 
+(64,958 
+) 
+(36,821 
+) 
+Sales and transfers of oil and natural gas produced during the period 
+(116,142 
+) 
+(53,478 
+) 
+(26,776 
+) 
+Net change due to extensions and discoveries 
+358,159 
+182,282 
+94,265 
+Net change due to revisions in estimates of reserves quantities 
+(56,850 
+) 
+(653 
+) 
+1,676 
+Previously estimated development costs incurred during the period 
+9,750 
+1,023 
+7,125 
+Accretion of discount 
+24,873 
+11,987 
+7,036 
+Other 
+(290 
+) 
+(1,335 
+) 
+1,035 
+Net change in income taxes 
+3,618 
+(24,375 
+) 
+(9,156 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+394,636 
+$ 
+215,473 
+$ 
+111,077 
+NOTE 18 — SUBSEQUENT EVENTS 
+On March 11, 2013, the borrowing base under the Company’s Credit Agreement was increased to $255.0 million
+based on the lenders’ review of its proved oil and natural gas reserves at December 31, 2012. At that time, the Credit Agreement was also amended to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank in
+the Company’s lending group, which also includes RBC as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. At March 14, 2013, the Company had $180.0 million in borrowings and $1.3 million in
+letters of credit outstanding under its Credit Agreement. The Company incurred $0.3 million of additional deferred loan costs in connection with the borrowing base redetermination and amendment of the Credit Agreement. These costs will be included
+with the remaining unamortized portion of the deferred loan costs of $1.6 million at December 31, 2012 to be amortized over the term of the agreement. 
+In March 2013, the Company granted awards of options to purchase 507,500 and 284,292 shares of the Company’s common stock at exercise prices of $8.21 per share and $8.18 per share, respectively, to
+certain of its employees. The fair value of these awards was approximately $2.8 million. The Company also granted awards of 324,771 shares of restricted stock to certain of its employees in March 2013. The fair value of these restricted stock awards
+was approximately $2.4 million. All of these awards vest over a term of three to four years. 
+In February 2013, options to
+purchase 408,000 shares of the Company’s common stock at $10.00 per share expired unexercised or were forfeited. 
+F-53
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 18 — SUBSEQUENT EVENTS — Continued 
+During the first quarter of 2013, the Company entered into several additional costless
+collar transactions to mitigate its risks associated with fluctuations in oil prices, including contracts with a new counterparty, The Bank of Nova Scotia (or affiliates thereof). The following table summarizes these contracts. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Bbls/month) 
+Price 
+Floor 
+($/Bbl) 
+Price 
+Ceiling 
+($/Bbl) 
+Oil 
+07/01/2013 - 12/31/2013 
+20,000 
+90.00 
+102.80 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+85.00 
+97.50 
+Oil 
+01/01/2014 - 12/31/2014 
+30,000 
+85.00 
+98.00 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+87.00 
+97.00 
+Oil 
+01/01/2014 - 12/31/2014 
+20,000 
+90.00 
+97.00 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+90.00 
+97.90 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+90.00 
+98.00 
+During the first quarter of 2013, the Company entered into several additional costless collar transactions to mitigate
+its risks associated with fluctuations in natural gas prices, including contracts with a new counterparty, The Bank of Nova Scotia (or affiliates thereof). The following table summarizes these contracts. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(MMBtu/month) 
+Price 
+Floor 
+($/MMBtu) 
+Price 
+Ceiling 
+($/MMBtu) 
+Natural Gas 
+04/01/2013 - 12/31/2013 
+100,000 
+3.25 
+4.41 
+Natural Gas 
+04/01/2013 - 12/31/2013 
+100,000 
+3.25 
+4.44 
+Natural Gas 
+04/01/2013 - 12/31/2013 
+100,000 
+3.50 
+4.37 
+Natural Gas 
+07/01/2013 - 12/31/2013 
+150,000 
+3.00 
+4.24 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.00 
+5.15 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.21 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.22 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.50 
+4.90 
+F-54
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 18 — SUBSEQUENT EVENTS — Continued 
+During the first quarter of 2013, the Company entered into several additional swap
+transactions to mitigate its risks associated with fluctuations in natural gas liquids prices. The following table summarizes these contracts. 
+Commodity 
+Calculation Period 
+Notional 
+Quantity 
+(Gal/month) 
+Fixed 
+Price 
+($/Gal) 
+Normal Butane 
+03/01/2013 - 12/31/2013 
+21,000 
+1.575 
+Normal Butane 
+03/01/2013 - 12/31/2013 
+117,000 
+1.575 
+Normal Butane 
+01/01/2014 - 12/31/2014 
+17,500 
+1.540 
+Normal Butane 
+01/01/2014 - 12/31/2014 
+45,500 
+1.550 
+Isobutane 
+03/01/2013 - 12/31/2013 
+43,500 
+1.675 
+Isobutane 
+03/01/2013 - 12/31/2013 
+23,000 
+1.675 
+Isobutane 
+01/01/2014 - 12/31/2014 
+22,000 
+1.640 
+Isobutane 
+01/01/2014 - 12/31/2014 
+37,000 
+1.640 
+Natural Gasoline 
+03/01/2013 - 12/31/2013 
+36,000 
+2.105 
+Natural Gasoline 
+03/01/2013 - 12/31/2013 
+90,500 
+2.148 
+Natural Gasoline 
+01/01/2014 - 12/31/2014 
+30,000 
+1.970 
+Natural Gasoline 
+01/01/2014 - 12/31/2014 
+41,000 
+2.000 
+During the first quarter of 2013, the Company extended one of its drilling rig contracts in South Texas for an
+additional six months. Should the Company elect to terminate the contract and if the drilling contractor were unable to secure work for the rig or if the drilling contractor were unable to secure work for the rig at the same daily rate being charged
+to the Company prior to the end of its term, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under this contract were approximately $2.1 million at March 14, 2013.
+In January and February 2013, the Company agreed to participate in the drilling and completion of various non-operated wells
+in the Eagle Ford shale and the Haynesville shale. If all of these wells are drilled and completed, the Company will have minimum outstanding aggregate commitments for its participation in these wells of approximately $5.6 million subsequent to
+December 31, 2012, which it expects to incur within the next few months. 
+F-55
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 18 — SUBSEQUENT EVENTS — Continued 
+In January 2013, the Company entered into the fourth amendment to its office lease
+agreement. This amendment increased the square footage of its corporate headquarters by 7,782 square feet, thereby increasing the size of its corporate headquarters from 28,743 square feet to 36,525 square feet effective January 1, 2013. The
+future minimum lease payments required under the office lease agreement as of January 1, 2013 are as follows (in thousands). 
+Year ending December 31, 
+Amount 
+2013 
+$ 
+643 
+2014 
+734 
+2015 
+752 
+2016 
+771 
+2017 
+789 
+Thereafter 
+3,813 
+Total 
+$ 
+7,502 
+NOTE 19 — SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) 
+The following table presents selected unaudited quarterly financial information for 2012 (in thousands, except per
+share data). 
+December 31 
+September 30 
+June 30 
+March 31 
+2012 
+Oil and natural gas revenues 
+$ 
+52,748 
+$ 
+38,008 
+$ 
+36,078 
+$ 
+29,164 
+Realized gain on derivatives 
+2,813 
+3,371 
+4,713 
+3,063 
+Unrealized (loss) gain on derivatives 
+(3,653 
+) 
+(12,993 
+) 
+15,114 
+(3,270 
+) 
+Expenses 
+72,377 
+38,087 
+66,263 
+21,857 
+Other expense 
+(907 
+) 
+(89 
+) 
+(31 
+) 
+(235 
+) 
+(Loss) income before income taxes 
+(21,376 
+) 
+(9,790 
+) 
+(10,389 
+) 
+6,865 
+Income tax (benefit) provision 
+(188 
+) 
+(593 
+) 
+(3,713 
+) 
+3,064 
+Net (loss) income 
+$ 
+(21,188 
+) 
+$ 
+(9,197 
+) 
+$ 
+(6,676 
+) 
+$ 
+3,801 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.38 
+) 
+$ 
+(0.17 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.08 
+Class B 
+$ 
+0.00 
+$ 
+0.00 
+$ 
+0.00 
+$ 
+0.15 
+Diluted 
+Class A 
+$ 
+(0.38 
+) 
+$ 
+(0.17 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.08 
+Class B 
+$ 
+0.00 
+$ 
+0.00 
+$ 
+0.00 
+$ 
+0.15 
+F-56
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010 
+NOTE 19 — SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) — Continued
+The following table presents selected unaudited quarterly financial information for 2011
+(in thousands, except per share data). 
+December 31 
+September 30 
+June 30 
+March 31 
+2011 
+Oil and natural gas revenues 
+$ 
+14,991 
+$ 
+17,447 
+$ 
+20,864 
+$ 
+13,698 
+Realized gain on derivatives 
+2,869 
+1,435 
+952 
+1,850 
+Unrealized gain (loss) on derivatives 
+3,604 
+2,870 
+332 
+(1,668 
+) 
+Expenses 
+15,784 
+15,469 
+14,953 
+48,347 
+Other expense 
+(309 
+) 
+(89 
+) 
+(89 
+) 
+(35 
+) 
+Income (loss) before income taxes 
+5,371 
+6,194 
+7,106 
+(34,502 
+) 
+Income tax provision (benefit) 
+1,430 
+– 
+(46 
+) 
+(6,906 
+) 
+Net income (loss) 
+$ 
+3,941 
+$ 
+6,194 
+$ 
+7,152 
+$ 
+(27,596 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+0.09 
+$ 
+0.14 
+$ 
+0.17 
+$ 
+(0.65 
+) 
+Class B 
+$ 
+0.16 
+$ 
+0.21 
+$ 
+0.23 
+$ 
+(0.58 
+) 
+Diluted 
+Class A 
+$ 
+0.09 
+$ 
+0.14 
+$ 
+0.17 
+$ 
+(0.65 
+) 
+Class B 
+$ 
+0.16 
+$ 
+0.21 
+$ 
+0.23 
+$ 
+(0.58 
+) 
+F-57
\ No newline at end of file
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/filing_metadata.csv b/raw/filings/0001520006/2012/0001193125-13-111031/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..dfa27ba24ff8aec419ea39a45504fe93af1b8558
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/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
+0001520006,MTDR,Matador Resources Co,10-K,2013-03-18,2012-12-31,2013-03-18T14:11:18.000Z,0001193125-13-111031,d444422d10k.htm,FORM 10-K,15585641,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000119312513111031/d444422d10k.htm,https://www.sec.gov/Archives/edgar/data/1520006/000119312513111031/,2012,2012,1
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/item1.txt b/raw/filings/0001520006/2012/0001193125-13-111031/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..7d6c47a01a21b0dd4d4e7a41a941c7a1b8469f14
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/item1.txt
@@ -0,0 +1,1594 @@
+Item 1. 
+Business. 
+In this
+Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador
+Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly-owned subsidiary of Matador Resources Company, now known as MRC Energy
+Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its
+corporate name to Matador Resources Company. 
+Unless the context otherwise requires, the term “common stock”
+refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only
+class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of
+our initial public offering. 
+For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the
+“Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. 
+General 
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources
+in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Our current operations are focused primarily on the oil and liquids rich portion of the Eagle Ford shale play in South Texas
+and in the Haynesville shale play in Northwest Louisiana. In 2012, more than 90% of our total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we sought to transition to a
+more balanced commodity portfolio through the drilling of wells that were prospective for oil and liquids. For the year ended December 31, 2012, approximately 37% of our total production by volume (using a conversion ratio of one Bbl of oil per
+6 Mcf of natural gas) and 79% of our total oil and natural gas revenues were attributable to oil production, primarily from the Eagle Ford shale. In 2013, we expect that approximately 82% of our estimated capital expenditures of $310.0 million will
+be directed to increasing our oil production and oil reserves in South Texas, primarily in the Eagle Ford shale play. Although we did not drill any operated Haynesville shale natural gas wells during 2012, we directed approximately 3% of our capital
+expenditures to the Haynesville shale in 2012 to participate in several non-operated wells. In addition to these primary operating areas, we have a growing acreage position in Southeast New Mexico and West Texas where we plan to drill three
+exploratory wells to test the Wolfcamp and Bone Spring plays during 2013. We also have a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where we are testing the Meade Peak shale. 
+We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO. Mr. Foran began his career as an
+oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by
+Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5
+million. 
+3 
+Table of Contents 
+On February 2, 2012, our common stock began trading on the NYSE under the symbol
+“MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share. We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167
+shares of common stock, including shares sold pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock.
+In 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South
+Texas, as we continued to execute our strategy to significantly increase our oil production and oil reserves during 2012. During the year ended December 31, 2012, we completed and began producing oil and natural gas from 28 gross/24.5 net Eagle
+Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We also completed and began producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin
+Chalk/upper Eagle Ford, or “Chalkleford,” intervals in 2012. In addition, during 2012, we completed and began producing natural gas from 28 gross/1.1 net non-operated Haynesville shale wells. We also re-entered and drilled a horizontal
+lateral from the previously suspended Crawford Federal #1 vertical well in Southwest Wyoming; we plan to complete this well in the third quarter of 2013. 
+We had two contracted drilling rigs operating in South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract), and
+almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. We did not drill any operated wells in the Haynesville shale play in Northwest Louisiana during 2012 as a result of the decline in natural gas prices
+compared to recent years. At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County. 
+Our average daily production for the year ended December 31, 2012 was approximately 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, as compared to 7,049
+BOE per day, including 422 Bbl of oil per day and 39.8 MMcf of natural gas per day for the year ended December 31, 2011. Our total oil production increased almost eight-fold to just over 1.2 million Bbl of oil during the year ended
+December 31, 2012 from approximately 154,000 Bbl of oil during the year ended December 31, 2011. This increased oil production is a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised approximately
+37% of our total production for the year ended December 31, 2012, as compared to only 6% of our total production for the year ended December 31, 2011. 
+During the three months ended December 31, 2012, specifically, our average daily production was 10,385 BOE per day, including 4,630 Bbl of oil per day and 34.5 MMcf of natural gas per day. This was
+an increase of almost 50% compared to our average daily production for the three months ended December 31, 2011 of 6,953 BOE per day, including 448 Bbl of oil per day and 39.0 MMcf of natural gas per day. Our total oil production increased
+ten-fold to 426,000 Bbl of oil during the three months ended December 31, 2012, as compared to total oil production of 41,000 Bbl of oil during the three months ended December 31, 2011. Our average daily production for the fourth quarter
+of 2012 was a sequential increase of 18% from the average daily production of 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day, achieved during the third quarter of 2012. For the three months ended
+December 31, 2012, our oil production grew 41% sequentially, as compared to the three months ended September 30, 2012. 
+At December 31, 2012, our estimated total proved reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas (13.3 million BOE). At December 31, 2012,
+58% of our total proved reserves were proved developed reserves compared to 34% at December 31, 2011. At December 31, 2012, 44% of our total proved reserves were oil and 56% of our total proved reserves were
+4 
+Table of Contents 
+natural gas, as compared to 12% oil and 88% natural gas at December 31, 2011. Our proved oil reserves grew 176% (almost three-fold) from 3.8 million Bbl at December 31, 2011 to
+10.5 million Bbl at December 31, 2012. This growth in oil reserves was attributable to our drilling program in the Eagle Ford shale during 2012. Our proved natural gas reserves declined to 80.0 Bcf at December 31, 2012 from 170.4 Bcf
+at December 31, 2011. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana
+from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these
+previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices
+improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+The PV-10
+of our estimated total proved reserves was $423.2 million at December 31, 2012 compared to a PV-10 of $248.7 million at December 31, 2011, an increase of 70% despite lower commodity prices used to estimate PV-10 in 2012 compared to 2011.
+The PV-10 at December 31, 2012 was determined using the 12-month unweighted average of first-day-of-the-month oil and natural gas prices for 2012 of $91.21 per barrel and $2.757 per MMBtu, respectively, adjusted by lease for quality, energy
+content, regional price differentials and other expenses as needed compared to average oil and natural gas prices of $92.71 per barrel and $4.118 per MMBtu, respectively, adjusted as further described above, used to determine PV-10 at
+December 31, 2011. The Standardized Measure of estimated future net cash flows from our total proved reserves, including estimated future income tax expenses, was $394.6 million at December 31, 2012 and $215.5 million at
+December 31, 2011. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at
+10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see
+“—Estimated Proved Reserves.” 
+For the year ended December 31, 2012, our oil and natural gas revenues were
+approximately $156.0 million, or an increase of about 133%, as compared to approximately $67.0 million for the year ended December 31, 2011. Our oil revenues increased over eight-fold to approximately $123.7 million for the year ended
+December 31, 2012, as compared to $14.5 million for the year ended December 31, 2011. Our total realized revenues for 2012, including realized gain on derivatives, were approximately $170.0 million, or an increase of about 129%, as
+compared to $74.1 million for 2011. For the year ended December 31, 2012, our Adjusted EBITDA was approximately $115.9 million, or an increase of about 132%, as compared to an Adjusted EBITDA of approximately $49.9 million for the year ended
+December 31, 2011. Adjusted EBITDA is a non-GAAP financial measure. For a reconciliation of Adjusted EBITDA to net income (loss) and net cash flow provided by operating activities, see “Selected Financial Data — Non-GAAP Financial
+Measures.” 
+5 
+Table of Contents 
+The following table presents certain summary data for each of our operating areas as of and
+for the year ended December 31, 2012: 
+Net Acreage 
+Producing 
+Wells 
+Total Identified 
+Drilling Locations (1) 
+Estimated Net Proved 
+Reserves (2) 
+Avg. Daily 
+Production 
+(BOE/d) (3) 
+Gross 
+Net 
+Gross 
+Net 
+MBOE (3) 
+% 
+Developed 
+South Texas: 
+Eagle Ford 
+27,911 
+37.0 
+31.7 
+274.0 
+221.0 
+14,331 
+45.5 
+3,908 
+Austin Chalk (4) 
+17,465 
+4.0 
+4.0 
+17.0 
+17.0 
+20 
+100.0 
+20 
+Area Total (5) 
+27,911 
+41.0 
+35.7 
+291.0 
+238.0 
+14,351 
+45.6 
+3,928 
+NW Louisiana/E Texas: 
+Haynesville 
+14,173 
+134.0 
+12.7 
+472.0 
+101.1 
+7,856 
+71.5 
+4,336 
+Cotton Valley (6) 
+22,469 
+106.0 
+69.7 
+71.0 
+49.3 
+1,512 
+100.0 
+706 
+Area Total (7) 
+24,968 
+240.0 
+82.4 
+543.0 
+150.4 
+9,368 
+76.1 
+5,042 
+SE New Mexico, West Texas (8) 
+7,591 
+13.0 
+5.7 
+39.0 
+25.1 
+100 
+100.0 
+30 
+SW Wyoming, NE Utah, SE Idaho 
+27,180 
+– 
+– 
+– 
+– 
+– 
+– 
+– 
+Total 
+87,650 
+294.0 
+123.8 
+873.0 
+413.5 
+23,819 
+57.8 
+9,000 
+(1) 
+These locations have been identified for potential future drilling and are not currently producing. In addition, the total net identified drilling locations is
+calculated by multiplying the gross identified drilling locations in an operating area by our working interest participation in such locations. At December 31, 2012, these identified drilling locations included 30 gross and 26.8 net locations
+to which we have assigned proved undeveloped reserves in the Eagle Ford and 2 gross and 1.9 net locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to identified drilling
+locations in the Austin Chalk or Cotton Valley or in the Wolfcamp or Bone Spring plays in Southeast New Mexico and West Texas at December 31, 2012. 
+(2) 
+These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers.
+(3) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(4) 
+Includes two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(5) 
+Some of the same leases cover the net acres shown for both the Eagle Ford formation and the Austin Chalk formation, a shallower formation than the Eagle Ford formation.
+Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for South Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations.
+(6) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(7) 
+Some of the same leases cover the net acres shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the Haynesville
+formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these
+formations. 
+(8) 
+Includes potential future drilling locations identified in either the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas at December
+31, 2012. 
+At December 31, 2012, our properties included approximately 42,500 gross acres and 27,900 net
+acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, LaSalle, Wilson and Zavala Counties in South Texas. We believe that approximately 88% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In
+addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 70% of
+our Eagle Ford acreage was held by production at December 31, 2012, and approximately 84% of our Eagle Ford acreage was either held by production at December 31, 2012 or not burdened by lease expirations before 2014. 
+At December 31, 2012, we had 37 gross and 31.7 net wells producing from the Eagle Ford shale in South Texas, and we have identified
+274 gross locations and 221.0 net locations for potential future drilling 
+6 
+Table of Contents 
+on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties,
+estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated
+horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Of the 274 gross and 221.0 net locations identified for potential
+future drilling in the Eagle Ford shale at December 31, 2012, we consider 155 gross and 125.1 net locations as Tier 1 locations. We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of
+225,000 Bbl of oil or greater. Of these Tier 1 locations, 115 gross locations and 109.1 net locations would be operated by us. These identified locations presume that we will be able to develop our Eagle Ford properties on 40-acre to 80-acre
+spacing, depending on the specific property and the wells we have already drilled. We anticipate that our acreage in central and northern LaSalle County and in northern Karnes County can be developed on 40-acre spacing in the Eagle Ford, while our
+other properties may be more likely developed on 80-acre spacing. We are currently drilling on 80-acre spacing on most of our properties. Although we had not yet drilled any wells on 40-acre spacing at December 31, 2012, we have several tests on
+less than 80-acre spacing planned on certain of our properties during 2013. We define Tier 2 Eagle Ford locations, including 119 gross and 95.9 net locations, as those locations that we anticipate to have estimated ultimate recoveries of between
+150,000 Bbl and 225,000 Bbl of oil, locations that are primarily prospective for natural gas or other locations on properties already held by existing production. At December 31, 2012, Tier 2 locations were identified primarily on our acreage in
+Zavala County and in southern LaSalle County; we have identified no potential future Eagle Ford drilling locations on our Atascosa County acreage. All of these Tier 2 locations would be operated by us, and approximately 85% of these locations are
+located on properties already held by production from the Eagle Ford or other producing horizons. Although we have no plans to drill any of these Tier 2 locations in 2013, as long as these properties remain held by production, these locations remain
+available for us to drill at a later time should commodity prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. Certain of these properties, such as our properties in Zavala and
+Atascosa Counties, also offer the opportunity to explore horizons other than the Eagle Ford, including the Austin Chalk, Buda, Edwards or Pearsall, and we may develop new prospects on these properties in the future. As we explore and develop all of
+our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for future drilling, particularly on those properties where we now presume development on 80-acre spacing. At December 31, 2012, these 274 gross and
+221.0 net potential future drilling locations included 30 gross and 26.8 net locations to which we have assigned proved undeveloped reserves. 
+In addition, at December 31, 2012, we had approximately 22,300 gross acres and 14,200 net acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and
+petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells
+drilled across the Haynesville shale play, approximately 5,700 of our net acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been
+drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production from the Haynesville or other formations, and we believe much of it is also
+prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play, although as of December 31, 2012, we had
+not tested the Middle Bossier shale on our acreage. 
+7 
+Table of Contents 
+At December 31, 2012, we had identified 472 gross locations and 101.1 net locations for
+potential future drilling on our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return,
+estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal
+lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 472 gross locations identified for future drilling, 397 of these locations
+(50.2 net locations) have been identified within the approximately 5,700 net acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may
+identify additional locations for future drilling. At December 31, 2012, these identified potential future drilling locations included only 2 gross and 1.9 net locations in the Haynesville shale play to which we have assigned proved undeveloped
+reserves. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total
+proved reserves at June 30, 2012, most of which were attributable to non-operated properties, including 100 gross and 14.8 net locations to which we had previously assigned proved undeveloped reserves. As long as the leasehold acreage
+associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes and the corresponding potential drilling locations remain available to be
+developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+At December 31, 2012, our properties also included approximately 15,900 gross and 7,600 net acres in the Delaware Basin in Southeast
+New Mexico and West Texas where we are developing new oil prospects. We believe that approximately 8,200 gross and 5,500 net acres are prospective for the Wolfcamp shale and Bone Spring formations, as well as other potential uphole targets including
+the Delaware sands and the Avalon shale. We believe that the Wolfcamp, Bone Spring, Avalon and Delaware formations are all prospective primarily for oil and that multiple target intervals may be prospective within each formation. At
+December 31, 2012, approximately 6,000 gross and 3,900 net of these acres were already held by production from other producing horizons. We expect to begin exploring this acreage position during the second and third quarters of 2013 and plan to
+drill a total of three test wells on this acreage in 2013. Two wells will test the Wolfcamp shale and one well will test the Second Bone Spring formation. At December 31, 2012, we had identified 39 gross and 25.1 net locations for potential future
+drilling in the Wolfcamp or Bone Spring plays on our acreage in Southeast New Mexico and West Texas, including the three exploratory test wells planned for 2013. These locations have been identified on a property-by-property basis and take into
+account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from nearby wells producing from the Wolfcamp and Bone Spring formations based on available public data, drilling
+densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria.
+Because we are just beginning the exploration of our properties in Southeast New Mexico and West Texas in 2013, our identified well locations at December 31, 2012 presume that only one horizon in the Wolfcamp or the Bone Spring may be developed at
+any one surface location and that these properties may be developed on 160-acre well spacing, although we believe that multiple intervals may be prospective at any one surface location and that denser well spacing may be possible. In addition,
+although our potential future drilling locations presume the drilling of horizontal wells, we also believe that certain portions of our acreage could lend itself to development with vertical wells. As a result, as we explore and develop our
+Southeast New Mexico and West Texas acreage further, we believe it is possible that we may identify additional locations 
+8 
+Table of Contents 
+for future drilling. At December 31, 2012, we had not assigned proved undeveloped reserves to any of these potential drilling locations in the Wolfcamp or Bone Spring formations. Although we
+believe that prospective well locations exist on this acreage for the Avalon shale and the Delaware sands, we had not included any Avalon or Delaware locations in our identified well locations at December 31, 2012. 
+At December 31, 2012, we also had a large unevaluated acreage position, including approximately 55,300 gross and 27,200 net acres in
+Southwest Wyoming and adjacent areas in Utah and Idaho, where we began drilling our initial well in February 2011 to test the Meade Peak natural gas shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak
+shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations in November 2011. After taking time to review
+and analyze the extensive well log and core data collected in this well, we re-entered the vertical well and drilled an approximately 2,500-ft horizontal lateral in the Meade Peak shale during the fourth quarter of 2012. Operations on this well are
+temporarily suspended, but we plan to complete and test the horizontal lateral portion of this well beginning in the third quarter of 2013. 
+We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation
+and others. At December 31, 2012, we were the operator for approximately 91% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large
+portion of our acreage in the core area of the Haynesville shale is operated by a subsidiary of Chesapeake Energy Corporation. We also operate the vast majority of our acreage in Southeast New Mexico and West Texas, as well as all of our acreage in
+Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interest is relatively small, particularly in the Haynesville shale. 
+At December 31, 2012, we were a non-operating working interest participant with affiliates of Chesapeake Energy Corporation, Royal
+Dutch Shell plc and several other companies in the Haynesville shale and with EOG Resources, Inc. and Hunt Oil Company in the Eagle Ford shale. We have entered into a joint operating agreement with an affiliate of Chesapeake Energy Corporation
+governing the Haynesville operations underlying our Elm Grove/Caspiana properties in Southern Caddo Parish, Louisiana and joint operating agreements with EOG Resources, Inc. and Hunt Oil Company governing operations on our joint acreage in Atascosa
+and Wilson Counties, Texas, respectively. We have not entered into a joint operating agreement with Royal Dutch Shell plc or certain other operators of wells in the Haynesville area in which we have a minority working interest. Particularly when our
+working interest is small, we do not always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our arrangement in accordance with industry standard practices.
+Where we do have joint operating agreements with affiliates of other companies, these agreements call for significant
+penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and
+equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation
+at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose. 
+While we do not have direct access to our operating partners’ drilling plans with respect to future well locations, we do attempt to
+maintain ongoing communications with the technical staff of these operators in 
+9 
+Table of Contents 
+an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these
+locations with Netherland, Sewell & Associates, Inc., independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. 
+We currently intend to allocate approximately 82% of our estimated 2013 capital expenditure budget of $310.0 million to the exploration,
+development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play. We also plan to allocate about 16% of our 2013 capital expenditure budget to the exploration and acquisition of additional interests in the
+Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. As a result of these anticipated capital expenditures in South Texas and in Southeast New Mexico and West Texas, we plan to dedicate about 98% of our 2013
+anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted approximately $310.0 million for 2013, the aggregate amount of capital we will expend may fluctuate materially based on market
+conditions, the actual costs to drill scheduled wells, our drilling results and our ability to obtain capital. Since approximately 84% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2014, 79% of
+our Wolfcamp and Bone Spring acreage was either held by production or not burdened by lease expirations before 2014 and almost all of our Haynesville acreage was held by production at December 31, 2012, we possess the financial flexibility to
+allocate our capital when and where we believe it is economical and justified. 
+Recent Developments 
+On March 11, 2013, the borrowing base under our Credit Agreement was increased to $255.0 million based on the lenders’ review of
+our proved oil and natural gas reserves at December 31, 2012. At that time, we also amended our Credit Agreement to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank in our lending group, which also
+includes Royal Bank of Canada (“RBC”), as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. At March 14, 2013, we had $180.0 million in borrowings and $1.3 million in letters of credit
+outstanding under our Credit Agreement. 
+Principal Areas of Interest 
+Our focus since inception has been the exploration for oil and natural gas in unconventional resource plays with a particular focus in
+recent years in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. During 2012, we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in
+South Texas as we sought to increase our oil production and reserves. Since our inception, our exploration efforts have concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential
+for multiple-zone completions. We have also sought to balance the risk profile of our prospects, as well as to explore for more conventional targets in addition to the unconventional resource plays. 
+At December 31, 2012, our principal areas of interest consisted of (1) the Eagle Ford shale play in South Texas, (2) the
+Haynesville shale play, including the Middle Bossier shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations in Northwest Louisiana and East Texas, (3) the Wolfcamp and Bone Spring plays in Southeast New Mexico
+and West Texas, particularly in the Delaware Basin, and (4) the Meade Peak shale play in Southwest Wyoming and the adjacent areas of Utah and Idaho. 
+10 
+Table of Contents 
+South Texas 
+Eagle Ford Shale and Other Formations 
+The Eagle Ford shale extends across
+portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower
+Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases
+consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more
+natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet natural gas with condensate. We believe that approximately 88% of our South Texas acreage at December 31, 2012
+lies within those portions of the Eagle Ford shale that are prone to produce oil or wet natural gas with condensate. 
+During
+2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas as we continued executing our strategy to significantly increase our oil production and oil reserves. In 2012, we
+completed and began producing oil and natural gas from 28 gross/24.5 net operated Eagle Ford shale wells, including 25 gross/23.7 net operated and 3 gross/0.8 net non-operated Eagle Ford shale wells. We had two contracted drilling rigs operating in
+South Texas throughout 2012 (except for a brief period near the end of the second quarter when we added a third rig to execute a two-well contract). At March 14, 2013, we continued to have two contracted drilling rigs operating in South Texas:
+one in LaSalle County and one in DeWitt County. More than 90% of our 2012 total capital expenditures of $334.6 million were directed to our operations in South Texas, primarily in the Eagle Ford shale. 
+For the year ended December 31, 2012, about 43% of our daily production, or 3,908 BOE per day, including 3,246 Bbl of oil per day
+and 4.0 MMcf of natural gas per day, was produced from the Eagle Ford shale in South Texas. Almost all of our oil production in 2012 was attributed to the Eagle Ford shale. The Eagle Ford contributed 98% of our daily oil production and about 12% of
+our daily natural gas production during 2012 as compared to 78% of our daily oil production and 3% of our daily natural gas production during 2011. During the year ended December 31, 2011, only about 8% of our daily production, or 548 BOE per
+day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past year reflects our ongoing drilling and
+completion program in the Eagle Ford shale. 
+At December 31, 2012, approximately 60% of our estimated total proved oil
+and natural gas reserves, or 14.3 million BOE, was attributable to the Eagle Ford shale, including approximately 10.4 million Bbl of oil and 23.8 Bcf of natural gas. Our proved reserves attributable to the Eagle Ford shale increased just
+over three-fold for the year to 14.3 million BOE for the year ended December 31, 2012, as compared to 4.7 million BOE for the year ended December 31, 2011. Our Eagle Ford proved reserves at December 31, 2012 comprised
+approximately 99% of our proved oil reserves and 30% of our proved natural gas reserves, as compared to approximately 96% of our proved oil reserves and 4% of our proved natural gas reserves at December 31, 2011. The PV-10 of our proved
+reserves in the Eagle Ford at December 31, 2012 was $393.2 million, or about 93% of the PV-10 of our total proved reserves of $423.2 million. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see
+“— Estimated Proved Reserves.” We anticipate that the percentage of our daily production and proved reserves attributable to the Eagle Ford shale will continue to grow in 2013 as we intend to allocate approximately 82% of our 2013
+11 
+Table of Contents 
+capital expenditure budget to the exploration, development and acquisition of additional interests in South Texas, primarily in the Eagle Ford shale play, in an effort to continue growing the oil
+and liquids component of our production and reserves. 
+At December 31, 2012, we had drilled and completed a total of 32
+gross/30.5 net Eagle Ford wells on our operated properties, and all of these wells were producing to sales. At December 31, 2012, we had also participated in 3 gross/0.6 net Eagle Ford wells with EOG Resources, Inc. as operator, on portions of
+our Atascosa County acreage and 2 gross/0.6 net Eagle Ford wells with Hunt Oil Company as operator, on portions of our Wilson County acreage. 
+During the year ended December 31, 2012, we completed and began producing oil and natural gas from 25 gross/23.7 net operated Eagle Ford wells drilled on our acreage position in South Texas. As we
+completed and began producing oil and natural gas from these wells during 2012, our Eagle Ford production increased significantly. During the fourth quarter of 2011, our daily production from the Eagle Ford shale averaged 584 BOE per day, including
+378 Bbl of oil per day and 1.2 MMcf of natural gas per day. By comparison, during the fourth quarter of 2012, our daily oil production from the Eagle Ford shale averaged 5,363 BOE per day, including 4,545 Bbl of oil per day and 4.9 MMcf of natural
+gas per day. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other
+heavier natural gas liquids components. Our Eagle Ford wells typically yield three to seven gallons of natural gas liquids per thousand cubic feet of natural gas produced at the wellhead depending on the specific property. 
+During the year ended December 31, 2012, we believe that we increased our technical knowledge on how to drill, complete and produce
+Eagle Ford shale wells. Eagle Ford wells drilled on the eastern portion of our acreage in Karnes and DeWitt Counties are typically 1,000 to 2,500 feet deeper than wells drilled on the western portion of our acreage in LaSalle County. At
+December 31, 2012, the typical drilling time for wells on the western portion of our acreage ranged from 10 to 15 days from spud to rig release and the typical drilling time for wells on the eastern portion of our acreage ranged from 15 to 20
+days from spud to rig release. These drilling times compared to 20 to 30 days from spud to rig release for wells drilled in the earlier months of 2012. As a result of more efficient drilling and reduced completion costs, the overall drilling and
+completion costs associated with our Eagle Ford wells declined during 2012. At December 31, 2012, we estimate that the cost for us to drill and complete a 5,000-ft Eagle Ford shale well was approximately $6 million to $7 million on the western
+portion of our acreage in LaSalle County and approximately $8 million to $10 million on the eastern portion of our acreage in Karnes and DeWitt Counties. We believe the reduction in drilling and completion costs we achieved during 2012 was due in
+part to improved efficiencies in our own operations, as well as to declining service costs associated with an increase in the supply of drilling and completion services in South Texas during 2012. We do not anticipate that service costs will decline
+to the same extent in 2013, although we will continue to look for ways to improve the costs associated with our operations. 
+At December 31, 2012, our aggregate leasehold interests consisted of approximately 42,500 gross acres and 27,900 net acres in the
+Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, LaSalle, Wilson and Zavala Counties in South Texas. We believe portions of this acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we
+would expect to produce 
+12 
+Table of Contents 
+predominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate typically ranging in thickness from 200 to 400 feet, and the Buda formation,
+which is a naturally fractured carbonate typically ranging in thickness from 90 to 160 feet, have produced from several fields on or nearby portions of our acreage. 
+During the year ended December 31, 2012, we acquired approximately 5,500 gross and 3,400 net acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This
+acreage essentially replaced the acreage upon which we drilled and established oil and natural gas production and reserves during 2012. We also allowed approximately 11,800 gross and 4,300 net acres of our Eagle Ford leasehold position, primarily in
+Atascosa County, but also including acreage in northeast Webb and southeast Dimmit Counties, to expire undrilled during the year ended December 31, 2012, as we no longer considered this acreage to be economic for further exploration and
+development in the Eagle Ford shale at then-current commodity prices. 
+At December 31, 2012, we owned a 100% working
+interest in approximately 26,900 gross acres and 24,100 net acres in Gonzales, Karnes, LaSalle, Wilson and Zavala Counties and a 50% working interest in approximately 2,800 gross and 1,400 net acres in DeWitt County and are the operator of this
+acreage. We also owned an approximate 21% working interest in approximately 12,800 gross acres in Atascosa County operated by EOG Resources, Inc. At December 31, 2012, approximately 84% of our Eagle Ford acreage was either held by production or
+not burdened by lease expirations before 2014. 
+Between March and July 2011, we acquired leasehold interests in approximately
+6,300 gross and 4,800 net acres in DeWitt, Gonzales, Karnes and Wilson Counties in the Eagle Ford shale play from Orca ICI Development, JV (“Orca”). We initially acquired a 50% working interest in the acreage (approximately 2,800 gross and
+1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Gonzales, Karnes and Wilson Counties and are the operator. At December 31, 2012,
+we had drilled and completed 15 gross/12.7 net wells on this acreage. 
+At December 31, 2012, we had paid 100% of the
+costs to drill and complete the first six wells drilled on the acreage in DeWitt County. We have an 85% working interest in these six wells until we have recovered all of our acquisition, drilling, completion, facilities and operating costs from
+each well, at which time Orca’s working interest will increase to 50%. After we have recovered all of our acquisition, drilling, completion, facilities and operating costs, when the cumulative production from any of these first six wells
+reaches 500,000 BOE, on a well-by-well basis, then Orca’s working interest in that well will increase to 55%. If the cumulative production from any of the first six wells reaches 750,000 BOE, on a well-by-well basis, then Orca’s working
+interest in that well will increase to 70%. Orca retains the right to pay its share of the costs and to participate for a 50% working interest in all subsequent wells drilled on the acreage in DeWitt County, and we have no further obligation to
+carry any of Orca’s costs in any subsequent well drilled on the acreage. Should Orca elect not to participate in a subsequent well that we propose to drill on the acreage, we will own a 100% working interest in the well until such time as we
+have recovered 400% of our acquisition, drilling, completion, facilities and operating costs from such well, at which time Orca’s working interest will increase to 50%. As of December 31, 2012, Orca had declined to participate in one
+subsequent well we drilled in DeWitt County, and we own an initial 100% working interest in this well. 
+At December 31,
+2012, we had paid 100% of the costs to drill and complete the first five wells drilled on the acreage in Gonzales, Karnes and Wilson Counties. We have a 100% working interest in these wells until we have recovered all of our acquisition, drilling,
+completion, facilities and operating costs from each of these five wells. After we have recovered all of our acquisition, drilling, completion, facilities and 
+13 
+Table of Contents 
+operating costs from any of these five wells, Orca may elect, on a well-by-well basis, to back-in for a 25% working interest in such wells. In addition, Orca retained a one-time election for a
+short period of time after we completed these first five wells to participate for a 25% working interest in all subsequent wells drilled on this acreage by paying a purchase price equal to 25% of our costs to acquire the acreage in Gonzales, Karnes
+and Wilson Counties. Following the completion of these first five wells, Orca declined to exercise its right to participate in all future wells drilled on this acreage. As a result, we will have a 100% working interest, and Orca will have no
+interest, in all subsequent wells drilled on this acreage. At December 31, 2012, we had drilled or participated in a total of 8 gross/6.6 net wells on this specific acreage. 
+As we continue to explore and develop our leasehold positions in the Eagle Ford shale in South Texas, we may face challenges with
+establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we
+produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our
+current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during the year ended December 31, 2012, although we experienced these
+problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to
+the successful development and profitability of the Eagle Ford shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing
+Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans Within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations
+and Cash Flows.” 
+We did experience temporary pipeline and natural gas processing interruptions from time to time during
+the year ended December 31, 2012 associated with natural gas production from our Eagle Ford shale wells. To alleviate most of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we
+entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the
+counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No
+assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these
+facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may experience similar interruptions and processing capacity constraints as we begin to explore and develop our
+Wolfcamp and Bone Spring plays in Southeast New Mexico and West Texas in 2013. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and
+Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+In addition to the Eagle Ford potential on our acreage, we believe that approximately 22,800 gross acres and 17,500 net acres in South
+Texas are prospective primarily for the Austin Chalk and 15,600 gross and 10,500 net acres are prospective primarily for the Buda formation, which have historically been targeted by operators in South Texas. During the year ended December 31,
+2012, we completed and began 
+14 
+Table of Contents 
+producing oil and natural gas from 2 gross/2.0 net wells in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or “Chalkleford,” intervals. Both of these wells were
+drilled on our acreage in Zavala County, which is in the heart of the historic Pearsall (Austin Chalk) Field where significant volumes of oil and natural gas have previously been produced from the Austin Chalk. Both of these wells are producing oil,
+but the results of these wells did not meet our expectations, with the upper Austin Chalk well apparently largely depleted by previous Austin Chalk production from nearby wells. We have not yet drilled an Austin Chalk well at any other location on
+our leasehold positions in South Texas, and although we believe that other prospective Austin Chalk well locations exist on this acreage, we have only included 17 gross and 17.0 net Austin Chalk well locations in our total identified drilling
+locations at December 31, 2012. We plan to drill an operated Austin Chalk exploratory test well on one of our leases in Gonzales County during 2013. At December 31, 2012, we had not included any Buda locations in our identified future drilling
+locations, although we do plan to participate in the drilling of an exploratory Buda test well on one of our leases in Atascosa County operated by EOG Resources, Inc. during the first quarter of 2013. 
+Northwest Louisiana and East Texas 
+As a result of substantially lower natural gas prices in 2012, we did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during
+the year ended December 31, 2012. We did, however, participate in the drilling and completion of 28 gross/1.1 net non-operated Haynesville shale wells in 2012, comprising about 3% of our total capital expenditures. We do not plan to drill any
+operated Haynesville wells in 2013, but we have budgeted capital expenditures of approximately $5.1 million for our participation in approximately 10 gross/0.5 net wells that we anticipate may be drilled by other operators on certain of our
+non-operated properties in 2013. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to
+be the core area of the Haynesville shale play. Of the approximately 5,700 net acres that we consider to be in the core area of the Haynesville play, we operate about 22% of that acreage. 
+For the year ended December 31, 2012, about 56% of our average daily production, or 5,042 BOE per day, including 31 Bbl of oil per
+day and 30.1 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. The vast majority of our natural gas production in 2012 was attributable to these properties. Natural gas production from
+these properties comprised approximately 88% of our daily natural gas production, but oil production from these properties only comprised about 1% of our daily oil production during 2012, as compared to 96% of our daily natural gas production and
+15% of our daily oil production during 2011. During the year ended December 31, 2011, approximately 92% of our daily production, or 6,459 BOE per day, including 64 Bbl of oil per day and 38.4 MMcf of natural gas per day, was attributable to our
+properties in Northwest Louisiana and East Texas. The decline in oil and particularly natural gas production from these properties over the past year reflects (i) the natural decline in production from these properties, (ii) the voluntary
+curtailment by the operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) our decision not to drill any operated Haynesville shale or Cotton Valley
+wells during 2012. 
+For the year ended December 31, 2012, about 76% of our daily natural gas production, or 26.0 MMcf of
+natural gas per day, was produced from the Haynesville shale, with another 12%, or 4.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations in this area. For the year ended December 31, 2011, about 81% of
+our daily natural gas production, or 32.3 MMcf of natural gas per day, was produced from the Haynesville shale, with another 15%, or 6.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties.
+15 
+Table of Contents 
+At December 31, 2012, approximately 33% of our estimated total proved reserves, or
+7.9 million BOE, were attributable to the Haynesville shale underlying this acreage with another 6% of our proved reserves, or 1.5 million BOE, associated with the Cotton Valley and shallower formations. As a result of substantially lower
+natural gas prices in 2012, we removed 97.8 Bcf (or 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, most of
+which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012. As long as the leasehold acreage associated with these
+previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time should natural gas prices
+improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+During
+2012, natural gas prices declined to their lowest levels in many years, ranging from a low of approximately $1.91 per MMBtu in mid-April to a high of approximately $3.90 per MMBtu in late November, based upon the NYMEX Henry Hub natural gas futures
+contract price for the earliest delivery date. Natural gas prices had declined again since late November 2012, before increasing to $3.81 per MMBtu at March 14, 2013, based upon the NYMEX Henry Hub natural gas futures contract for the earliest
+delivery date. We would not expect to drill any operated natural gas wells in either our Haynesville or Cotton Valley properties until natural gas prices improve further from these levels, the costs to drill and complete these wells decline further
+from their recent levels or new technologies are developed that increase expected recoveries. See “Risk Factors — Our Identified Drilling Locations Are Scheduled out over Several Years, Making Them Susceptible to Uncertainties That Could
+Materially Alter the Occurrence or Timing of Their Drilling.” 
+Haynesville and Middle Bossier Shales 
+The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above
+the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and
+Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be
+productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although
+there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. 
+At December 31, 2012, we had leasehold and mineral interests in approximately 22,300 gross and 14,200 net acres prospective for the
+Haynesville shale. This acreage includes approximately 5,700 net acres in what we believe is the core area of the play. Over 99% of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are
+also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play as well. We
+have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations exist on this acreage, we have not included any Middle Bossier locations in our identified drilling locations at December 31, 2012.
+16 
+Table of Contents 
+Within the 5,700 net acres that we believe to be in the core area of the Haynesville shale
+play, we are the operator of approximately 1,200 net acres in two sections where we have working interests of 95% and 100%, respectively, in all wells to be drilled. We have identified 12 gross and 11.7 net potential additional Haynesville locations
+that we may drill and operate in the future in these two sections. The remainder of our acreage in the core area of the Haynesville shale play, about 4,500 net acres, is operated by other companies, including approximately half of our non-operated
+Haynesville acreage in this area of the play that is operated by a subsidiary of Chesapeake following a sale of a portion of our interest in July 2008. Including the acreage operated by a subsidiary of Chesapeake, our non-operated Haynesville
+acreage is attributable to leasehold interests that we hold in 81 sections in Caddo, DeSoto, Bossier and Red River Parishes in Northwest Louisiana. Our working interests in the Haynesville wells in these sections range from less than 1% to more than
+30%. 
+Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations 
+Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest
+Louisiana and East Texas were attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East
+Texas. 
+All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in Northwest Louisiana,
+approximately 10,000 gross and net acres at December 31, 2012, is held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to
+discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. 
+In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H #1-Alt. on our Elm Grove/Caspiana properties,
+in DeSoto Parish and commenced sales of natural gas from this well. Based on the performance of this well and data available from public sources on other Cotton Valley horizontal wells drilled in this area of Northwest Louisiana, we believe that
+Cotton Valley horizontal wells drilled on our Elm Grove/Caspiana properties may have estimated ultimate natural gas recoveries of 4 to 6 Bcf. Prior to drilling this well, we had only drilled and completed vertical Cotton Valley and Hosston wells on
+these properties. We are the operator and have a 100% working interest in this well. We have identified 71 gross and 49.3 net additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove/Caspiana properties. We did not
+drill any of these locations in 2012 and do not plan to drill any of these locations in 2013. As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however,
+these Cotton Valley natural gas volumes remain available to be developed by us at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+We also continue to hold the shallow rights by existing production or by leases that are still in their primary terms in our Central and
+Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2012, we held an estimated 11,500 net leasehold and mineral acres by existing production in these areas. 
+Southeast New Mexico and West Texas — Delaware Basin 
+During 2012, we added to our acreage position in the Delaware Basin in Southeast New Mexico and West Texas, which is a mature exploration and production province with extensive developments in a wide
+variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of 
+17 
+Table of Contents 
+development in this basin has focused on relatively conventional reservoir targets, but we believe the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling
+and hydraulic fracturing technology is enhancing the development potential of this basin. 
+One example of such an opportunity
+appears to be the so-called “Wolf-Bone” play of the Delaware Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp formations span several thousand feet of stacked shales, sandstones, limestones and
+dolomites, representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural gas have been produced primarily from conventional sandstone and carbonate
+reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized by a number of operators as targets for horizontal
+drilling and multi-stage hydraulic fracturing techniques. As a result, several large industry players are expanding positions and conducting drilling programs throughout Eddy and Lea Counties in Southeast New Mexico and Loving, Pecos, Reeves and
+Ward Counties in West Texas. 
+For the year ended December 31, 2012, less than 1% of our average daily production, or only
+about 30 BOE per day, including 25 Bbl of oil per day and 30 Mcf of natural gas per day, was attributable to our leasehold properties in Southeast New Mexico and West Texas. At December 31, 2012, we held leasehold interests in approximately
+15,900 gross and 7,600 net acres in Southeast New Mexico and West Texas where we are developing new oil prospects. In particular, in August 2012, we acquired approximately 4,900 gross and 2,900 net acres prospective for the Wolfcamp and Bone Spring
+formations in Loving County, Texas, almost all of which is held by production from uphole formations to which we did not acquire the exploration and development rights. Subsequent to that time, we have added additional interests in this immediate
+area and at December 31, 2012, we held approximately 5,200 gross and 3,000 net acres in this leasehold position in Loving County. We have budgeted approximately $15.0 million of our anticipated 2013 capital expenditures to acquire additional
+leasehold interests prospective for oil and liquids production in Southeast New Mexico and West Texas. A portion of our leasehold interests in this area, including approximately 7,700 gross and 2,100 net acres in Winkler County, Texas, is no longer
+considered to be prospective by us, and we plan to let this acreage expire without drilling. 
+At December 31, 2012, we
+believe that approximately 8,200 gross and 5,500 net acres of our leasehold interests in the Delaware Basin are prospective for the Wolfcamp and Bone Spring formations, as well as other potential uphole targets, including the Avalon shale and
+Delaware sands, of which approximately 6,000 gross and 3,900 net acres are already held by existing production from other horizons by us or other operators. We believe that the Wolfcamp, Bone Spring, Avalon and Delaware formations are all
+prospective primarily for oil and that multiple intervals may be prospective within each target formation. We expect to begin exploring this acreage position during the second and third quarters of 2013, with plans to drill three exploratory test
+wells on this acreage in 2013. We have allocated approximately $35.6 million of our 2013 capital expenditure budget for these drilling and completion operations, including an estimated $5.4 million for pipelines, production facilities and related
+infrastructure. Two of these wells will test the Wolfcamp and one well will test the Second Bone Spring formation. 
+Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale 
+The Meade Peak shale is an organic-rich member of the Phosphoria formation, a source rock that is believed to have sourced much of the oil
+and natural gas in conventional reservoirs in the western Wyoming and eastern Utah area. The Phosphoria/Meade Peak shale has an observed shale thickness of 70 to 350 feet, total organic carbon values of 3% to 14% and vitrinite reflectance values
+ranging from 1.8% to 2.7%. The 
+18 
+Table of Contents 
+formation is encountered at depths of 3,000 to 14,000 feet, with the majority of our acreage in the depth range of 3,000 to 10,000 feet. The shale has been penetrated by over 100 wells in the
+area, most of which have natural gas shows. 
+We believe there have been no previous attempts to drill horizontally or to
+hydraulically fracture the Meade Peak shale in this area. Our focus to date has been to confirm the physical characteristics of the Meade Peak shale and evaluate its production potential. We have gathered well log data in the area, conducted a
+series of mapping evaluations of structural disposition and studied the petrophysical characteristics of the Meade Peak shale. In addition, we have purchased 2-D seismic data and conducted surface mapping studies using a structural geologist who has
+experience in the immediate area to better understand the area’s tectonic history. 
+At December 31, 2012, we held
+leasehold interests in approximately 55,300 gross and 27,200 net acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a
+combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are
+the operator of this prospect. We had no production, no proved reserves and no identified drilling locations attributable to this acreage at December 31, 2012. 
+At December 31, 2011, we held leasehold interests in approximately 144,000 gross and 136,000 net acres in this prospect, of which approximately 102,000 gross and 93,000 net acres were scheduled to
+expire at various times during 2012. Although we elected to take extensions or new leases on some portions of this expiring acreage during 2012, certain leases, particularly those taken on state lands, did not offer the opportunity for automatic
+extension and expired during 2012. Should we desire to reacquire mineral rights on these lands, we would need to seek new leases. 
+Along with our partners, we began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet,
+approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling, well logging
+and coring operations in November 2011. During 2012, we conducted detailed evaluations of the well logs and conducted special core analysis tests to better understand the petrophysical characteristics of the Meade Peak shale. 
+In September 2012, we entered into an agreement with our principal partner related to the ongoing exploration of the Meade Peak shale,
+pursuant to which our principal partner (i) paid us a prospect fee of $1.0 million, (ii) agreed to provide up to a total cost of $3.0 million (carrying our 50% share) for extensions of expiring leases and new leasing in the prospect in
+which we will have a 50% working interest at no cost to us and (iii) agreed to carry our 50% share of the drilling and completion costs associated with the horizontal lateral up to a total cost for these operations of $5.0 million, with each
+party paying 50% of all drilling and completion costs in excess of $5.0 million. In return for this consideration, in December 2012, we assigned 50% of our gross and net leasehold interests in the prospect to our principal partner. 
+In November 2012, we re-entered the Crawford Federal #1 vertical well and drilled a horizontal lateral from that wellbore into the Meade
+Peak shale approximately 2,500 feet in length. We temporarily suspended this well following drilling operations. We expect to return to this well in the third quarter of 2013 to conduct the completion operations on the horizontal lateral, which we
+expect will consist of three to 
+19 
+Table of Contents 
+four hydraulic fracture treatments along the length of the lateral. After the horizontal lateral is completed, we and our partners plan to test and evaluate this well before making further
+decisions concerning the future exploration of the Meade Peak shale in this prospect. 
+Operating Summary 
+The following table sets forth certain unaudited production data for the years ended December 31, 2012, 2011 and 2010: 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+Unaudited Production Data 
+Net Production Volumes: 
+Oil (MBbl) 
+1,214 
+154 
+33 
+Natural gas (Bcf) 
+12.5 
+14.5 
+8.4 
+Total oil equivalent (MBOE) (1) 
+3,294 
+2,573 
+1,433 
+Average daily production (BOE/d) (1) 
+9,000 
+7,049 
+3,926 
+Average Sales Prices: 
+Oil, with realized derivatives (per Bbl) 
+$ 
+103.55 
+$ 
+93.80 
+$ 
+76.39 
+Oil, without realized derivatives (per Bbl) 
+$ 
+101.86 
+$ 
+93.80 
+$ 
+76.39 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+3.55 
+$ 
+4.11 
+$ 
+4.38 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+2.59 
+$ 
+3.62 
+$ 
+3.75 
+Operating Expenses (per BOE): 
+Production taxes and marketing 
+$ 
+3.54 
+$ 
+2.44 
+$ 
+1.38 
+Lease operating 
+$ 
+8.56 
+$ 
+2.82 
+$ 
+3.69 
+Depletion, depreciation and amortization 
+$ 
+24.43 
+$ 
+12.34 
+$ 
+10.89 
+General and administrative 
+$ 
+4.42 
+$ 
+5.21 
+$ 
+6.77 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2012 from our primary operating areas: 
+Average Net Daily Production 
+Total
+Net 
+Production 
+(MBOE) (1) 
+Percentage of 
+Total
+Net 
+Production 
+Oil 
+(Bbl/d) 
+Gas 
+(Mcf/d) 
+Oil Equivalent 
+(BOE/d) (1) 
+South Texas: 
+Eagle Ford 
+3,246 
+3,976 
+3,908 
+1,431 
+43.4 
+% 
+Austin Chalk (2) 
+15 
+31 
+20 
+7 
+0.3 
+Area Total 
+3,261 
+4,007 
+3,928 
+1,438 
+43.7 
+NW Louisiana/E Texas: 
+Haynesville 
+1 
+26,007 
+4,336 
+1,587 
+48.2 
+Cotton Valley (3) 
+30 
+4,051 
+706 
+258 
+7.8 
+Area Total 
+31 
+30,058 
+5,042 
+1,845 
+56.0 
+SE New Mexico, West Texas 
+25 
+30 
+30 
+11 
+0.3 
+SW Wyoming, NE Utah, SE Idaho (4) 
+– 
+– 
+– 
+– 
+– 
+Total 
+3,317 
+34,095 
+9,000 
+3,294 
+100.0 
+% 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(4) 
+We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+20 
+Table of Contents 
+The following table sets forth information regarding our average net daily production and
+total production for the year ended December 31, 2011 from our primary operating areas: 
+Average Net Daily Production 
+Total
+Net 
+Production 
+(MBOE) (1) 
+Percentage of 
+Total
+Net 
+Production 
+Oil 
+(Bbl/d) 
+Gas 
+(Mcf/d) 
+Oil Equivalent 
+(BOE/d) (1) 
+South Texas: 
+Eagle Ford 
+331 
+1,298 
+548 
+200 
+7.8 
+% 
+Austin Chalk (2) 
+– 
+30 
+5 
+2 
+0.1 
+Area Total 
+331 
+1,328 
+553 
+202 
+7.9 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+32,319 
+5,387 
+1,966 
+76.4 
+Cotton Valley (3) 
+64 
+6,054 
+1,072 
+392 
+15.2 
+Area Total 
+64 
+38,373 
+6,459 
+2,358 
+91.6 
+SE New Mexico, West Texas 
+27 
+59 
+37 
+13 
+0.5 
+SW Wyoming, NE Utah, SE Idaho (4) 
+– 
+– 
+– 
+– 
+– 
+Total 
+422 
+39,760 
+7,049 
+2,573 
+100.0 
+% 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(4) 
+We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+Our total production of approximately 3.3 million BOE for the year ended December 31, 2012 was an increase of 28% over our
+total production of approximately 2.6 million BOE for the year ended December 31, 2011. This increased production was primarily due to drilling operations in the Eagle Ford shale. Our average daily production for the year ended
+December 31, 2012 was 9,000 BOE per day, as compared to 7,049 BOE per day for the year ended December 31, 2011. Our average daily oil production for the year ended December 31, 2012 was 3,317 Bbl of oil per day, an approximate
+eight-fold increase from 422 Bbl of oil per day for the year ended December 31, 2011. 
+21 
+Table of Contents 
+Producing Wells 
+The following table sets forth information relating to producing wells at December 31, 2012. Wells are classified as oil wells or natural gas wells according to their predominant production stream.
+We do not have any currently active dual completions. We have an approximate average working interest of 93% in all wells that we operate. For wells where we are not the operator, our working interests range from less than 1% to as much as 44%, and
+average approximately 8%. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. 
+Oil Wells 
+Natural Gas Wells 
+Total Wells 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+35.0 
+29.7 
+2.0 
+2.0 
+37.0 
+31.7 
+Austin Chalk (1) 
+2.0 
+2.0 
+2.0 
+2.0 
+4.0 
+4.0 
+Area Total 
+37.0 
+31.7 
+4.0 
+4.0 
+41.0 
+35.7 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+– 
+134.0 
+12.7 
+134.0 
+12.7 
+Cotton Valley (2) 
+2.0 
+2.0 
+104.0 
+67.7 
+106.0 
+69.7 
+Area Total 
+2.0 
+2.0 
+238.0 
+80.4 
+240.0 
+82.4 
+SE New Mexico, West Texas 
+12.0 
+5.1 
+1.0 
+0.6 
+13.0 
+5.7 
+SW Wyoming, NE Utah, SE Idaho (3) 
+– 
+– 
+– 
+– 
+– 
+– 
+Total 
+51.0 
+38.8 
+243.0 
+85.0 
+294.0 
+123.8 
+(1) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(3) 
+We currently have no production from our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+22 
+Table of Contents 
+Estimated Proved Reserves 
+The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2012, 2011 and 2010. The reserves estimates were based on evaluations prepared by our engineering
+staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves
+reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be
+attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids,
+which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 
+At December
+31, (1) 
+2012 
+2011 
+2010 
+Estimated Proved Reserves
+Data: (2) 
+Estimated proved reserves: 
+Oil (MBbl) 
+10,485 
+3,794 
+152 
+Natural Gas (Bcf) 
+80.0 
+170.4 
+127.4 
+Total (MBOE) (3) 
+23,819 
+32,196 
+21,387 
+Estimated proved developed reserves: 
+Oil (MBbl) 
+4,764 
+1,419 
+152 
+Natural Gas (Bcf) 
+54.0 
+56.5 
+43.1 
+Total (MBOE) (3) 
+13,771 
+10,843 
+7,342 
+Percent Developed 
+57.8 
+% 
+33.7 
+% 
+34.3 
+% 
+Estimated proved undeveloped reserves: 
+Oil (MBbl) 
+5,721 
+2,375 
+– 
+Natural Gas (Bcf) 
+26.0 
+113.9 
+84.3 
+Total (MBOE) (3) 
+10,048 
+21,353 
+14,045 
+PV-10 (4) (in millions) 
+$ 
+423.2 
+$ 
+248.7 
+$ 
+119.9 
+Standardized Measure (5) (in millions) 
+$ 
+394.6 
+$ 
+215.5 
+$ 
+111.1 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative
+transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2010 were $75.96 per Bbl for oil and $4.376 per MMBtu for
+natural gas, for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas, and for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas. These
+prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. 
+(3) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(4) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2010, 2011 and 2012 may be reconciled to our Standardized Measure
+of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2010, 2011 and 2012 were, in millions, $8.8, $33.2,
+and $28.6, respectively. 
+(5) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+23 
+Table of Contents 
+Our proved oil reserves grew 176% (almost three-fold) from approximately 3.8 million
+Bbl at December 31, 2011 to approximately 10.5 million Bbl at December 31, 2012. This increase is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas. Proved oil reserves at
+December 31, 2012 comprised 44% of our total proved reserves as compared to only 12% at December 31, 2011. 
+Our
+total proved oil and natural gas reserves decreased from 32.2 million BOE at December 31, 2011 to 23.8 million BOE at December 31, 2012, reflecting primarily the decrease in our proved natural gas reserves from 170.4 Bcf at
+December 31, 2011 to 80.0 Bcf at December 31, 2012. This decrease in our proved natural gas reserves was primarily attributable to the decrease in our proved undeveloped natural gas reserves from 113.9 Bcf at December 31, 2011 to 26.0
+Bcf at December 31, 2012. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest
+Louisiana from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at
+December 31, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available
+to be developed by us or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries. The PV-10 of our total proved oil and natural gas
+reserves increased by 70% from $248.7 million at December 31, 2011 to $423.2 million at December 31, 2012. Our total proved reserves at December 31, 2012 were made up of approximately 44% oil and 56% natural gas as compared to 12% oil
+and 88% natural gas at December 31, 2011. 
+Our proved developed oil and natural gas reserves increased from
+10.8 million BOE at December 31, 2011 to 13.8 million BOE at December 31, 2012 due primarily to additions resulting from our drilling operations in the Eagle Ford shale. Our proved developed oil reserves increased from
+1.4 million Bbl at December 31, 2011 to 4.8 million Bbl at December 31, 2012 as a result of our drilling operations in the Eagle Ford shale. Our proved developed natural gas reserves declined from 56.5 Bcf (9.4 million BOE) at
+December 31, 2011 to 54.0 Bcf (9.0 million BOE) at December 31, 2012. The net increase of 3.0 million BOE in our proved developed reserves from December 31, 2011 to December 31, 2012 was composed of (1) additions of
+7.4 million BOE, including 4.7 million Bbl of oil and 16.2 Bcf of natural gas (2.7 million BOE), plus conversions of 0.4 million BOE, including 0.3 million Bbl of oil and 0.8 Bcf of natural gas (0.1 million BOE) from proved
+undeveloped to proved developed reserves, less (2) net oil and natural gas production of 3.3 million BOE, including 1.2 million Bbl of oil and 12.5 Bcf of natural gas (2.1 million BOE), less (3) downward revisions of proved
+developed reserves by 1.5 million BOE, including 0.5 million Bbl of oil and 6.2 Bcf of natural gas (1.0 million BOE). The downward revisions in proved developed natural gas reserves were primarily attributable to the lower natural gas
+prices used to estimate proved reserves at December 31, 2012 as compared to December 31, 2011. During the year ended December 31, 2012, we recorded no changes to proved developed reserves as a result of the acquisition or divestment
+of reserves. 
+Our proved undeveloped oil and natural gas reserves decreased from 21.4 million BOE at December 31,
+2011 to 10.1 million BOE at December 31, 2012. Our proved undeveloped oil reserves increased from 2.4 million Bbl at December 31, 2011 to 5.7 million Bbl at December 31, 2012 as a result of our drilling operations in
+the Eagle Ford shale. Our proved undeveloped natural gas reserves decreased from 113.9 Bcf (19.0 million BOE) at December 31, 2011 to 26.0 Bcf (4.3 million BOE) at December 31, 2012 due primarily to the removal of 97.8 Bcf (16.3 million
+BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana as a result of lower natural gas prices in 2012. The net decrease of 11.3 million BOE in our proved undeveloped reserves from
+December 31, 
+24 
+Table of Contents 
+2011 to December 31, 2012 is composed of (1) additions to proved undeveloped reserves of 5.5 million BOE, including 4.0 million Bbl of oil and 9.3 Bcf of natural gas (1.5
+million BOE) identified through drilling operations, less (2) the conversion of 0.4 million BOE of proved undeveloped reserves to proved developed reserves, including 0.3 million Bbl of oil and 0.8 Bcf of natural gas (0.1 million
+BOE), less (3) the net downward revisions of proved undeveloped reserves by 16.4 million BOE in the period, including 0.3 million Bbl of oil and 96.4 Bcf (16.1 million BOE). During the year ended December 31, 2012, we recorded no
+changes to proved undeveloped reserves as a result of the acquisition or divestment of reserves. At December 31, 2012, we had no proved reserves in our estimates that remained undeveloped for five years or more following their initial booking.
+The following table sets forth additional summary information by operating area with respect to our estimated net proved
+reserves at December 31, 2012: 
+Net Proved
+Reserves (1) 
+Oil 
+Gas 
+Oil 
+Equivalent 
+PV-10 (2) 
+Standardized 
+Measure (3) 
+(MBbl) 
+(Bcf) 
+(MBOE) (4) 
+(in millions) 
+(in millions) 
+South Texas: 
+Eagle Ford 
+10,358 
+23.8 
+14,331 
+393.2 
+366.6 
+Austin Chalk (5) 
+7 
+0.1 
+20 
+0.4 
+0.4 
+Area Total 
+10,365 
+23.9 
+14,351 
+393.6 
+367.0 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+47.1 
+7,856 
+21.8 
+20.3 
+Cotton Valley (6) 
+34 
+8.9 
+1,512 
+5.8 
+5.4 
+Area Total 
+34 
+56.0 
+9,368 
+27.6 
+25.7 
+SE New Mexico, West Texas 
+86 
+0.1 
+100 
+2.0 
+1.9 
+SW Wyoming, NE Utah, SE Idaho (7) 
+– 
+– 
+– 
+– 
+– 
+Total 
+10,485 
+80.0 
+23,819 
+423.2 
+394.6 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include
+the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies
+and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2012 may be reconciled to our Standardized Measure of discounted
+future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2012 were approximately $28.6 million. 
+(3) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and
+abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+(4) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(5) 
+Includes two wells producing small volumes of natural gas from the San Miguel formation in Zavala County, Texas. 
+(6) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(7) 
+At December 31, 2012, we had no proved reserves attributable to our acreage in Southwest Wyoming and adjacent areas of Utah and Idaho. 
+Technology Used to Establish Reserves 
+Under current SEC rules, proved reserves are those quantities of oil and natural gas, 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 economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of
+oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty 
+25 
+Table of Contents 
+can be established using techniques that have been proven 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 have been field tested and have been demonstrated to provide reasonably certain results with
+consistency and repeatability in the formation being evaluated or in an analogous formation. 
+In order to establish reasonable
+certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include,
+but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production
+performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both
+developed and undeveloped properties were forecast using either volumetric and/or analogy methods. 
+Internal Control Over
+Reserves Estimation Process 
+We maintain an internal staff of petroleum engineers and geoscience professionals to ensure
+the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Reserves Manager is primarily responsible for overseeing the preparation of our reserves estimates and has over 16 years of industry experience. Our
+Reserves Manager received his Ph.D. degree in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and received a certificate of completion in a prescribed course of study in Reserves and
+Evaluation from Texas A&M University in May 2009. Our Vice President – Reservoir Engineering is responsible for reviewing and approving our reserves estimates and has over 35 years of industry experience. Following the preparation of our
+reserves estimates, we had our reserves estimates audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. The Engineering Committee of our board of directors reviews the reserves report
+and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by members of our board of directors, including members of our Audit Committee. 
+Acreage Summary 
+The
+following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2012. At that date, about 44% of our total net acreage had been developed, although these percentages are somewhat higher
+in South Texas and much higher in Northwest Louisiana and East Texas. 
+Developed Acres 
+Undeveloped Acres 
+Total Acres 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+18,236 
+15,736 
+24,220 
+12,175 
+42,456 
+27,911 
+Austin Chalk 
+8,892 
+8,892 
+13,893 
+8,573 
+22,785 
+17,465 
+Area Total (1) 
+18,236 
+15,736 
+24,220 
+12,175 
+42,456 
+27,911 
+NW Louisiana/E Texas: 
+Haynesville 
+19,286 
+11,178 
+2,995 
+2,995 
+22,281 
+14,173 
+Cotton Valley (2) 
+22,085 
+19,435 
+3,370 
+3,034 
+25,455 
+22,469 
+Area Total (3) 
+24,749 
+21,859 
+3,444 
+3,109 
+28,193 
+24,968 
+SE New Mexico, West Texas 
+1,160 
+991 
+14,700 
+6,600 
+15,860 
+7,591 
+SW Wyoming, NE Utah, SE Idaho 
+– 
+– 
+55,273 
+27,180 
+55,273 
+27,180 
+Total 
+44,145 
+38,586 
+97,637 
+49,064 
+141,782 
+87,650 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford
+shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for South Texas. 
+26 
+Table of Contents 
+(2) 
+Includes shallower zones and also includes acreage surrounding one well producing from the Frio formation in Orange County, Texas. 
+(3) 
+Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the Cotton Valley formation, a shallower formation than the
+Haynesville shale. Therefore, the sum of the net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Undeveloped Acreage Expiration 
+The following table sets forth the
+approximate number of gross and net undeveloped acres at December 31, 2012 that will expire prior to December 31, 2014 by operating area unless production is established within the spacing units covering the acreage prior to the expiration
+dates or unless the existing leases are renewed prior to expiration or unless continued operations maintain the leases beyond the expiration of each respective primary term. 
+Acres 
+Expiring 2013 
+Acres 
+Expiring 2014 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+8,832 
+4,455 
+3,903 
+613 
+Austin Chalk 
+5,260 
+3,689 
+589 
+89 
+Area Total (1) 
+8,832 
+4,455 
+3,903 
+613 
+NW Louisiana/E Texas: 
+Haynesville 
+– 
+– 
+33 
+33 
+Cotton Valley 
+– 
+– 
+– 
+– 
+Area Total (2) 
+– 
+– 
+33 
+33 
+SE New Mexico, West Texas 
+8,717 
+2,658 
+7,514 
+497 
+SW Wyoming, NE Utah, SE Idaho 
+5,882 
+2,861 
+– 
+– 
+Total 
+23,431 
+9,974 
+11,450 
+1,143 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Eagle Ford shale and the Austin Chalk formation, a shallower formation than the Eagle Ford
+shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for South Texas. 
+(2) 
+Some of the same leases cover the gross and net acreage shown for the Haynesville shale and the Cotton Valley formation, a shallower formation than the Haynesville
+shale. Therefore, the sum of the total gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless
+operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or unless production from the acreage has been established prior to such date, in which event the lease will remain in
+effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In
+addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not
+been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. Our leases are mainly fee leases with three to five years of primary term. We believe that our lease terms are similar to
+our competitors’ fee lease terms as they relate to both primary term and royalty interests. 
+27 
+Table of Contents 
+Drilling Results 
+The following table summarizes our drilling activity for the years ended December 31, 2012, 2011 and 2010: 
+Year Ended December 31, 
+2012 
+2011 
+2010 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development Wells 
+Productive 
+36 
+17.1 
+30 
+0.6 
+5 
+1.7 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Exploration Wells 
+Productive 
+22 
+10.4 
+30 
+10.2 
+36 
+3.4 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Total Wells 
+Productive 
+58 
+27.6 
+60 
+10.8 
+41 
+5.1 
+Dry 
+– 
+– 
+– 
+– 
+– 
+– 
+Marketing 
+Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a
+consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down
+independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. 
+Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at
+various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When
+there is an opportunity to do so, the mid-stream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a
+negotiated percentage of the proceeds that are generated from the mid-stream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation
+fees. 
+The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations
+include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative
+fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices do adversely affect the
+carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled
+maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has
+historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the
+Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+28 
+Table of Contents 
+For the years ended December 31, 2012, 2011 and 2010, we had three significant
+purchasers that accounted for approximately 74%, 60% and 70%, respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the
+loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. 
+Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a
+significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the
+counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its firm natural gas transportation
+agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. 
+Under this agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year,
+we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas
+deficiency. We believe that our current and anticipated production from the wells covered by this agreement is sufficient to meet 80% of the maximum thermal quantity transportation and processing commitments under this agreement. 
+We were also party to one natural gas transportation agreement at December 31, 2012 that requires us to deliver a specified volume
+of natural gas through a pipeline for a fixed period of time. If we fail to meet the volume requirement, we are required to pay an amount to the owners of the pipeline to offset a portion of the expenses they incurred in building the pipeline to our
+well location. This contract does not constitute a material commitment. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by
+Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Title to Properties 
+We endeavor to assure that title to our properties is
+in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often
+will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of
+these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or
+affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, where required, or making lease rental payments or by producing oil and natural gas from wells in paying quantities prior to expiration of
+various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a
+Result of Title Deficiencies in the Properties in Which We Invest.” 
+29 
+Table of Contents 
+Competition 
+The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property
+acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other
+resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able
+to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be
+able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. 
+Our ability to drill and
+explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting
+field operations since 2004 while our competitors have a longer history of operations, and most of them have also demonstrated the ability to operate through industry cycles. 
+The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors
+— Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” 
+Regulation 
+Oil and Natural Gas Regulation 
+Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local
+laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of
+doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with
+the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict
+the impact of future government regulation on our properties or operations. 
+Texas, New Mexico, Louisiana, Wyoming, Idaho and
+Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have
+statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the
+regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states
+restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed
+price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. 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. 
+30 
+Table of Contents 
+Some of our oil and natural gas leases are issued by agencies of the federal government, as
+well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. 
+Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of
+transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as
+under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural
+gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
+In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act,
+among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly
+increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related
+regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. 
+Intrastate natural
+gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and
+services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our
+operations in any way that is materially different from our competitors that are similarly situated. 
+The price we receive
+from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though
+other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the
+effects, if any, of these regulations on our operations. 
+In 2007, the Energy Independence & Security Act of 2007, or
+the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations
+that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. 
+U.S. Federal and State Taxation 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions
+of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated 
+31 
+Table of Contents 
+with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning
+a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to
+eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We
+Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a
+Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” 
+Hydraulic Fracturing Policies and Procedures 
+We use hydraulic fracturing
+as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals.
+Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 50% of the drilling and completion costs for our horizontal wells are associated with hydraulic
+fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state
+laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic
+Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” 
+The protection of
+groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and
+federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). 
+Although
+rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue, running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed
+by pumping remedial cement jobs and other appropriate remedial measures. 
+The vast majority of hydraulic fracturing treatments
+are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate
+governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more
+environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture
+stimulation procedures. 
+While current fracture stimulation procedures utilize a significant amount of water, we typically
+recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal
+facilities in a way that is designed to avoid any impact to surface waters. 
+32 
+Table of Contents 
+Environmental Regulation 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells,
+are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety
+of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource
+Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to
+regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and
+criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some
+activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental
+laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. 
+The OPA 90 and
+its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the
+exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for
+removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure
+to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable
+requirements under the OPA 90 will not have a material adverse effect on us. 
+The CWA and comparable state laws impose
+restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be
+imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal
+National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and
+offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has 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. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other
+pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require
+certain oil-storing facilities to prepare plans and meet construction and operating standards. 
+33 
+Table of Contents 
+CERCLA, also known as the “Superfund” law, imposes liability, without regard to
+fault or the legality of the original conduct, on various 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 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 responsible for releases of hazardous substances under CERCLA may be subject to
+joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. 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 hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or
+handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for
+petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. 
+RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and
+nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration
+and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made
+to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state
+statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal
+requirements than are nonhazardous wastes. 
+The CAA, as amended, and comparable state laws restrict the emission of air
+pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain
+projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New
+Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for
+completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (VOC) emissions from natural gas not sent to the gathering line during well
+completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it
+available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish
+specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the
+installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business. 
+34 
+Table of Contents 
+Changes in environmental laws and regulations occur frequently, and any changes that result
+in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general.
+For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s
+atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas
+emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and
+natural gas. 
+The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources
+under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on
+October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule
+that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas
+distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting
+obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our
+profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional
+greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of
+emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our
+business, financial condition, results of operations and cash flows. 
+Underground injection is the subsurface placement of
+fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil
+bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent
+migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate
+five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. 
+Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “—
+Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing 
+35 
+Table of Contents 
+regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level
+pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass
+hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and
+recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption
+for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our
+financial condition, results of operations and cash flows. 
+In addition, in some states and localities, there has been a push
+to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of
+the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to
+assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. 
+The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground
+Injection Control Program. The EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released in December 2012, with final results expected in 2014. In addition, in December
+2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review, but such studies could result in additional regulatory
+scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. The BLM has indicated that it is considering proposed rules to regulate hydraulic fracturing on federal lands. Further,
+the EPA has announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on
+some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims
+associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that
+these costs will not result in material expenditures that adversely affect our profitability. 
+Additionally, in the course of
+our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural
+gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude
+oil and natural gas production and processing streams. Some states, including Texas, 
+36 
+Table of Contents 
+have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the
+operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 
+We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community
+right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain
+of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. 
+The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is
+listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife
+Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may
+materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted. 
+We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to
+our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws
+and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government
+Regulation and Liability, including Complex Environmental Laws, Which Could Require Significant Expenditures.” 
+The clear
+trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2011 to 2013 is to focus on compliance by the energy
+extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material
+adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that
+we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. 
+We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not
+currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not
+fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 
+Office Lease 
+Our
+corporate headquarters are located in approximately 36,500 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The initial lease, as amended, expires on
+37 
+Table of Contents 
+June 30, 2022 and at December 31, 2012 covered approximately 29,000 square feet. On January 16, 2013, we entered into a fourth amendment to our office lease agreement to include
+approximately 7,800 square feet of additional space, increasing the size of our corporate headquarters from approximately 28,700 square feet to approximately 36,500 square feet. 
+Employees 
+At December 31, 2012, we had 50 full-time employees. We
+believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional
+services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services.
+Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant
+opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. 
+Available Information 
+Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report
+on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance
+Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a
+written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other
+report or document we file and any reference to our website is intended to be an inactive textual reference only. 
+38 
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/item13.txt b/raw/filings/0001520006/2012/0001193125-13-111031/item13.txt
new file mode 100644
index 0000000000000000000000000000000000000000..9fa45ce66d5faa6011e28511020bf0749f3a2b61
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/item13.txt
@@ -0,0 +1,4 @@
+Item 13. 
+Certain Relationships and Related Transactions, and Director Independence. 
+The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the
+Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
\ No newline at end of file
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/item9a.txt b/raw/filings/0001520006/2012/0001193125-13-111031/item9a.txt
new file mode 100644
index 0000000000000000000000000000000000000000..02ef045364b6a172bd89e078304a352dc42a42f7
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/item9a.txt
@@ -0,0 +1,60 @@
+Item 9A. 
+Controls and Procedures. 
+Evaluation of Disclosure Controls and Procedures 
+As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in
+Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief
+Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2012 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange
+Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the
+Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. 
+Changes in Internal Control over Financial Reporting 
+During the quarter
+ended December 31, 2012, there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. 
+Management’s Report on Internal Control over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules
+13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control
+over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in “Internal 
+101
+Table of Contents 
+Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief
+Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes
+in accordance with U.S. generally accepted accounting principles. 
+Grant Thornton LLP, our independent registered public
+accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2012 as included herein. 
+Important Considerations 
+The effectiveness of our disclosure controls and
+procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems,
+the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the
+degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful
+in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. 
+102
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Matador
+Resources Company 
+We have audited the internal control over financial reporting of Matador Resources Company (a Texas corporation) and
+subsidiaries (collectively 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 March 18, 2013 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas 
+March 18, 2013 
+103
+Table of Contents
\ No newline at end of file
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/rp_note.txt b/raw/filings/0001520006/2012/0001193125-13-111031/rp_note.txt
new file mode 100644
index 0000000000000000000000000000000000000000..d5466276a6113a0521724d7a5493891e30e89410
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/rp_note.txt
@@ -0,0 +1,14 @@
+NOTE 16 — TRANSACTIONS WITH RELATED PARTIES 
+In January 2007, the Company entered into a joint venture with Marlan Downey and Julie Downey Garvin of Roxanna Oil
+Company (“Roxanna”) to assemble acreage for and to market a new natural gas shale prospect in Southwest Wyoming, Northeast Utah and Southeast Idaho. Mr. Downey is a special advisor to the Company’s Board of Directors and a
+shareholder in the Company. Ms. Garvin is President of Roxanna, which is also a shareholder in Matador. Mr. Downey and Ms. Garvin developed the prospect concept independently and sought the Company’s expertise in assembling a
+large acreage position across the prospect. The Company actively marketed this prospect in conjunction with Mr. Downey and Ms. Garvin. In May 2010, the Company, Roxanna and its subsidiary, Roxanna Rocky Mountains, LLC, entered into
+participation and joint operating agreements with an industry partner for the joint exploration and development of this opportunity. Under these agreements, Roxanna Rocky Mountains, LLC reserves a 2.5% overriding royalty interest in the leases and
+has the opportunity to earn up to a 10% working interest in all wells drilled. The industry partner has a 50% working interest in the project, and the Company retains a working interest equal to the difference between 50% and the working interest
+participation elected by Roxanna Rocky Mountains, LLC. The Company, as operator, drilled the initial test well for this prospect located in Lincoln County, Wyoming during 2011 and suspended operations. The Company re-entered this vertical well in
+late 2012 and drilled a horizontal lateral wellbore in the Meade Peak shale. This well was awaiting completion of the horizontal lateral at December 31, 2012. 
+F-47
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2012, 2011 and 2010
\ No newline at end of file
diff --git a/raw/filings/0001520006/2012/0001193125-13-111031/rpt_disclosure.txt b/raw/filings/0001520006/2012/0001193125-13-111031/rpt_disclosure.txt
new file mode 100644
index 0000000000000000000000000000000000000000..1c12ce6b7d7a266d18d3938c0bf4120918f1b82f
--- /dev/null
+++ b/raw/filings/0001520006/2012/0001193125-13-111031/rpt_disclosure.txt
@@ -0,0 +1,106 @@
+TRANSACTIONS WITH RELATED PERSONS 
+Since January 1, 2012, there has not been, nor is there currently proposed, any transaction or series of similar transactions to
+which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our 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, other than compensation arrangements with directors and executive officers, which are described in “Compensation of Named Executive Officers” and the
+transactions described or referred to below. 
+Participation in Our Initial Public Offering 
+On February 7, 2012, upon the closing of our initial public offering, the following directors purchased at least $120,000 of Common
+Stock in the directed share program from the underwriters in the offering at the initial price to the public: 
+Director or Executive Officer 
+Amount 
+Joseph Wm. Foran (1) 
+$ 
+1,660,800 
+David M. Laney (2) 
+684,000 
+Gregory E. Mitchell (3) 
+200,004 
+Carlos M. Sepulveda, Jr. 
+600,000 
+Margaret B. Shannon 
+200,004 
+(1) 
+$1,200,000 of shares were purchased by Mr. Foran, and $460,800 of shares were purchased by Sage Resources, Ltd., a limited partnership owned by the Foran family,
+including Mr. Foran. 
+(2) 
+$180,000 of shares were purchased by Mr. Laney, $144,000 of shares were purchased by Mr. Laney’s adult children, who gave Mr. Laney voting power of
+such shares through a revocable power of attorney, which power of attorney is no longer in effect, and $360,000 of shares were purchased by Laney Investments Ltd., for which Mr. Laney has sole voting and investment power.
+(3) 
+All of the shares were purchased by JAMAL Enterprises, LP, for which Mr. Mitchell has sole voting and investment authority. 
+Loan Program 
+During 2011, we guaranteed the repayment of loans to certain of our executive officers by Comerica Bank. The purpose of these loans was to assist our executive officers in buying shares of our Common
+Stock pursuant to the exercise of stock options. We guaranteed the repayment of the following loans, and made deposits of funds in certificates of deposit to secure our guarantees, for the following executive officers until January 2012, when such
+guarantees were terminated. 
+Executive Officer and Date of Loan or Renewal 
+Loan 
+Amount 
+Interest 
+Rate 
+Interest Paid or Payable 
+in 2012 through 
+Termination of
+the 
+Loan Guarantee in 
+January 2012 
+Matthew V. Hairford; December 29, 2009; renewed October 8, 2011 
+$ 
+310,000 
+5.25 
+% 
+$ 
+1,067 
+David E. Lancaster; April 30, 2009; renewed May 30, 2011 
+$ 
+470,000 
+5.25 
+% 
+$ 
+1,618 
+Bradley M. Robinson; December 29, 2008; renewed January 29, 2011 
+$ 
+280,000 
+5.25 
+% 
+$ 
+964 
+Our Board approved the termination of the loan program on April 7, 2011, and we terminated our
+guarantees and the associated pledge of our certificates of deposit with Comerica Bank relating to these loans in January 2012. We made no payments to Comerica Bank pursuant to these loan guarantees. 
+56 
+Table of Contents 
+Procedures for Approval of Related Party Transactions 
+Our Board has adopted a written related party transaction policy. Pursuant to this policy, a “Related Party Transaction” is
+defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, involving a
+Related Party (as defined below) and in which we are a participant, other than: 
+• 
+a transaction involving compensation of directors; 
+• 
+a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, change in control provision or
+agreement or a special supplemental benefit for an executive officer; 
+• 
+a transaction available to all employees generally or to all salaried employees generally; 
+• 
+a transaction with a Related Party involving less than $120,000; 
+• 
+a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that
+class receive the same benefit on a pro rata basis; or 
+• 
+a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of
+services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. 
+“Related Party” means: 
+• 
+any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or nominees for directors;
+• 
+any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; 
+• 
+any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law,
+father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and 
+• 
+any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general
+partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. 
+Pursuant to our related party transaction policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or disapproval of the Related Party
+Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all material facts of the Related Party
+Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be disclosed in our filings with the SEC
+and/or our website in accordance with applicable laws, rules and regulations. All of the Related Party Transactions discussed above occurred prior to the adoption of the policy, except for participation in our initial public offering. Those
+executive officers and directors who participated in our initial public offering negotiated with RBC Capital Markets, LLC; therefore, the related party transaction policy was not triggered. 
+57 
+Table of Contents
\ No newline at end of file
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@@ -0,0 +1,6632 @@
+10-K
+1
+mtdr10-k12312013.htm
+10-K
+MTDR 10-K 12.31.2013 
+Table of Contents 
+UNITED STATES 
+SECURITIES AND EXCHANGE COMMISSION 
+WASHINGTON, D.C. 20549 
+FORM 10-K 
+(Mark One) 
+ý 
+ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
+For the fiscal year ended December 31, 2013 
+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 001-34574 
+Matador Resources Company 
+(Exact name of registrant as specified in its charter) 
+Texas 
+27-4662601 
+(State or other jurisdiction of 
+incorporation or organization) 
+(I.R.S. Employer 
+Identification No.) 
+5400 LBJ Freeway, Suite 1500 
+Dallas, Texas 75240 
+75240 
+(Address of principal executive offices) 
+(Zip Code) 
+Registrant’s telephone number, including area code: (972) 371-5200 
+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 
+New York Stock Exchange 
+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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for 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 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 
+¨ 
+Accelerated filer 
+ý 
+Non-accelerated filer 
+¨ 
+(Do not check if a smaller reporting company) 
+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 equity of the registrant held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter was $593,728,477 . 
+As of March 13, 2014 , there were 65,744,878 shares of common stock outstanding. 
+DOCUMENTS INCORPORATED BY REFERENCE 
+The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2014 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates. 
+Table of Contents 
+MATADOR RESOURCES COMPANY 
+FORM 10-K 
+FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013 
+TABLE OF CONTENTS 
+Page 
+PART I 
+I TEM 1. 
+BUSINESS 
+3 
+I TEM 1A. 
+RISK FACTORS 
+30 
+I TEM 1B. 
+UNRESOLVED STAFF COMMENTS 
+48 
+I TEM 2. 
+PROPERTIES 
+48 
+I TEM 3. 
+LEGAL PROCEEDINGS 
+48 
+I TEM 4. 
+MINE SAFETY DISCLOSURES 
+48 
+PART II 
+I TEM 5. 
+MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 
+49 
+I TEM 6. 
+SELECTED FINANCIAL DATA 
+51 
+I TEM 7. 
+MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
+53 
+I TEM 7A. 
+QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
+73 
+I TEM 8. 
+FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
+75 
+I TEM 9. 
+CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 
+75 
+I TEM 9A. 
+CONTROLS AND PROCEDURES 
+75 
+I TEM 9B. 
+OTHER INFORMATION 
+78 
+PART III 
+I TEM 10. 
+DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 
+78 
+I TEM 11. 
+EXECUTIVE COMPENSATION 
+78 
+I TEM 12. 
+SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 
+78 
+I TEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+78 
+I TEM 14. 
+PRINCIPAL ACCOUNTING FEES AND SERVICES 
+78 
+PART IV 
+I TEM 15. 
+EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 
+79 
+i 
+Table of Contents 
+CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 
+Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “potential,” “predict,” “project,” “should” or other similar words. 
+By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the success of our drilling program, the timing of planned capital expenditures, sufficient cash flow from operations together with available borrowing capacity under our credit agreement, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, availability of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this Annual Report on Form 10-K and in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”), all of which are difficult to predict. Forward-looking statements may include statements about: 
+• 
+our business strategy; 
+• 
+our reserves; 
+• 
+our technology; 
+• 
+our cash flows and liquidity; 
+• 
+our financial strategy, budget, projections and operating results; 
+• 
+our oil and natural gas realized prices; 
+• 
+the timing and amount of future production of oil and natural gas; 
+• 
+the availability of drilling and production equipment; 
+• 
+the availability of oil field labor; 
+• 
+the amount, nature and timing of capital expenditures, including future exploration and development costs; 
+• 
+the availability and terms of capital; 
+• 
+our drilling of wells; 
+• 
+government regulation and taxation of the oil and natural gas industry; 
+• 
+our marketing of oil and natural gas; 
+• 
+our exploitation projects or property acquisitions; 
+• 
+our costs of exploiting and developing our properties and conducting other operations; 
+• 
+general economic conditions; 
+• 
+competition in the oil and natural gas industry; 
+• 
+the effectiveness of our risk management and hedging activities; 
+• 
+environmental liabilities; 
+• 
+counterparty credit risk; 
+• 
+developments in oil-producing and natural gas-producing countries; 
+• 
+our future operating results; 
+• 
+estimated future reserves and the present value thereof; and 
+• 
+our plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical. 
+Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition. 
+You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such 
+1 
+Table of Contents 
+forward-looking statements, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. 
+2 
+Table of Contents 
+PART I 
+Item 1. Business. 
+In this Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly-owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company. 
+Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering. 
+For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. 
+General 
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, we have a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where we are testing the Meade Peak shale. 
+We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. 
+On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: 
+• focus exploration and development activity on our Eagle Ford acreage in South Texas; 
+• explore and develop our Wolfcamp and Bone Spring acreage in the Permian Basin; 
+• identify, evaluate and develop oil and natural gas plays to maintain a balanced portfolio; 
+• continue to improve operational and cost efficiencies; 
+• maintain our financial discipline; and 
+• pursue opportunistic acquisitions. 
+The successful execution of our business strategies in 2013 led to significant increases in our oil and natural gas revenues and Adjusted EBITDA, oil production and proved oil and natural gas reserves, and the associated increase in the PV-10 of our proved reserves. We also significantly increased our leasehold position in the Permian Basin and added to our acreage positions in the Eagle Ford shale and the Haynesville shale. Adjusted EBITDA and PV-10 are non-GAAP financial measures. For a definition of such terms and a reconciliation to the most directly comparable GAAP financial measures, see “Selected Financial Data — Non-GAAP Financial Measures” and “—Estimated Proved Reserves.” 
+3 
+Table of Contents 
+2013 Highlights 
+Increased Oil and Natural Gas Revenues and Adjusted EBITDA 
+Our oil and natural gas revenues for the year ended December 31, 2013 were the highest achieved in any fiscal year in the Company’s history. Our oil and natural gas revenues increased $113.0 million to $269.0 million in 2013 , which represents an increase of 72% from 2012. This revenue increase was primarily driven by a significant increase in our oil production in 2013 and a higher weighted average natural gas price realized in 2013 . Our Adjusted EBITDA of $191.8 million for 2013 was an increase of 65% , as compared to our Adjusted EBITDA of $115.9 million for 2012. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” 
+Increased Oil and Oil Equivalent Production 
+Our total oil production and our average daily oil equivalent production for the year ended December 31, 2013 were the best in our history. In 2013 , we produced 2.1 million barrels of oil, an increase of 76% , as compared to 1.2 million barrels of oil produced in 2012. Our average daily oil equivalent production was 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, an increase of 30% , as compared to 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, for the year ended December 31, 2012 . This increase in oil production was a direct result of our drilling operations in the Eagle Ford shale. We achieved this increased oil production despite having as much as 15% to 20% of our production capacity shut in at various times during 2013 , as we continued our operational practices of pad and batch drilling in the Eagle Ford shale and shutting in producing wells while conducting drilling and completion operations on offsetting wells. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2013 , as compared to 37% for the year ended December 31, 2012 and 6% for the year ended December 31, 2011. 
+Increased Oil and Natural Gas Reserves 
+At December 31, 2013 , our estimated total proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, which is an increase of 117% from December 31, 2012 . The associated PV-10 of our estimated total proved oil and natural gas reserves increased 55% to $655.2 million at December 31, 2013 from $423.2 million at December 31, 2012 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” 
+Our proved oil reserves grew 56% to 16.4 million Bbl at December 31, 2013 , as compared to 10.5 million Bbl at December 31, 2012 . This growth in oil reserves was primarily attributable to our drilling program in the Eagle Ford shale during 2013. Our proved natural gas reserves increased 165% to 212.2 Bcf at December 31, 2013 from 80.0 Bcf at December 31, 2012 . This large increase in proved natural gas reserves was attributable to our drilling and completion activities and improvements in natural gas prices in 2013. As a result of the continued improvement in natural gas prices during 2013, we re-classified Haynesville shale natural gas volumes previously removed from our proved reserves in 2012 as proved undeveloped reserves in 2013 and also included additional Haynesville shale proved undeveloped natural gas reserves in our total proved reserves at December 31, 2013 . 
+At December 31, 2013 , proved developed reserves included 8.3 million Bbl of oil and 53.5 Bcf of natural gas, and proved undeveloped reserves included 8.1 million Bbl of oil and 158.7 Bcf of natural gas. Proved developed reserves comprised 33% and proved oil reserves comprised 32% of our total proved oil and natural gas reserves, respectively, at December 31, 2013 . Based on our 2013 year-end total proved reserves and our 2013 oil equivalent production of 4.3 million BOE, we improved our reserves/production (“R/P”) ratio to 12.1 years at December 31, 2013 , as compared to 7.2 years at December 31, 2012 . 
+Operational Efficiencies 
+We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to manage more effectively operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past two years. 
+D uring this time, we have progressed from drilling wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In August 2013, we began drilling certain wells on our western Eagle Ford acreage from batch drilled pads using a drilling rig equipped with a “walking” package and, as a result, we have improved both drilling times and costs. We have realized cost savings of approximately $325,000 per well on initial wells drilled using this rig, and we expect the use of batch drilling and the “walking” rig will lead to total cost savings of approximately $400,000 per well or more going 
+4 
+Table of Contents 
+forward. Recent wells drilled on our western Eagle Ford acreage in La Salle County, Texas have drilling times from spud to total depth of eight to 10 days per well and costs at or just below $6 million per well. In April 2014, we expect to replace the drilling rig currently operating in the central portion of our acreage in Karnes and Wilson Counties, Texas with a new “walking” rig. At that time, we will have two “walking” rigs operating in the Eagle Ford and will conduct batch drilling operations on our properties using these rigs for the balance of 2014. Recent wells in our central Eagle Ford acreage have been drilled for between $7.0 and $7.5 million, but we expect to see further cost improvements with the initiation of batch drilling operations in this area as well. We anticipate that we will drill almost 250,000 lateral feet with two rigs in the Eagle Ford in 2014, as compared to 150,000 feet using two rigs in 2012 and effectively 1.5 rigs in 2013, an increased drilling efficiency of almost 70%. 
+During 2013, we continued to refine the design of our hydraulic fracture treatments to enhance well productivity and ultimate hydrocarbon recovery, increasing fluid volumes to 40 Bbl per foot and proppant volumes to more than 2,000 pounds per foot, while decreasing the spacing between perforation clusters where the fractures are initiated. These Generation 5, and now Generation 6, fracture treatments are resulting in significant improvements in initial well productivity as compared to earlier generation treatment designs. We also believe that initiating the use of gas lift relatively early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. 
+Acreage Acquisitions 
+During 2013, we acquired approximately 55,400 gross (38,900 net) acres in the Permian Basin in Southeast New Mexico and West Texas. These acreage acquisitions brought our total Permian Basin acreage position to approximately 70,800 gross (44,800 net) acres as of December 31, 2013 . Between January 1 and December 31, 2013 , we also acquired approximately 1,720 gross (1,660 net) acres in the Eagle Ford shale play in South Texas and approximately 1,190 gross (1,190 net) acres in the Haynesville shale play in Northwest Louisiana. 
+Issuance of Common Stock 
+In April 2013, we filed with the SEC a universal shelf registration statement on Form S-3 (the “Shelf Registration Statement”), which provided us with the ability to offer and sell up to $300 million of debt and equity securities, subject to market conditions and our capital needs. The SEC declared the Shelf Registration Statement effective on May 9, 2013. As of December 31, 2013, we had approximately $151 million of securities available for issuance under the Shelf Registration Statement. 
+On September 10, 2013, we completed an underwritten public offering of 9,775,000 shares of our common stock and received net proceeds of approximately $141.7 million. The net proceeds from this offering were used to fund a portion of our capital expenditures, including the addition of a third rig to our drilling program and the acquisition of additional acreage in the Eagle Ford shale, the Permian Basin and the Haynesville shale. Pending such uses, we used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under our third amended and restated credit agreement (the “Credit Agreement”) in September 2013, which amounts may be reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. 
+Recent Developments 
+On March 12, 2014 , the borrowing base under our Credit Agreement was increased to $385.0 million , and the conforming borrowing base was increased to $310.0 million based on the lenders’ review of our proved oil and natural gas reserves at December 31, 2013 . At that time, we also amended our Credit Agreement to include Wells Fargo Bank, N.A., which replaced Capital One, N.A., in our lending group, which also includes Royal Bank of Canada, as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia, SunTrust Bank, BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank. At March 13, 2014 , we had $250.0 million in borrowings and $0.3 million in letters of credit outstanding under our Credit Agreement. 
+Between January 1 and March 13, 2014 , we acquired an additional 7,000 gross (5,300 net) acres in Southeast New Mexico and West Texas, bringing our total Permian Basin acreage position to 77,800 gross (50,100 net) acres as of March 13, 2014 . 
+Principal Areas of Interest 
+Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Eagle Ford shale play in South Texas, the Haynesville shale play in Northwest Louisiana and most recently, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. During 2013 , we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in South Texas as we sought to continue to increase our oil production and reserves. Since our inception, our exploration efforts have 
+5 
+Table of Contents 
+concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2013, essentially all of our efforts are focused on unconventional plays. 
+At December 31, 2013 , our principal areas of interest consisted of the Eagle Ford shale play in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas, and the Meade Peak shale play in Southwest Wyoming and the adjacent areas of Utah and Idaho. 
+The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2013 : 
+Producing 
+Total Identified 
+Estimated Net Proved 
+Wells 
+Drilling Locations (1) 
+Reserves (2) 
+Avg. Daily 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+% 
+Production 
+Acreage 
+MBOE (3) 
+Developed 
+(BOE/d) (3) 
+South Texas: 
+Eagle Ford (4) 
+27,147 
+73 
+63.3 
+273 
+229.3 
+20,221 
+54.9 
+8,225 
+NW Louisiana/E Texas: 
+Haynesville 
+14,969 
+140 
+13.0 
+527 
+114.5 
+28,797 
+14.9 
+2,831 
+Cotton Valley (5) 
+21,821 
+100 
+63.7 
+71 
+49.3 
+1,339 
+100.0 
+600 
+Area Total (6) 
+25,761 
+240 
+76.7 
+598 
+163.8 
+30,136 
+18.7 
+3,431 
+Permian Basin: 
+SE New Mexico, West Texas (7) 
+44,834 
+13 
+5.0 
+241 
+177.7 
+1,372 
+31.1 
+84 
+Other: 
+Wyoming, Utah, Idaho 
+36,004 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+133,746 
+326 
+145.0 
+1,112 
+570.8 
+51,729 
+33.2 
+11,740 
+__________________ 
+(1) 
+Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2013 . The total net engineered drilling locations is calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2013 , these engineered drilling locations included 52 gross (39.8 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford, four gross (3.4 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Permian Basin and 125 gross (20.6 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formation at December 31, 2013 . 
+(2) 
+These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. 
+(3) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(4) 
+Includes two wells producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(5) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(6) 
+Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. 
+(7) 
+Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring or Avalon shale plays on our acreage in the Permian Basin at December 31, 2013 . 
+We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation and others. At December 31, 2013 , we were the operator for approximately 90% of our Eagle Ford acreage and 70% of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by a subsidiary of Chesapeake Energy Corporation. We also operate the majority of our acreage in the Permian Basin in Southeast New Mexico and West Texas, as well as all of our acreage in Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interests are often relatively small, particularly in the Haynesville shale. 
+From time to time, we enter into joint operating agreements with our co-working interest partners governing operations on certain of our jointly owned wells and properties. Particularly when our working interest is small, however, we do not 
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+always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our business arrangement in accordance with industry standard practices. Where we do have joint operating agreements with affiliates of other companies, these agreements call for significant penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose. 
+While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. 
+South Texas — Eagle Ford Shale and Other Formations 
+The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. 
+At December 31, 2013 , our properties included approximately 39,000 gross ( 27,100 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 87% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 82% of our Eagle Ford acreage was held by production at December 31, 2013 , and approximately 97% of our Eagle Ford acreage was either held by production at December 31, 2013 or not burdened by lease expirations before 2015 . During the year ended December 31, 2013 , we acquired approximately 1,720 gross (1,660 net) acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This acreage essentially replaced the acreage upon which we drilled and established oil and natural gas production and reserves during 2013 . 
+At December 31, 2013 , we had 73 gross ( 63.3 net) wells producing from the Eagle Ford shale in South Texas. We had drilled and completed a total of 61 gross (59.5 net) Eagle Ford wells on our operated properties, and we had also participated in 12 gross (3.8 net) Eagle Ford wells with co-working interest owners on certain of our non-operated Eagle Ford properties. 
+During 2013 , approximately 70% of our total capital expenditures of $373.5 million were directed to our operations in South Texas, and almost entirely in the Eagle Ford shale, as we continued executing our strategy to significantly increase our oil production and oil reserves. During the first quarter of 2013, we had two contracted drilling rigs operating full-time in South Texas and all of our operated drilling and completion activities were focused on the Eagle Ford shale. In late April 2013, we moved one of these contracted drilling rigs to Southeast New Mexico, while the second contracted drilling rig continued to operate in the Eagle Ford shale. In mid-August 2013, we added a third contracted drilling rig to our drilling program and returned to operating two contracted drilling rigs in the Eagle Ford shale play. We expect to operate two contracted drilling rigs in South Texas throughout 2014 . At March 13, 2014 , one of our two Eagle Ford rigs was operating in southern Wilson County, Texas, while the other was operating in La Salle County, Texas. The development of our Eagle Ford shale properties in South Texas will continue to be the primary driver of our growth in 2014 , and we intend to direct approximately $318.4 million , or 72%, of our estimated 2014 capital expenditure budget of $440.0 million to our operations in South Texas. 
+During the year ended December 31, 2013 , we completed and began producing oil and natural gas from 32 gross (27.6 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 25 gross (25.0 net) operated and seven gross (2.6 net) non-operated wells. As we completed and began producing oil and natural gas from these wells during 2013 , our Eagle Ford production increased significantly. For the year ended December 31, 2013 , 70% of our daily oil equivalent production, or 8,225 BOE per day, including 5,748 Bbl of oil per day and 14.9 MMcf of natural gas per day, was produced 
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+from the Eagle Ford shale. Almost all of our oil production in 2013 and 2012 was attributable to the Eagle Ford shale. The Eagle Ford shale contributed approximately 98% of our daily oil production and approximately 42% of our daily natural gas production during 2013 , as compared to approximately 98% of our daily oil production and approximately 12% of our daily natural gas production during 2012 . During the year ended December 31, 2012 , approximately 44% of our daily production, or 3,928 BOE per day, including 3,261 Bbl of oil per day and 4.0 MMcf of natural gas per day, was attributable to the Eagle Ford shale. During the year ended December 31, 2011, only about 8% of our daily production, or 548 BOE per day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past several years reflects our ongoing drilling and completion operations in South Texas. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich natural gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other heavier natural gas liquids components. Our Eagle Ford wells typically yield five to seven gallons of natural gas liquids per Mcf of natural gas produced at the wellhead depending on the specific property. 
+At December 31, 2013 , approximately 39% of our estimated total proved oil and natural gas reserves, or 20.2 million BOE, was attributable to the Eagle Ford shale, including approximately 15.2 million Bbl of oil and 30.1 Bcf of natural gas. Our proved reserves attributable to the Eagle Ford shale increased approximately 41% to 20.2 million BOE for the year ended December 31, 2013 , as compared to 14.4 million BOE for the year ended December 31, 2012 . Our Eagle Ford proved reserves at December 31, 2013 comprised approximately 93% of our proved oil reserves and 14% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 30% of our proved natural gas reserves at December 31, 2012 . The PV-10 of our proved reserves in the Eagle Ford shale at December 31, 2013 was $540.4 million , or approximately 82% of the PV-10 of our total proved reserves of $655.2 million . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” 
+At December 31, 2013 , we have identified and engineered 273 gross ( 229.3 net) locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Of the 273 gross ( 229.3 net) engineered locations identified for potential future drilling in the Eagle Ford shale at December 31, 2013 , we consider 150 gross (125.9 net) locations to be Tier 1 locations. We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of 225,000 Bbl of oil or greater. Of these Tier 1 locations, 114 gross (111.5 net) locations would be operated by us. These identified locations presume that we will be able to develop our Eagle Ford properties on 40-acre to 80-acre spacing, depending on the specific property and the wells we have already drilled. As a result of the initial performance of test wells drilled on 40-acre and 50-acre spacing during 2013 , we anticipate that Eagle Ford shale wells on our acreage in central and northern La Salle County, northern Karnes County and southern Wilson County can be developed on 40-acre spacing, while our other properties may be more likely developed on 80-acre spacing. We are currently drilling on 40-acre spacing on most of our properties in central and northern La Salle County, northern Karnes County and southern Wilson County. On our properties in the eastern portion of our Eagle Ford acreage in DeWitt County, we continue to drill on 80-acre spacing with no plans to test less than 80-acre spacing at December 31, 2013 , because we believe that higher permeability, better transmissibility and higher pressure in these areas make these properties less conducive to reduced spacing. 
+We define Tier 2 Eagle Ford locations, including 123 gross (103.4 net) locations, as those locations that we anticipate to have estimated ultimate recoveries of between 150,000 Bbl and 225,000 Bbl of oil, locations that are primarily prospective for natural gas or locations with lesser estimates of ultimate oil recovery, but on properties already held by existing production. At December 31, 2013 , Tier 2 locations were identified primarily on our acreage in Zavala County, southern La Salle County and eastern Gonzales County. We have identified no potential future Eagle Ford drilling locations on our Atascosa County acreage. All of these Tier 2 locations would be operated by us, and almost all of these locations are on properties already held by production from the Eagle Ford or other producing horizons. Although we have no plans to drill any of these Tier 2 locations in 2014 , as long as these properties remain held by production, or remain in the primary terms of the leases, these locations remain available for us to drill at a later time should commodity prices improve, drilling and completion costs decline further or new technologies be developed that increase expected recoveries. Certain of these properties, such as our properties in Zavala and Atascosa Counties, also offer the opportunity to explore horizons other than the Eagle Ford, including the Austin Chalk, Buda, Edwards or Pearsall, and we may develop new prospects on these properties in the future. We have included one test of the Buda formation on our Zavala County acreage as part of our 2014 capital expenditure budget. As we explore and develop all of our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2013 , these 273 gross ( 229.3 net) potential future drilling locations included 52 gross (39.8 net) locations to which we have assigned proved undeveloped reserves. 
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+We believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past two years. During this time, we have progressed from drilling wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In August 2013, we began drilling certain wells on our western Eagle Ford acreage from batch drilled pads using a drilling rig equipped with a “walking” package and, as a result, we have improved both drilling times and costs. We realized cost savings of approximately $325,000 per well on initial wells drilled using this rig, and we expect the use of batch drilling and the “walking” rig will lead to total cost savings of approximately $400,000 per well or more going forward. Recent wells drilled on our western Eagle Ford acreage in La Salle County have drilling times from spud to total depth of eight to 10 days per well and costs at or just below $6 million per well. In April 2014, we expect to replace the drilling rig currently operating in the central portion of our acreage in Karnes and Wilson Counties with a new “walking” rig. At that time, we will have two “walking” rigs operating in the Eagle Ford and will conduct batch drilling operations on our properties using these rigs for the balance of 2014. Recent wells in our central Eagle Ford acreage have been drilled for between $7.0 and $7.5 million, but we expect to see further cost improvements with the initiation of batch drilling operations in this area as well. We anticipate that we will drill almost 250,000 lateral feet with two rigs in the Eagle Ford in 2014, as compared to 150,000 feet using two rigs in 2012 and effectively 1.5 rigs in 2013, an increased drilling efficiency of almost 70%. 
+During 2013, we continued to refine the design of our hydraulic fracture treatments to enhance well productivity and ultimate hydrocarbon recovery, increasing fluid volumes to 40 Bbl per foot and proppant volumes to more than 2,000 pounds per foot, while decreasing the spacing between perforation clusters where the fractures are initiated. These Generation 5, and now Generation 6, fracture treatments are resulting in significant improvements in initial well productivity as compared to earlier generation treatment designs. We also believe that initiating the use of gas lift relatively early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. 
+As we continue to explore and develop our leasehold positions in the Eagle Ford shale, we may face challenges with establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during 2013 or 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and optimizing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which have, among other things, required us to flare natural gas occasionally. To alleviate a portion of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in or flare our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate typically ranging in thickness from 200 to 400 feet, and the Buda formation, which is a naturally fractured carbonate typically ranging in thickness from 90 to 160 feet, have produced from several fields on or nearby portions of our acreage. We believe that approximately 21,000 gross (16,800 net) acres of our properties in South Texas are prospective for the Austin Chalk and 17,200 gross (13,300 net) acres are prospective for the Buda formation, which have historically been targeted by operators in South Texas. 
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+In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas which are held by production and which we believe are prospective for the Buda formation. We believe our acreage is located within the extension of a trend where encouraging drilling by other operators has occurred in the Buda just southwest of our leasehold position. We have acquired a 3-D seismic survey over our acreage, and at March 13, 2014 , we were evaluating a series of seismic attributes which are similar to fracture patterns observed in cores from other wells in the area and from our drilling of previous wells on the acreage in 2012 and which are consistent with regional mapping. At December 31, 2013 , we had not included any Buda locations in our future drilling locations, although we do plan to drill one gross (1.0 net) exploratory well to test the Buda formation on our Glasscock Ranch property in 2014. We participated in one non-operated test of the Buda formation in South Texas (approximately 21% working interest) on one of our leases in Atascosa County during the first quarter of 2013. This well tested a strong initial oil flow from a very short horizontal lateral, but the well was plugged and abandoned after oil production from this interval declined to uneconomic levels soon thereafter. We do not expect to participate in any additional Buda tests on our Atascosa County acreage during 2014 . 
+Southeast New Mexico and West Texas — Permian Basin 
+The Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and intense hydraulic fracturing techniques. 
+One example of such an opportunity appears to be the so-called “Wolf-Bone” play in the western Permian Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp shale formations span several thousand feet of stacked shales, sandstones, limestones and dolomites, representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural gas have been produced primarily from conventional sandstone and carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized and tested by a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a result, many industry players are expanding positions and conducting drilling programs throughout the western Permian Basin in Lea and Eddy Counties in Southeast New Mexico and Loving, Pecos, Reeves, Ward and Winkler Counties in West Texas. In addition, other industry players have been successful in developing similar formations on the eastern side of the Permian Basin, east of the Central Basin Platform in West Texas. Multiple horizontal drilling and completion targets are being identified and tested by companies throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third sands) and multiple intervals within the Wolfcamp shale, often identified as the Wolfcamp “A” through “D” intervals. 
+During 2013, we added significantly to our acreage position and initiated an exploration program to begin testing our Permian Basin leasehold. We acquired an additional 55,400 gross (38,900 net) acres in Southeast New Mexico and West Texas. At December 31, 2013 , our leasehold position included approximately 70,800 gross (44,800 net) acres in the Permian Basin, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas in the western Permian Basin. At December 31, 2013 , approximately 7,000 gross (4,900 net) of these acres were held by production. We consider the vast majority of this acreage to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon shale and Delaware formations, as well as the Abo, Strawn, Devonian, Cisco/Canyon and Glorieta/San Andres formations. We have also acquired approximately 2,000 gross (1,450 net) acres in Howard and Dawson Counties, Texas in the eastern Permian Basin, although we do not expect to drill any wells in the eastern Permian Basin in 2014. In addition, a portion of our leasehold interests in the Permian Basin, including approximately 7,300 gross (450 net) acres in Winkler County, Texas, is no longer considered to be prospective by us, and we plan to allow this acreage to expire without drilling. 
+At December 31, 2013 and March 13, 2014, we were running one contracted drilling rig in the Permian Basin to further evaluate and delineate our acreage position both geographically and geologically. During 2013, we drilled three wells in the Permian Basin - two in Lea County, New Mexico and one in Loving County, Texas. Our first well, the Ranger 12 State #1 well in Lea County, was a vertical data collection well where we took extensive well log and whole and sidewall core data in an effort to better understand the multiple potential completion targets throughout the vertical section. We were continuing to test multiple potential completion intervals in this well at December 31, 2013 . Our second well, the Ranger 33 State Com #1H in Lea County, was a 4,300-ft horizontal lateral drilled and completed in the Second Bone Spring sand with 18 fracturing stages, including 165,000 Bbl of fluid and 7.5 million pounds of sand. This well was placed on production at the end of October 2013 
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+and has continued to exhibit strong performance. In its first three months on production, including the initial cleanup phase, the well produced over 48,000 BOE, including approximately 44,000 Bbl of oil (92% oil), and continued to flow with gas lift assist. Our third well, the Dorothy White #1H in Loving County, Texas, was a 5,000-ft horizontal lateral drilled in the upper portion of the Wolfcamp formation, the Wolfcamp “A”, at approximately 10,700-ft vertical depth. We completed this well in January 2014 with 20 fracturing stages, including 200,000 Bbl of fluid and 9.8 million pounds of sand. The Dorothy White #1H was placed on production in January 2014 and flowed 1,355 BOE per day, including 902 Bbl of oil per day and 2.7 MMcf of natural gas per day (67% oil) at 3,711 pounds per square inch pressure (“psi”) on a 22/64 th inch choke during a 24-hour initial potential test. 
+Because of these encouraging initial results, we plan to run one rig continuously in the western Permian Basin throughout 2014. We have allocated approximately $108.6 million , or about 25% of our 2014 capital expenditure budget of $440.0 million , to our drilling and completion activities in the Permian Basin, as well as for the acquisition of additional leasehold interests in the area. The objective of our 2014 Permian Basin drilling program is to further evaluate and delineate our acreage position in an effort to define an expanded, multi-rig drilling program for 2015 and beyond. 
+At December 31, 2013 , we had identified and engineered 241 gross ( 177.7 net) locations for potential future drilling on our Permian Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including some Avalon shale locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Permian Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Because we have just begun the exploration of our properties in the Permian Basin in 2013, our engineered well locations at December 31, 2013 do not yet include all portions of our acreage position. Our identified well locations presume that these properties may be developed on 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. In addition, although our potential future drilling locations presume the drilling of horizontal wells, we also believe that certain portions of our acreage could lend themselves to development with vertical wells. As a result, as we explore and develop our Permian Basin acreage further, we anticipate that we may identify additional locations for future drilling. In addition, although we believe that prospective well locations exist on our acreage for the Delaware formation or other potential completion intervals, we had not included any locations for these intervals in our engineered well locations at December 31, 2013 . At December 31, 2013 , these potential future drilling locations included only four gross (3.4 net) locations in the Permian Basin to which we have assigned proved undeveloped reserves. 
+As we continue to explore and develop our leasehold positions in the Permian Basin, we may face challenges with establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Permian Basin operations, but industry activity in Southeast New Mexico and West Texas is increasing rapidly, and we may encounter difficulties in securing these services as we move forward with our exploration and development operations in this area in future periods. We believe that maintaining reliable and timely drilling and completion services, reducing drilling and completion costs and securing the necessary pipeline and natural gas processing capabilities will be essential to the successful development and profitability of the Wolfcamp, Bone Spring and other plays in the Permian Basin. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+Northwest Louisiana and East Texas 
+We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2013 , although we did participate in the drilling and completion of 11 gross (0.4 net) non-operated Haynesville shale wells. We do not plan to drill any operated Haynesville shale wells in 2014 , but we have budgeted capital expenditures of approximately $12.0 million for our participation in 26 gross (1.5 net) wells that we anticipate may be drilled by other operators on certain of our non-operated properties in 2014 , as well as for additional leasehold acquisition opportunities in the Haynesville shale play. Certain of these wells were already in progress at December 31, 2013 . During the year ended December 31, 2013 , we acquired approximately 1,190 gross (1,190 net) acres in Northwest Louisiana that we consider to be prospective primarily for natural gas production from the core area of the Haynesville shale. This acreage acquisition provides us additional operational flexibility if we resume operated activities in the Haynesville shale play in the future. At December 31, 2013 , we held approximately 28,600 gross (25,800 net) acres in Northwest Louisiana and East Texas, 
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+including 22,700 gross ( 15,000 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,800 gross (6,900 net) acres that we consider to be in the core area of the Haynesville play. 
+For the year ended December 31, 2013 , approximately 29% of our average daily oil equivalent production, or 3,431 BOE per day, including 17 Bbl of oil per day and 20.5 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 58% of our daily natural gas production, but oil production from these properties comprised only about 0.3% of our daily oil production during 2013 , as compared to approximately 88% of our daily natural gas production and approximately 1% of our daily oil production during 2012 . During the year ended December 31, 2012 , approximately 56% of our average daily oil equivalent production, or 5,042 BOE per day, including 31 Bbl of oil per day and 30.1 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. The decline in oil and particularly natural gas production from these properties over the past year reflects (i) the natural decline in production from these properties, (ii) our decision not to drill any operated Haynesville shale or Cotton Valley wells during 2013 and (iii) the lack of drilling on these properties by our co-working interest owners in 2013 . 
+For the year ended December 31, 2013 , approximately 48% of our daily natural gas production, or 17.0 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 10% , or 3.5 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2012 , approximately 76% of our daily natural gas production, or 26.0 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 12% , or 4.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. 
+At December 31, 2013 , approximately 56% of our estimated total proved reserves, or 28.8 million BOE, was attributable to the Haynesville shale with another 3% of our proved reserves, or 1.3 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. The unweighted arithmetic average of the first-day-of-the-month natural gas price used to estimate proved natural gas reserves for 2013 increased to $3.670 per MMBtu, as compared to $2.757 per MMBtu for 2012 . Primarily as a result of the continued improvement in natural gas prices over the past year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013 . We had removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our estimated total proved reserves at June 30, 2012 because the natural gas price used to estimate natural gas reserves at June 30, 2012 had declined to $3.146 per MMBtu, a price at which the natural gas volumes associated with almost all of our identified Haynesville shale well locations could no longer be classified as proved undeveloped reserves. 
+At December 31, 2013 , we had identified and engineered 527 gross ( 114.5 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 49.3 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 527 gross ( 114.5 net) locations identified for future drilling on our Haynesville acreage, 452 gross (63.6 net) locations have been identified within the 13,800 gross (6,900 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2013 , these potential future drilling locations included 125 gross (20.6 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. 
+About one-third of our acreage in the core area of the Haynesville shale play in Northwest Louisiana is operated by a subsidiary of Chesapeake Energy Corporation. During the fourth quarter of 2013, we notified Chesapeake that we would be electing to take in kind the anticipated natural gas production from most of the wells operated by Chesapeake effective January 1, 2014. In addition, in December 2013, we entered into a five-year natural gas gathering agreement effective January 1, 2014 for this natural gas production. This agreement has no firm transportation commitments and no natural gas volume commitments. We believe that taking this natural gas production in kind and transporting through this gathering agreement will improve price realizations and reduce marketing and transportation fees and other costs associated with this natural gas production by an average of approximately $0.70 or more per MMBtu beginning January 1, 2014. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities 
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+Table of Contents 
+Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+The NYMEX Henry Hub natural gas futures contract price for the earliest delivery date was $4.38 per MMBtu at March 13, 2014 . Although we do not have plans to drill any Haynesville or Cotton Valley wells on our operated properties at December 31, 2013 , as a result of the recent improvement in natural gas prices, we anticipate that certain of our co-working interest owners may elect to drill additional Haynesville wells in 2014 on properties where they are the operator. As noted above, our 2014 capital expenditure budget includes our participation in 26 gross (1.5 net) non-operated Haynesville wells in 2014, several of which were already in progress at December 31, 2013 . Should natural gas prices remain above $4.00 per MMBtu during a significant portion of 2014, however, we believe that we may receive proposals to participate in additional non-operated wells during 2014. Should we elect to participate in these non-operated Haynesville wells, our 2014 capital expenditure budget would most likely be increased accordingly. See “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling” and “Risk Factors — We Have Limited Control over Activities on Properties We Do Not Operate.” 
+Haynesville and Middle Bossier Shales 
+The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. 
+At December 31, 2013 , we had approximately 22,700 gross ( 15,000 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,800 gross (6,900 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play. We have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2013 . 
+Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.4 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including approximately one-third of our non-operated Haynesville acreage in this area of the play that is operated by a subsidiary of Chesapeake following a sale of a portion of our interest in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%. 
+Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations 
+Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. 
+All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in Northwest Louisiana, approximately 10,000 gross (9,800 net acres) at December 31, 2013 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. 
+13 
+Table of Contents 
+We have identified 71 gross ( 49.3 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove/Caspiana properties. We did not drill any of these locations in 2013 and do not plan to drill any of these locations in 2014 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve further, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2013 , we held an estimated 13,800 gross (11,400 net) leasehold and mineral acres by existing production in these areas. 
+Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale 
+At December 31, 2013 , we held leasehold interests in approximately 76,500 gross ( 36,000 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are the operator of this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2013 . 
+We began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations in September 2011 and completed drilling, well logging and coring operations in November 2011. During 2012, we conducted detailed evaluations of the well logs and conducted special core analysis to better understand the petrophysical characteristics of the Meade Peak shale. 
+In September 2012, we entered into an agreement with the principal non-operated working interest owner related to the ongoing exploration of the Meade Peak shale, pursuant to which the working interest owner (i) paid us a prospect fee of $1.0 million, (ii) agreed to provide up to a total cost of $3.0 million (carrying our 50% share) for extensions of expiring leases and new leasing in the prospect in which we will have a 50% working interest at no cost to us and (iii) agreed to carry our 50% share of the drilling and completion costs associated with the horizontal lateral up to a total cost for these operations of $5.0 million, with each party paying 50% of all drilling and completion costs in excess of $5.0 million. In return for this consideration, in December 2012, we assigned 50% of our gross and net leasehold interests in the prospect to this working interest owner. 
+In November 2012, we re-entered the Crawford Federal #1 vertical well and drilled a horizontal lateral from that wellbore into the Meade Peak shale approximately 2,500 feet in length. We completed the lateral with a five-stage fracture treatment in September 2013 and initiated flow back to recover the hydraulic fracture load fluid. Due to weather constraints, we have temporarily suspended our testing program for this well and plan to resume operations in 2014. We plan to evaluate this well with the other working interest owners before making further decisions concerning the future exploration of the Meade Peak shale in this prospect. 
+14 
+Table of Contents 
+Operating Summary 
+The following table sets forth certain unaudited production data for the years ended December 31, 2013, 2012 and 2011 : 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Unaudited Production Data: 
+Net Production Volumes: 
+Oil (MBbl) 
+2,133 
+1,214 
+154 
+Natural gas (Bcf) 
+12.9 
+12.5 
+14.5 
+Total oil equivalent (MBOE) (1) 
+4,285 
+3,294 
+2,573 
+Average daily production (BOE/d) (1) 
+11,740 
+9,000 
+7,049 
+Average Sales Prices: 
+Oil, with realized derivatives (per Bbl) 
+$ 
+98.67 
+$ 
+103.55 
+$ 
+93.80 
+Oil, without realized derivatives (per Bbl) 
+$ 
+99.79 
+$ 
+101.86 
+$ 
+93.80 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+4.47 
+$ 
+3.55 
+$ 
+4.11 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+4.35 
+$ 
+2.59 
+$ 
+3.62 
+Operating Expenses (per BOE): 
+Production taxes and marketing 
+$ 
+4.89 
+$ 
+3.54 
+$ 
+2.44 
+Lease operating 
+$ 
+9.04 
+$ 
+8.56 
+$ 
+2.82 
+Depletion, depreciation and amortization 
+$ 
+22.96 
+$ 
+24.43 
+$ 
+12.34 
+General and administrative 
+$ 
+4.85 
+$ 
+4.42 
+$ 
+5.21 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2013 from our primary operating areas: 
+Average Net Daily Production 
+Oil (Bbl/d) 
+Natural Gas (Mcf/d) 
+Oil Equivalent (BOE/d) (1) 
+Total Net Production (MBOE) (1) 
+Percentage of Total Net Production 
+South Texas: 
+Eagle Ford (2) 
+5,748 
+14,865 
+8,225 
+3,002 
+70.1 
+% 
+NW Louisiana/E Texas: 
+Haynesville 
+— 
+16,984 
+2,831 
+1,033 
+24.1 
+% 
+Cotton Valley (3) 
+17 
+3,498 
+600 
+219 
+5.1 
+% 
+Area Total 
+17 
+20,482 
+3,431 
+1,252 
+29.2 
+% 
+Permian Basin: 
+SE New Mexico, West Texas 
+78 
+36 
+84 
+31 
+0.7 
+% 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+Total 
+5,843 
+35,383 
+11,740 
+4,285 
+100.0 
+% 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+15 
+Table of Contents 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2012 from our primary operating areas: 
+Average Net Daily Production 
+Oil (Bbl/d) 
+Natural Gas (Mcf/d) 
+Oil Equivalent (BOE/d) (1) 
+Total Net Production (MBOE) (1) 
+Percentage of Total Net Production 
+South Texas: 
+Eagle Ford (2) 
+3,261 
+4,007 
+3,928 
+1,438 
+43.7 
+% 
+NW Louisiana/E Texas: 
+Haynesville 
+1 
+26,007 
+4,336 
+1,587 
+48.2 
+% 
+Cotton Valley (3) 
+30 
+4,051 
+706 
+258 
+7.8 
+% 
+Area Total 
+31 
+30,058 
+5,042 
+1,845 
+56.0 
+% 
+Permian Basin: 
+SE New Mexico, West Texas 
+25 
+30 
+30 
+11 
+0.3 
+% 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+Total 
+3,317 
+34,095 
+9,000 
+3,294 
+100.0 
+% 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+Our total production of approximately 4.3 million BOE for the year ended December 31, 2013 was an increase of 30% from our total production of approximately 3.3 million BOE for the year ended December 31, 2012 . This increased production was primarily due to our drilling operations in the Eagle Ford shale. Our average daily production for the year ended December 31, 2013 was 11,740 BOE per day, as compared to 9,000 BOE per day for the year ended December 31, 2012 . Our average daily oil production for the year ended December 31, 2013 was 5,843 Bbl of oil per day, an increase of 76% from 3,317 Bbl of oil per day for the year ended December 31, 2012 . 
+Producing Wells 
+The following table sets forth information relating to producing wells at December 31, 2013 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. 
+Oil Wells 
+Natural Gas Wells 
+Total Wells 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford (1) 
+69 
+59.3 
+4 
+4.0 
+73 
+63.3 
+NW Louisiana/E Texas: 
+Haynesville 
+— 
+— 
+140 
+13.0 
+140 
+13.0 
+Cotton Valley (2) 
+2 
+2.0 
+98 
+61.7 
+100 
+63.7 
+Area Total 
+2 
+2.0 
+238 
+74.7 
+240 
+76.7 
+Permian Basin: 
+SE New Mexico, West Texas 
+12 
+4.4 
+1 
+0.6 
+13 
+5.0 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+83 
+65.7 
+243 
+79.3 
+326 
+145.0 
+__________________ 
+(1) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+Estimated Proved Reserves 
+16 
+Table of Contents 
+The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2013, 2012 and 2011 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 
+At December 31, (1) 
+2013 
+2012 
+2011 
+Estimated Proved Reserves Data: (2) 
+Estimated proved reserves: 
+Oil (MBbl) 
+16,362 
+10,485 
+3,794 
+Natural Gas (Bcf) (3) 
+212.2 
+80.0 
+170.4 
+Total (MBOE) (4) 
+51,729 
+23,819 
+32,196 
+Estimated proved developed reserves: 
+Oil (MBbl) 
+8,258 
+4,764 
+1,419 
+Natural Gas (Bcf) (3) 
+53.5 
+54.0 
+56.5 
+Total (MBOE) (4) 
+17,168 
+13,771 
+10,843 
+Percent developed 
+33.2 
+% 
+57.8 
+% 
+33.7 
+% 
+Estimated proved undeveloped reserves: 
+Oil (MBbl) 
+8,104 
+5,721 
+2,375 
+Natural gas (Bcf) (3) 
+158.7 
+26.0 
+113.9 
+Total (MBOE) (4) 
+34,561 
+10,048 
+21,353 
+PV-10 (5) (in millions) 
+$ 
+655.2 
+$ 
+423.2 
+$ 
+248.7 
+Standardized Measure (6) (in millions) 
+$ 
+578.7 
+$ 
+394.6 
+$ 
+215.5 
+__________________ 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.670 per MMBtu for natural gas, for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas, and for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. 
+(3) 
+As a result of substantially lower natural gas prices in 2012, at June 30, 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves, most of which were attributable to non-operated properties. Primarily as a result of the continued improvement in natural gas prices during 2013, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013. 
+(4) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(5) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2013, 2012 and 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2013, 2012 and 2011 were, in millions, $76.5 , $28.6 and $33.2 , respectively. 
+(6) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+17 
+Table of Contents 
+Our estimated total proved oil and natural gas reserves increased 117% from 23.8 million BOE at December 31, 2012 to 51.7 million BOE at December 31, 2013 . Our proved oil reserves grew 56% from approximately 10.5 million Bbl at December 31, 2012 to approximately 16.4 million Bbl at December 31, 2013 . This increase is primarily attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas. Our proved natural gas reserves increased 165% from 80.0 Bcf at December 31, 2012 to 212.2 Bcf at December 31, 2013 . This increase in our proved natural gas reserves was attributable to our drilling and completion activities in 2013 and to the increase in our proved undeveloped natural gas reserves in 2013 from 26.0 Bcf at December 31, 2012 to 158.7 Bcf at December 31, 2013 due primarily to higher natural gas prices. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf ( 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012 . During 2013, primarily as a result of continued improvement in natural gas prices during the year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013 . The PV-10 of our total proved oil and natural gas reserves increased by 55% from $423.2 million at December 31, 2012 to $655.2 million at December 31, 2013 . Our total proved reserves at December 31, 2013 were made up of approximately 32% oil and 68% natural gas, as compared to 44% oil and 56% natural gas at December 31, 2012 . 
+Our proved developed oil and natural gas reserves increased from 13.8 million BOE at December 31, 2012 to 17.2 million BOE at December 31, 2013 due primarily to additions resulting from our drilling operations in the Eagle Ford shale. Our proved developed oil reserves increased from 4.8 million Bbl at December 31, 2012 to 8.3 million Bbl at December 31, 2013 as a result of our drilling operations in the Eagle Ford shale. Our proved developed natural gas reserves decreased slightly from 54.0 Bcf at December 31, 2012 to 53.5 Bcf at December 31, 2013 due primarily to declining natural gas production in the Haynesville shale and Cotton Valley coupled with the fact that we did not drill any operated Haynesville shale or Cotton Valley wells on our operated properties during 2013 and likewise, our co-working interest owners drilled very few Haynesville shale wells on the properties they operate. 
+The following table summarizes changes in our estimated proved developed reserves at December 31, 2013 . 
+Proved Developed Reserves 
+(MBOE) (1) 
+As of December 31, 2012 
+13,771 
+Extensions and discoveries 
+3,971 
+Purchases of minerals-in-place 
+28 
+Revisions of prior estimates 
+(651 
+) 
+Production 
+(4,285 
+) 
+Conversion of proved undeveloped to proved developed 
+4,334 
+As of December 31, 2013 
+17,168 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+Our proved undeveloped oil and natural gas reserves increased from 10.0 million BOE at December 31, 2012 to 34.6 million BOE at December 31, 2013 . Our proved undeveloped oil reserves increased from 5.7 million Bbl at December 31, 2012 to 8.1 million Bbl at December 31, 2013 , primarily as a result of our drilling operations in the Eagle Ford shale. Our proved undeveloped natural gas reserves increased from 26.0 Bcf at December 31, 2012 to 158.7 Bcf at December 31, 2013 due primarily to the previously discussed addition of approximately 134.2 Bcf ( 22.4 MBOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which is reflected in our estimated total proved reserves at December 31, 2013 . 
+At December 31, 2013 , we had no proved reserves in our estimates that remained undeveloped for five years or more following their booking. 
+18 
+Table of Contents 
+The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2013 . 
+Proved Undeveloped Reserves 
+(MBOE) (1) 
+As of December 31, 2012 
+10,048 
+Extensions and discoveries 
+15,260 
+Purchases of minerals-in-place 
+— 
+Revisions of prior estimates 
+13,587 
+Conversion of proved undeveloped to proved developed 
+(4,334 
+) 
+As of December 31, 2013 
+34,561 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth, since 2011, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). 
+Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves 
+Proved Undeveloped Reserves Converted to Proved Developed Reserves 
+Oil 
+Natural Gas 
+Total 
+(MBbl) 
+(Bcf) 
+(MBOE) (1) 
+2011 
+— 
+3.4 
+573 
+$ 
+1,409 
+2012 
+283 
+0.8 
+415 
+8,096 
+2013 
+2,944 
+8.3 
+4,334 
+115,699 
+Total 
+3,227 
+12.5 
+5,322 
+$ 
+125,204 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2013 : 
+Net Proved Reserves (1) 
+Oil 
+Natural Gas 
+Oil Equivalent 
+PV-10 (2) 
+Standardized Measure (3) 
+(MBbl) 
+(Bcf) 
+(MBOE) (4) 
+(in millions) 
+(in millions) 
+South Texas: 
+Eagle Ford (5) 
+15,198 
+30.1 
+20,221 
+$ 
+540.4 
+$ 
+477.3 
+NW Louisiana/E Texas: 
+Haynesville 
+— 
+172.8 
+28,797 
+74.7 
+66.0 
+Cotton Valley (6) 
+36 
+7.8 
+1,339 
+8.2 
+7.2 
+Area Total 
+36 
+180.6 
+30,136 
+82.9 
+73.2 
+Permian Basin: 
+SE New Mexico, West Texas 
+1,128 
+1.5 
+1,372 
+31.9 
+28.2 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+Total 
+16,362 
+212.2 
+51,729 
+$ 
+655.2 
+$ 
+578.7 
+__________________ 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 
+19 
+Table of Contents 
+2013 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2013 were approximately $ 76.5 million . 
+(3) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+(4) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(5) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(6) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+Technology Used to Establish Reserves 
+Under current SEC rules, proved reserves are those quantities of oil and natural gas, 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 economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven 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 have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. 
+In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. 
+Internal Control Over Reserves Estimation Process 
+We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Vice President – Reservoir Engineering is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 36 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. 
+20 
+Table of Contents 
+Acreage Summary 
+The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2013 . 
+Developed Acres 
+Undeveloped Acres 
+Total Acres 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+22,604 
+18,206 
+16,381 
+8,941 
+38,985 
+27,147 
+NW Louisiana/E Texas: 
+Haynesville 
+18,960 
+11,238 
+3,734 
+3,731 
+22,694 
+14,969 
+Cotton Valley 
+20,510 
+18,418 
+3,916 
+3,403 
+24,426 
+21,821 
+Area Total (1) 
+24,215 
+21,885 
+4,392 
+3,876 
+28,607 
+25,761 
+Permian Basin: 
+SE New Mexico, West Texas 
+1,120 
+897 
+69,699 
+43,937 
+70,819 
+44,834 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+76,496 
+36,004 
+76,496 
+36,004 
+Total 
+47,939 
+40,988 
+166,968 
+92,758 
+214,907 
+133,746 
+__________________ 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Undeveloped Acreage Expiration 
+The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2013 that will expire prior to December 31, 2015 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. 
+Acres 
+Acres 
+Expiring 2014 
+Expiring 2015 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+2,879 
+846 
+2,343 
+1,777 
+NW Louisiana/E Texas: 
+Haynesville 
+11 
+11 
+— 
+— 
+Cotton Valley 
+11 
+11 
+— 
+— 
+Area Total (1) 
+11 
+11 
+— 
+— 
+Permian Basin: 
+SE New Mexico, West Texas 
+7,775 
+706 
+5,496 
+2,439 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+Total 
+10,665 
+1,563 
+7,839 
+4,216 
+__________________ 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. 
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+Table of Contents 
+Drilling Results 
+The following table summarizes our drilling activity for the years ended December 31, 2013, 2012 and 2011 : 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development Wells 
+Productive 
+32 
+20.7 
+36 
+17.1 
+30 
+0.6 
+Dry 
+— 
+— 
+— 
+— 
+— 
+— 
+Exploration Wells 
+Productive 
+14 
+8.7 
+22 
+10.4 
+30 
+10.2 
+Dry (1) 
+1 
+0.4 
+— 
+— 
+— 
+— 
+Total Wells 
+Productive 
+46 
+29.4 
+58 
+27.5 
+60 
+10.8 
+Dry (1) 
+1 
+0.4 
+— 
+— 
+— 
+— 
+__________________ 
+(1) 
+We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013. 
+Marketing 
+Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. 
+Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. 
+The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+For the year ended December 31, 2013 , we had five significant purchasers that accounted for approximately 87% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2012 and 2011 , we had three significant purchasers that accounted for approximately 74% and 60% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. 
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+Table of Contents 
+About one-third of our acreage in the core area of the Haynesville shale play in Northwest Louisiana is operated by a subsidiary of Chesapeake Energy Corporation. During the fourth quarter of 2013, we notified Chesapeake that we would be electing to take in kind the anticipated natural gas production from most of the wells operated by Chesapeake effective January 1, 2014. In addition, we entered into a five-year natural gas gathering agreement effective January 1, 2014 for this anticipated natural gas production. This agreement has no firm transportation commitments and no natural gas volume commitments. We believe that taking our natural gas production in kind and transporting through this gathering agreement will improve price realizations and reduce marketing and transportation fees and other costs associated with this natural gas production by an average of approximately $0.70 or more per MMBtu. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. 
+Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain periods, we had an immaterial natural gas deficiency and the counterparty to this agreement has agreed to waive the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Title to Properties 
+We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” 
+Seasonality 
+Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations. 
+Competition 
+The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which 
+23 
+Table of Contents 
+would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. 
+Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. 
+The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” 
+Regulation 
+Oil and Natural Gas Regulation 
+Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. 
+Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. 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. 
+Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. 
+Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue. 
+In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. 
+24 
+Table of Contents 
+Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. 
+Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. 
+The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. 
+In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. 
+U.S. Federal and State Taxation 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” 
+Hydraulic Fracturing Policies and Procedures 
+We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” 
+The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). 
+Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures. 
+25 
+Table of Contents 
+The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. 
+While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. 
+Environmental Regulation 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. 
+The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us. 
+The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has 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. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards. 
+CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various 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 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 responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third 
+26 
+Table of Contents 
+parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. 
+RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. 
+The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (“VOC”) emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. We continue to evaluate the effect these rules have on our business and operations, which effects we do not expect to be material. 
+Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
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+Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. 
+Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows. 
+In addition, in some states and localities, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. 
+The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA recently issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, the EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released in December 2012, with draft final results expected in 2014. Further, the BLM has proposed rules to regulate hydraulic fracturing on federal lands. The EPA has also announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. 
+Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub- 
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+surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, 
+have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 
+We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. 
+The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted. 
+We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” 
+The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. 
+We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 
+Office Lease 
+Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. In April 2013 , we entered into the fifth amendment to our office lease agreement. This amendment increased the square footage of our corporate headquarters to 40,071 square feet effective July 1, 2013 . The lease expires on June 30, 2022 . 
+Employees 
+At December 31, 2013 , we had 66 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. 
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+Available Information 
+Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only. 
+Item 1A. Risk Factors. 
+Risks Related to the Oil and Natural Gas Industry and Our Business 
+Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations. 
+The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital, borrowing capacity under our Credit Agreement and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following: 
+• 
+the domestic and foreign supply of oil and natural gas; 
+• 
+the domestic and foreign demand for oil and natural gas; 
+• 
+the prices and availability of competitors’ supplies of oil and natural gas; 
+• 
+the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls; 
+• 
+the price and quantity of foreign imports; 
+• 
+the impact of U.S. dollar exchange rates on oil and natural gas prices; 
+• 
+domestic and foreign governmental regulations and taxes; 
+• 
+speculative trading of oil and natural gas futures contracts; 
+• 
+the availability, proximity and capacity of gathering, processing and transportation systems for natural gas; 
+• 
+the availability of refining capacity; 
+• 
+the prices and availability of alternative fuel sources; 
+• 
+weather conditions and natural disasters; 
+• 
+political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America; 
+• 
+the continued threat of terrorism and the impact of military action and civil unrest; 
+• 
+public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; 
+• 
+the level of global oil and natural gas inventories and exploration and production activity; 
+• 
+the impact of energy conservation efforts; 
+• 
+technological advances affecting energy consumption; and 
+• 
+overall worldwide economic conditions. 
+Approximately 50% of our production during the year ended December 31, 2013 and 68% of our proved reserves at December 31, 2013 were attributable to natural gas. In addition, three of our significant assets or prospects — the Haynesville 
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+shale, Cotton Valley and Meade Peak shale — currently produce or are expected to produce predominantly natural gas. As a result, they are sensitive to fluctuations in natural gas prices. 
+During 2013 , natural gas prices began the year with a low of approximately $3.11 per MMBtu in early January , climbed to approximately $4.41 per MMBtu in late April and fell back to approximately $3.23 per MMBtu in early August before reaching a 2013 high of approximately $4.46 per MMBtu in late December , based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. Natural gas prices climbed to above $6.00 per MMBtu in early 2014 and settled at $4.38 per MMBtu at March 13, 2014 , based upon the NYMEX Henry Hub natural gas futures contract for the earliest delivery date. Although we do not expect to drill any operated natural gas wells in the Haynesville shale or Cotton Valley in 2014, given the recent improvement in natural gas prices, we anticipate that certain of our co-working interest owners may drill natural gas wells, and in particular Haynesville shale wells, on properties they operate. We expect to be offered the opportunity to participate, and most likely will participate, in these non-operated natural gas wells. 
+In 2011, we began to focus on increasing our oil and liquids production. Specifically, our drilling opportunities in the Eagle Ford shale play in South Texas and in the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas focus on oil and liquids. Approximately 50% of our production during the year ended December 31, 2013 and 32% of our proved reserves at December 31, 2013 were attributable to oil. We currently intend to allocate approximately 97% of our 2014 capital expenditure budget to opportunities prospective for oil and liquids production, including primarily the Eagle Ford shale and the Wolfcamp and Bone Spring plays. These opportunities are sensitive to changes in oil prices. For the year ended December 31, 2013 , oil prices ranged from a low of approximately $86.68 per Bbl in mid-April to a high of approximately $110.53 per Bbl in early September , based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. 
+Declines in oil or natural gas prices not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically and could reduce the amount we may borrow under our Credit Agreement. Should oil prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities (as we have done with our operated natural gas properties in recent years), each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. In addition, such declines in commodity prices could cause a reduction in our borrowing base. If the borrowing base were to be less than the outstanding borrowings under our Credit Agreement at any time, we would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. 
+Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business. 
+Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling, completing and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. 
+If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling and completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from, or abandonment of, the well. The productivity and profitability of a well may be negatively affected by a number of additional factors, including the following: 
+• 
+general economic and industry conditions, including the prices received for oil and natural gas; 
+• 
+shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel; 
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+• 
+potential drainage by operators on adjacent properties; 
+• 
+loss of or damage to oilfield development and service tools; 
+• 
+problems with title to the underlying properties; 
+• 
+increases in severance taxes; 
+• 
+adverse weather conditions that delay drilling activities or cause producing wells to be shut in; 
+• 
+domestic and foreign governmental regulations; and 
+• 
+proximity to and capacity of gathering, processing and transportation facilities. 
+If we do not drill productive and profitable wells in the future, our business, financial condition, results of operations, cash flows and reserves could be materially and adversely affected. 
+Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth. 
+Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash, operating cash flows and potential future borrowings under our Credit Agreement or otherwise may not be sufficient to fund all of our future acquisitions or future capital expenditures. The rate of our future growth is dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable. 
+Although we currently have no plans to do so, we may sell additional equity securities or issue debt securities to raise capital. If we succeed in selling additional equity securities or securities convertible into equity securities to raise funds, the ownership of our existing shareholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing shareholders. If we raise additional capital through the issuance of new debt securities or additional indebtedness, we may become subject to additional covenants that restrict our business activities. 
+Our cash flows from operations and access to capital are subject to a number of variables, including: 
+• 
+our estimated proved oil and natural gas reserves; 
+• 
+the amount of oil and natural gas we produce from existing wells; 
+• 
+the prices at which we sell our production; 
+• 
+the costs of developing and producing our oil and natural gas reserves; 
+• 
+our ability to acquire, locate and produce new reserves; 
+• 
+the ability and willingness of banks to lend to us; and 
+• 
+our ability to access the equity and debt capital markets. 
+In addition, the possible occurrence of future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets, has caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future. 
+If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in certain exploration opportunities. Alternatively, to fund an acquisition, increase our rate of growth, develop our properties or pay for higher service costs, we may decide to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise to meet any increase in capital spending. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and future results of operations could be adversely affected. 
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+We May Incur Additional Indebtedness Which Could Reduce Our Financial Flexibility, Increase Interest Expense and Adversely Impact Our Operations and Our Unit Costs. 
+At March 13, 2014 , we had available borrowings of approximately $134.7 million under our Credit Agreement (after giving effect to outstanding letters of credit). Our borrowing base is determined semi-annually by our lenders based primarily on the estimated value of our existing and future acquired oil and natural gas reserves, but both we and our lenders can request one unscheduled redetermination between scheduled redetermination dates. Our Credit Agreement is secured by substantially all of our interests in our oil and natural gas properties and contains covenants restricting our ability to incur additional indebtedness, sell assets, pay dividends and make certain investments. Since the borrowing base is subject to periodic redeterminations, if a redetermination resulted in a lower borrowing base, we could be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or repay the deficit in equal installments over a period of six months. If we are required to do so, we may not have sufficient funds to fully make such repayments. 
+In the future, we may incur significant amounts of additional indebtedness, including under our Credit Agreement, in order to fund acquisitions, develop our properties or invest in certain exploration opportunities. Interest rates on such future indebtedness may be higher than current levels, causing our financing costs to increase accordingly. 
+A high level of indebtedness could affect our operations in several ways, including the following: 
+• 
+requiring a significant portion of our cash flows to be used for servicing our indebtedness; 
+• 
+increasing our vulnerability to general adverse economic and industry conditions; 
+• 
+placing us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our level of indebtedness may prevent us from pursuing; 
+• 
+impairing our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate or other purposes; and 
+• 
+increasing the risk that we may default on our debt obligations. 
+Our Operations Are Subject to Operational Hazards and Unforeseen Interruptions for Which We May Not Be Adequately Insured. 
+There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including: 
+• 
+natural disasters; 
+• 
+adverse weather conditions; 
+• 
+loss of drilling fluid circulation; 
+• 
+blowouts where oil or natural gas flows uncontrolled at a wellhead; 
+• 
+cratering or collapse of the formation; 
+• 
+pipe or cement leaks, failures or casing collapses; 
+• 
+fires or explosions; 
+• 
+releases of hazardous substances or other waste materials that cause environmental damage; 
+• 
+pressures or irregularities in formations; and 
+• 
+equipment failures or accidents. 
+In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices. Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. 
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+Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. Pollution and environmental risks generally are not fully insurable. In addition, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delays in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+We May Have Accidents, Equipment Failures or Mechanical Problems While Drilling or Completing Wells or in Production Activities, Which Could Adversely Affect Our Business. 
+While we are drilling and completing oil or natural gas wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from, or abandonment of, the well, and the costs associated with remedying such accidents could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Because Our Reserves and Production Are Concentrated in a Small Number of Properties, Problems in Production and Markets Relating to Any Property Could Have a Material Impact on Our Business. 
+Almost all of our current oil and natural gas production and our proved reserves are attributable to our properties in South Texas and in Northwest Louisiana and East Texas. For the year ended December 31, 2013 , approximately 70% of our oil and natural gas production, including approximately 98% of our average daily oil production, was attributable to our properties in South Texas. At December 31, 2013 , approximately 82% of the PV-10 of our proved reserves and approximately 93% of our total proved oil reserves were attributable to our properties in South Texas, primarily in the Eagle Ford shale. We expect that most of our operations in the near future will be primarily in South Texas. In addition, we expect to direct approximately 25% of our 2014 capital expenditure budget to further evaluating our acreage position in the Permian Basin in Southeast New Mexico and West Texas. 
+The industry focus on the Eagle Ford shale and the Permian Basin may adversely impact our ability to transport and process our oil and natural gas production due to significant competition for gathering systems, pipelines, processing facilities and oil and condensate trucking operations. For example, infrastructure constraints have in the past required, and may in the future require, us to flare natural gas occasionally, decreasing the volumes sold from our wells. Even though we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, due to the concentration of our operations we may be disproportionately exposed to the impact of delays or interruptions of production from our wells in our operating areas caused by transportation capacity constraints or interruptions, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions or plant closures for scheduled maintenance. 
+Our operations may also be adversely affected by weather conditions and events such as hurricanes, tropical storms and inclement winter weather, resulting in delays in exploration and drilling, damage to facilities and equipment and the inability to receive equipment or access personnel and products at affected job sites in a timely manner. For example, during the fourth quarter of 2013, the Permian Basin experienced severe winter weather that impacted many operators. In particular, the weather conditions and freezing temperatures resulted in power outages, curtailments in trucking, delays in drilling and completion of wells and other production constraints. Although we did not experience any material delays or other issues as a result of inclement weather in this area, as we increase our operations and production in the Permian Basin, we may increasingly face these and other challenges posed by severe weather. 
+Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations and cash flows. 
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+The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows. 
+Shortages or the high cost of drilling rigs, completion equipment and services, personnel or supplies, including sand and other proppants, could delay or adversely affect our operations. When drilling activity in the United States increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies, including sand and other proppants, and personnel and the services and products of other vendors to the industry. These costs may increase, and necessary equipment, supplies and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition, results of operations and cash flows. 
+In addition, the demand for hydraulic fracturing services from time to time exceeds the availability of fracturing equipment and crews across the industry and in certain operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages could further amplify such an equipment and crew shortage. If demand for fracturing services were to increase or the supply of fracturing equipment and crews were to decrease, higher costs could result which could adversely affect our business, financial condition, results of operations and cash flows. 
+If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired. 
+We use a substantial amount of water in our drilling and hydraulic fracturing operations. Our inability to obtain sufficient amounts of water at reasonable prices, or treat and dispose of water after drilling and hydraulic fracturing, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations 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 and production of oil and natural gas. Furthermore, future environmental regulations and permitting requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. 
+Unless We Replace Our Oil and Natural Gas Reserves, Our Reserves and Production Will Decline, Which Would Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The rate of production from our oil and natural gas properties declines as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional oil and natural gas producing properties. We are currently focusing primarily on increasing our production and reserves from the Eagle Ford shale and the Permian Basin, areas in which our competitors have been active. As a result of this activity, we may have difficulty expanding our current production or acquiring new properties in these areas and may experience such difficulty in other areas in the future. During periods of low oil and/or natural gas prices, existing reserves may no longer be economic, and it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our current and future production, our reserves will decrease, and our business, financial condition, results of operations and cash flows would be adversely affected. 
+Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves. 
+The process of estimating accumulations of oil and natural gas is complex and inexact, due to numerous inherent uncertainties. This process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. This process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of: 
+• 
+the quality and quantity of available data; 
+• 
+the interpretation of that data; 
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+• 
+the judgment of the persons preparing the estimate; and 
+• 
+the accuracy of the assumptions used. 
+The accuracy of any estimates of proved reserves generally increases with the length of production history. Due to the limited production history of many of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data becomes available, the estimated proved reserves will be redetermined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors. 
+Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves. 
+The Calculated Present Value of Future Net Revenues from Our Proved Oil and Natural Gas Reserves Will Not Necessarily Be the Same as the Current Market Value of Our Estimated Oil and Natural Gas Reserves. 
+It should not be assumed that the present value of future net cash flows included in this Annual Report on Form 10-K is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as: 
+• 
+actual prices we receive for oil and natural gas; 
+• 
+actual costs and timing of development and production expenditures; 
+• 
+the amount and timing of actual production; and 
+• 
+changes in governmental regulations or taxation. 
+In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under U.S. generally accepted accounting principles, or GAAP, is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general. 
+Approximately 68% of Our Total Proved Reserves at December 31, 2013 Consisted of Undeveloped and Developed Non-Producing Reserves, and Those Reserves May Not Ultimately Be Developed or Produced. 
+At December 31, 2013 , approximately 67% of our total proved reserves were undeveloped and approximately 1% were developed non-producing. Our undeveloped and/or developed non-producing reserves may never be developed or produced or such reserves may not be developed or produced within the time periods we have projected or at the costs we have estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves would reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, resulting in some projects becoming uneconomical and reducing proved reserves. In addition, delays in the development of reserves or declines in the oil and/or natural gas prices used to estimate proved reserves in the future could cause us to have to reclassify a portion of our proved reserves as unproved reserves. Any reduction in our proved reserves caused by the reclassification of undeveloped or developed non-producing reserves could materially affect our business, financial condition, results of operations and cash flows. 
+Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling. 
+Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including assessment of risks, costs, drilling results, oil and natural gas prices, the availability of equipment and capital, approval by regulators and seasonal conditions. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe, or at all, or if we will be able to economically produce hydrocarbons from these or any other potential 
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+drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. 
+Certain of Our Unproved and Unevaluated Acreage Is Subject to Leases That Will Expire over the Next Several Years Unless Production Is Established on Units Containing the Acreage. 
+At December 31, 2013 , we had leasehold interests in approximately 5,800 net acres across all of our areas of interest that are not currently held by production and are subject to leases with primary or renewed terms that expire prior to December 31, 2015 . Unless we establish production, generally in paying quantities, on units containing these leases during their terms or we renew such leases, these leases 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. In addition, on certain portions of our acreage, third party leases may have been taken and could become immediately effective if our leases expire. If our leases expire or we are unable to renew such leases, we will lose our right to develop the related properties. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business, financial condition, results of operations and cash flows. 
+We May Not Increase Our Acreage Positions in Areas with Exposure to Oil, Condensate and Natural Gas Liquids. 
+If we are unable to locate or consummate acquisition opportunities and increase our acreage positions in the Eagle Ford shale in South Texas, the Permian Basin in Southeast New Mexico and West Texas or other areas with similar exposure to oil, condensate and natural gas liquids, we may not realize our growth strategy in oil and liquids-rich plays. The inability to realize our growth strategy and increase our acreage positions in these areas could adversely affect our business, financial condition, results of operations and cash flows. 
+The 2-D and 3-D Seismic Data and Other Advanced Technologies We Use Cannot Eliminate Exploration Risk, Which Could Limit Our Ability to Replace and Grow Our Reserves and Materially and Adversely Affect Our Results of Operations and Cash Flows. 
+We employ visualization and 2-D and 3-D seismic images to assist us in exploration and development activities where applicable. These techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses by drilling unproductive wells based on these technologies. Poor results from our exploration activities could limit our ability to replace and grow reserves and adversely affect our business, financial condition, results of operations and cash flows. 
+We Currently Own Only a Limited Amount of Seismic and Other Geological Data and May Have Difficulty Obtaining Additional Data at a Reasonable Cost, Which Could Adversely Affect Our Results of Operations and Cash Flows. 
+We currently own only a limited amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost, which could negatively affect our business, financial condition, results of operations and cash flows. 
+Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel. 
+Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
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+Our Competitors May Use Superior Technology and Data Resources That We May Be Unable to Afford or That Would Require a Costly Investment by Us in Order to Compete with Them More Effectively. 
+Our industry is subject to rapid and significant advancements in technology, including the introduction of new products, equipment and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will 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 cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected. 
+Strategic Relationships upon Which We May Rely Are Subject to Change, Which May Diminish Our Ability to Conduct Our Operations. 
+Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These relationships are subject to change and, if they do, our ability to grow may be impaired. 
+To develop our business, we will endeavor to use the business relationships of our management, board and special board advisors to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations. 
+The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue. 
+The unavailability of satisfactory oil, natural gas and natural gas liquids gathering, processing and transportation arrangements may hinder our access to oil, natural gas and natural gas liquids markets or delay production from our wells. The availability of a ready market for our oil, natural gas and natural gas liquids production depends on a number of factors, including the demand for, and supply of, oil, natural gas and natural gas liquids and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and oil and condensate trucking operations owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. In addition, certain of these gathering systems, pipelines and processing facilities, particularly in the Permian Basin, may be outdated or in need of repair and subject to higher rates of line loss, failure and breakdown. 
+We may be required to shut in wells for lack of a market or because of inadequate or unavailable pipelines, gathering systems or trucking capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. In addition, if we are unable to market our production we may be required to flare natural gas occasionally, which would decrease the volumes sold from our wells. 
+The disruption of third party facilities due to maintenance, weather or other factors could negatively impact our ability to market and deliver our oil, natural gas and natural gas liquids. The third parties control when or if such facilities are restored and what prices will be charged. In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which has, among other things, required us to flare natural gas occasionally. While we have entered into a firm five-year natural gas processing and transportation agreement covering the anticipated natural gas production from a significant portion of our Eagle Ford shale acreage in South Texas, no assurance can be given that this agreement will alleviate these issues completely, and we may be required to pay deficiency payments under this agreement if we do not meet the thermal quantity transportation and processing commitments under this agreement. We may experience similar interruptions and processing capacity constraints as we continue to explore and develop our Wolfcamp and Bone Spring plays in the Permian Basin in 2014 . If we were required to shut in our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. 
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+Financial Difficulties Encountered by Our Oil and Natural Gas Purchasers, Third Party Operators or Other Third Parties Could Decrease Our Cash Flows from Operations and Adversely Affect the Exploration and Development of Our Prospects and Assets. 
+We derive essentially all of our revenues from the sale of our oil, natural gas and natural gas liquids to unaffiliated third party purchasers, independent marketing companies and midstream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows. 
+Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. If we are not able to obtain the capital necessary to fund either of these contingencies or find a new farmout party, our results of operations and cash flows could be negatively affected. 
+The Third Parties on Whom We Rely for Gathering, Processing and Transportation Services Are Subject to Complex Federal, State and Other Laws that Could Adversely Affect the Cost, Manner or Feasibility of Conducting Our Business. 
+The operations of the third parties on whom we rely for gathering, processing and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Business — Regulation.” 
+We Have Limited Control over Activities on Properties We Do Not Operate. 
+We are not the operator on some of our properties, particularly in the Haynesville shale. As a result of our sale of certain assets to a subsidiary of Chesapeake Energy Corporation in 2008, we do not operate one of our most significant natural gas assets in the Haynesville shale. We also have other non-operated acreage positions in Northwest Louisiana, South Texas, Southeast New Mexico and West Texas. Because we are not the operator for these properties, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs, or control the risks, could materially and adversely affect the drilling results, reserves and future cash flows from these properties. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including: 
+• 
+timing and amount of capital expenditures; 
+• 
+the operator’s expertise and financial resources; 
+• 
+the rate of production of reserves, if any; 
+• 
+approval of other participants in drilling wells; and 
+• 
+selection and implementation or execution of technology. 
+In areas where we do not have the right to propose the drilling of wells, we may have limited influence on when, how and at what pace our properties in those areas are developed. Further, the operators of those properties may experience financial problems in the future or may sell their rights to another operator not of our choosing, both of which could limit our ability to develop and monetize the underlying oil or natural gas reserves. In addition, the operators of these properties may elect to curtail the oil or natural gas production or to shut in the wells on these properties during periods of low oil or natural gas prices, and we may receive less than anticipated or no production and associated revenues from these properties until the operator elects to return them to production. 
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+A Component of Our Growth May Come through Acquisitions, and Our Failure to Identify or Complete Future Acquisitions Successfully Could Reduce Our Earnings and Hamper Our Growth. 
+We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. 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. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations and financial and management information systems and to attract, retain, motivate and effectively manage our employees. 
+In addition, we may be unable to successfully integrate any potential acquisitions into our existing operations. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas. Our financial position, results of operations and cash flows may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted. 
+We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. Our Credit Agreement includes covenants limiting our ability to incur additional debt. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. 
+We May Purchase Oil and Natural Gas Properties with Liabilities or Risks That We Did Not Know About or That We Did Not Assess Correctly, and, as a Result, We Could Be Subject to Liabilities That Could Adversely Affect Our Results of Operations. 
+Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities. 
+We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest. 
+If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired or other title deficiencies, our interest would be worth less than what we paid or may be worthless. In such an instance, all or part of the amount paid for such oil and natural gas lease as well as all or part of any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost. 
+It is not our practice in acquiring oil and natural gas leases, or undivided interests in oil and natural gas leases, to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease in all acquisitions. Rather, in certain acquisitions we rely upon the judgment of oil and natural gas lease brokers and/or landmen who perform the field work in examining records in the appropriate governmental office before attempting to acquire a lease on a specific mineral interest. 
+Prior to the drilling of an oil and natural gas well, however, it is standard industry practice for the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows. 
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+We May Be Required to Write Down the Carrying Value of Our Proved Properties under Accounting Rules and These Write-Downs Could Adversely Affect Our Financial Condition. 
+There is a risk that we will be required to write down the carrying value of our oil and natural gas properties when oil or natural gas prices are low. In addition, non-cash write-downs may occur if we have: 
+• 
+downward adjustments to our estimated proved reserves; 
+• 
+increases in our estimates of development costs; or 
+• 
+deterioration in our exploration and development results. 
+We periodically review the carrying value of our oil and natural gas properties under full-cost accounting rules. Under these rules, the net capitalized costs of oil and natural gas properties less related deferred income taxes may not exceed a cost center ceiling that is based on the present value, based on constant prices and costs projected forward from a single point in time, of estimated future after-tax net cash flows from proved reserves, discounted at 10%. If the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceed the cost center ceiling, we must charge the amount of this excess to operations in the period in which the excess occurs. We may not reverse write-downs even if prices increase in subsequent periods. A write-down does not affect net cash flows from operating activities, but it does reduce the book value of our net tangible assets, retained earnings and shareholders’ equity and could lower the value of our common stock. 
+Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses. 
+To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, using primarily “costless collars” or “swaps” with respect to a portion of our future production. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over the specified period, providing downside price protection. The goal of these and other hedges is to lock in a range of prices in the case of collars or a fixed price in the case of swaps so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil, natural gas or natural gas liquids prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged. 
+In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option or swap contracts fail to perform under the contracts. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. 
+Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful. 
+An Increase in the Differential between the NYMEX or Other Benchmark Prices of Oil and Natural Gas and the Wellhead Price We Receive for Our Production Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark prices and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead prices we receive could adversely affect our business, financial condition, results of operations and cash flows. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials. 
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+We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures. 
+The exploration, development, production and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation and environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for: 
+• 
+personal injuries; 
+• 
+property damage; 
+• 
+containment and clean-up of oil and other spills; 
+• 
+management and disposal of hazardous materials; 
+• 
+remediation, clean-up costs and natural resource damages; and 
+• 
+other environmental damages. 
+We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations. 
+We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows. 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. 
+Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for certain 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 or manufacturing activities and (iv) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the United States. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our financial condition, results of operations and cash flows. 
+Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays. 
+In past sessions, Congress has considered, but did not pass, legislation to amend the Safe Drinking Water Act, or SDWA, to remove the SDWA’s exemption granted to most hydraulic fracturing operations (other than operations using fluids containing 
+42 
+Table of Contents 
+diesel) and to require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. The EPA recently issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate oil and natural gas production. We routinely use hydraulic fracturing to produce oil, natural gas and natural gas liquids from formations such as the Eagle Ford shale, the Wolfcamp and Bone Spring plays and the Haynesville shale, where we focus our operations. The EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. A progress report was released in December 2012, with draft final results expected in 2014. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action towards federal legislation and regulation of hydraulic fracturing or similar production operations. Also at the federal level, the BLM has proposed rules to regulate hydraulic fracturing on federal lands. Additionally, the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. 
+In addition, a number of states and local regulatory authorities are considering or have implemented more stringent regulatory requirements applicable to hydraulic fracturing, which could include a moratorium on drilling and effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. Texas and Wyoming have adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process. This legislation and any implementing regulations could increase our costs of compliance and doing business. 
+The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in unconventional plays. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, hydraulic fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations. 
+Legislation or Regulations Restricting Emissions of Greenhouse Gases Could Result in Increased Operating Costs and Reduced Demand for the Oil, Natural Gas and Natural Gas Liquids We Produce while the Physical Effects of Climate Change Could Disrupt Our Production and Cause Us to Incur Significant Costs in Preparing for or Responding to Those Effects. 
+The EPA has published its final findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, the EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published 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. On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. Monitoring of those newly covered emissions commenced on January 1, 2011, with the first annual reports filed in 2012. 
+In an interpretative guidance on climate change disclosures, the SEC indicated that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland and water availability and quality. If such effects were to occur, there is the potential for our exploration and production operations to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. See “—If We Are Unable to Acquire Adequate Supplies of Water for Our Drilling and Hydraulic Fracturing Operations or Are Unable to Dispose of the Water We Use at a Reasonable Cost and Pursuant to Applicable Environmental Rules, Our Ability to Produce Oil and Natural Gas Commercially and in Commercial Quantities Could Be Impaired.” Should climate change or other drought conditions occur, our ability to obtain water of a sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. 
+43 
+Table of Contents 
+New Regulations on All Emissions from Our Operations Could Cause Us to Incur Significant Costs. 
+On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. We continue to evaluate the effect these rules have on our business and operations, which are not anticipated to be materially impacted. 
+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. There were attempts at comprehensive federal legislation establishing a cap and trade program, but that legislation did not pass. Further, various states have considered or adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the oil, natural gas and natural gas liquids that we produce. 
+A Change in the Jurisdictional Characterization of Some of Our Assets by FERC or a Change in Policy by It 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 NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services 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. A change in the jurisdictional characterization by FERC, the courts or Congress or a change in policy by FERC or Congress may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. 
+Should We Fail to Comply with All Applicable FERC-Administered Statutes, Rules, Regulations and Orders, We Could Be Subject to Substantial Penalties and Fines. 
+Under the Energy Policy Act, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. The nature of our gathering facilities is such that we have not yet been regulated by FERC as a natural gas company subject to the provisions of the NGA. It is possible, however, that laws, rules and regulations pertaining to those and other matters may be considered or adopted by FERC or Congress from time to time. Failure to comply with those laws, rules and regulations in the future could subject us to civil penalty liability. 
+The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business. 
+On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products, including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished. 
+In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act could also result in additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. 
+44 
+Table of Contents 
+In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. 
+As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining such commodity hedges and the terms thereof. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. 
+If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our cash flows, which could adversely affect our ability to make capital expenditures. 
+Finally, the Dodd-Frank Act 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 Dodd-Frank Act and implementing regulations is to lower commodity prices. 
+Any of these consequences could have a material adverse effect on our business, financial condition and results of operations. 
+We May Have Difficulty Managing Growth in Our Business, Which Could Have a Material Adverse Effect on Our Business, Financial Condition, Results of Operations and Cash Flows and Our Ability to Execute Our Business Plan in a Timely Fashion. 
+Because of our size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers, landmen, attorneys and financial and accounting professionals, could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to execute our business plan in a timely fashion. 
+Our Success Depends, to a Large Extent, on Our Ability to Retain Our Key Personnel, Including Our Chairman of the Board and Chief Executive Officer, Management and Technical Team, the Members of Our Board of Directors and Our Special Board Advisors, and the Loss of Any Key Personnel, Board Member or Special Board Advisor Could Disrupt Our Business Operations. 
+Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman and Chief Executive Officer, Joseph Wm. Foran. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. We have entered into employment agreements with Mr. Foran and other key personnel. However, these employment agreements do not ensure that these individuals will remain in our employment. If Mr. Foran or other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. With the exception of Mr. Foran, we do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. 
+We have an active Board of Directors that meets at least quarterly throughout the year and is closely involved in our business and the determination of our operational strategies. Members of our Board of Directors work closely with management to identify potential prospects, acquisitions and areas for further development. Certain of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and, as a result, our operations may be adversely affected. 
+In addition, our board consults regularly with our special advisors regarding our business and the evaluation, exploration, engineering and development of our prospects. Due to the knowledge and experience of our special advisors, they play a key role in our multi-disciplined approach to making decisions regarding prospects, acquisitions and development. If any of our special advisors resign or become unable to continue in their present role, our operations may be adversely affected. 
+45 
+Table of Contents 
+Risks Relating to Our Common Stock 
+The Price of Our Common Stock Has Fluctuated Substantially and May Fluctuate Substantially in the Future. 
+Our stock price has experienced volatility and could vary significantly as a result of a number of factors. In 2013 , our stock price fluctuated between a high of $24.10 and a low of $7.58. In the future, the trading volume of our common stock may continue to fluctuate and cause significant price variations to occur. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. 
+Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include: 
+• 
+our actual or anticipated operating and financial performance and drilling locations, including oil and natural gas reserves estimates; 
+• 
+quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us; 
+• 
+changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts; 
+• 
+speculation in the press or investment community; 
+• 
+public reaction to our press releases, announcements and filings with the SEC; 
+• 
+sales of our common stock by us or shareholders, or the perception that such sales may occur; 
+• 
+general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices; 
+• 
+the realization of any of the risk factors presented in this Annual Report on Form 10-K; 
+• 
+the recruitment or departure of key personnel; 
+• 
+commencement of or involvement in litigation; 
+• 
+the prices of oil, natural gas and natural gas liquids; 
+• 
+the success of our exploration and development operations, and the marketing of any oil, natural gas and natural gas liquids we produce; 
+• 
+changes in market valuations of companies similar to ours; and 
+• 
+domestic and international economic, legal and regulatory factors unrelated to our performance. 
+The Requirements of Being a Public Company, Including Compliance with the Reporting Requirements of the Securities Exchange Act of 1934, as Amended, and the Requirements of the Sarbanes-Oxley Act of 2002, Have Increased Our Costs and Occupy a Significant Amount of Management’s Time. 
+As a public company with listed equity securities, we are required to comply with laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE. Complying with these statutes, regulations and requirements is difficult and occupies a significant amount of time of our Board of Directors and management and has significantly increased our costs and expenses. 
+If We Fail to Maintain Effective Internal Control over Financial Reporting in the Future, Our Ability to Accurately Report Our Financial Results Could Be Adversely Affected. 
+Until February 2012, we were a private company and maintained internal controls and procedures in accordance with being a private company. We maintained limited accounting personnel to perform our accounting processes and limited supervisory resources with which to address our internal control over financial reporting. In connection with our audits for the years ended December 31, 2011 and 2010, our independent registered public accountants identified and communicated material weaknesses. There were no material weaknesses identified in connection with our audits for the years ended December 31, 2013 and 2012. 
+A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual and interim financial statements will not be prevented or detected and corrected on a timely basis. 
+46 
+Table of Contents 
+Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Further, our remediation efforts may not enable us to avoid material weaknesses in the future. Any failure to maintain effective controls could result in material misstatements that are not prevented or detected and corrected on a timely basis, which could potentially subject us to sanction or investigation by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information and adversely affect our business and our stock price. 
+We Do Not Presently Intend to Pay Any Cash Dividends on or Repurchase Any Shares of Our Common Stock. 
+We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. In addition, certain covenants in our Credit Agreement may limit our ability to pay dividends or repurchase shares of our common stock. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment, and there is no guarantee that the price of our common stock will exceed the price you paid. 
+The Trading Volume of Our Common Stock Has Been Low, and the Sale of a Substantial Number of Shares in the Public Market Could Depress the Price of Our Common Stock. 
+Our common stock is listed on the NYSE and has had a lower average daily trading volume relative to many other stocks. Thinly traded stock can be more volatile than stock trading in an active public market, which can lead to significant price swings even when a relatively small number of shares are being traded and can limit an investor’s ability to quickly sell blocks of stock. 
+Future Sales of Shares of Our Common Stock by Existing Shareholders and Future Offerings of Our Common Stock by Us Could Depress the Price of Our Common Stock. 
+The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, and the perception that these sales could occur may also depress the market price of our common stock. If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales could also cause our stock price to decrease and make it more difficult for you to sell shares of our common stock. 
+We may also sell additional shares of common stock, such as in our September 2013 equity offering, or securities convertible into common stock. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities would have on the market price of our common stock. 
+Provisions of Our Certificate of Formation, Bylaws and Texas Law May Have Anti-Takeover Effects That Could Prevent a Change in Control Even if It Might Be Beneficial to Our Shareholders. 
+Our certificate of formation and bylaws contain certain provisions that may discourage, delay or prevent a merger or acquisition that our shareholders may consider favorable. These provisions include: 
+• 
+authorization for our Board of Directors to issue preferred stock without shareholder approval; 
+• 
+a classified Board of Directors so that not all members of our Board of Directors are elected at one time; 
+• 
+the prohibition of cumulative voting in the election of directors; and 
+• 
+a limitation on the ability of shareholders to call special meetings to those owning at least 25% of our outstanding shares of common stock. 
+Provisions of Texas law may also discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or an affiliated shareholder, cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our Board of Directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. 
+47 
+Table of Contents 
+Our Directors and Executive Officers Own Approximately 10% of Our Common Stock, Which Could Give Them Influence in Corporate Transactions and Other Matters, and the Interests of Our Directors and Executive Officers Could Differ from Other Shareholders. 
+Our directors and executive officers beneficially own approximately 10% of our outstanding common stock. These shareholders could influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. Their influence or control of the Company may have the effect of delaying or preventing a change of control of the Company and may adversely affect the voting and other rights of other shareholders. In addition, due to their ownership interest in our common stock, our directors and executive officers may be able to remain entrenched in their positions. 
+Our Board of Directors Can Authorize the Issuance of Preferred Stock, Which Could Diminish the Rights of Holders of Our Common Stock and Make a Change of Control of the Company More Difficult Even if It Might Benefit Our Shareholders. 
+Our Board of Directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of the company, even if that change of control might benefit our shareholders. 
+Item 1B. Unresolved Staff Comments. 
+Not applicable. 
+Item 2. Properties. 
+See “Business” for descriptions of our properties. We also have various operating leases for rental of office space and office and field equipment. See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K for the future minimum rental payments. Such information is incorporated herein by reference. 
+Item 3. Legal Proceedings. 
+See “Note 13 – Commitments and Contingencies” to the consolidated financial statements in this Annual Report on Form 10-K. Such information is incorporated herein by reference. 
+Item 4. Mine Safety Disclosures. 
+Not applicable. 
+48 
+Table of Contents 
+PART II 
+Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. 
+General Market Information 
+Shares of our common stock are traded on the NYSE under the symbol “MTDR.” Our shares have been traded on the NYSE since February 2, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+On March 13, 2014 , we had 65,744,878 shares of common stock outstanding held by approximately 350 record holders, excluding shareholders for whom shares are held in “nominee” or “street” name. 
+The following table sets forth the high and low sales prices of our common stock as reported by the NYSE for the periods indicated: 
+2013 
+2012 
+High 
+Low 
+High 
+Low 
+First Quarter 
+$ 
+9.00 
+$ 
+7.58 
+$ 
+12.33 
+$ 
+10.85 
+Second Quarter 
+$ 
+12.48 
+$ 
+8.25 
+$ 
+12.09 
+$ 
+8.63 
+Third Quarter 
+$ 
+17.89 
+$ 
+11.49 
+$ 
+11.53 
+$ 
+9.41 
+Fourth Quarter 
+$ 
+24.10 
+$ 
+15.62 
+$ 
+10.50 
+$ 
+7.70 
+On March 13, 2014 , the last reported sales price of our common stock on the NYSE was $22.06 per share. 
+Dividend Policy 
+We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Our future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, certain covenants in our Credit Agreement may limit our ability to pay dividends on our common stock. 
+Prior to the consummation of our initial public offering on February 7, 2012, the holders of our Class B common stock were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends accrued and were payable quarterly at the rate of $0.06-2/3 per share of Class B common stock outstanding. Upon the automatic conversion of the outstanding shares of Class B common stock at the closing of our initial public offering, the right of the holders of Class B common stock to dividends was terminated and such holders were paid approximately $28,000 during the first quarter of 2012 for all accrued but unpaid dividends existing at the time of such conversion. 
+Equity Compensation Plan Information 
+The following table presents the securities authorized for issuance under our equity compensation plans as of December 31, 2013 . 
+Equity Compensation Plan Information 
+Plan Category 
+Number of Shares to be Issued Upon Exercise of Outstanding Options, Warrants and Rights 
+Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights 
+Number of Shares Remaining Available for Future Issuance Under Equity Compensation Plans 
+Equity compensation plans approved by security holders (1) (2) 
+1,613,695 
+$ 
+9.32 
+1,778,715 
+Equity compensation plans not approved by security holders 
+— 
+— 
+— 
+Total 
+1,613,695 
+$ 
+9.32 
+1,778,715 
+__________________ 
+(1) 
+Our Board of Directors has determined not to make any additional grants of awards under the Matador Resources Company 2003 Stock and Incentive Plan. 
+(2) 
+Our 2012 Long-Term Incentive Plan was approved by our Board of Directors in December 2011 and took effect on January 1, 2012. The 2012 Long-Term Incentive Plan was also approved by our shareholders at the Annual Meeting of Shareholders on June 7, 2012. For a description of our 2012 Long-Term Incentive Plan, see “ Note 8 – Stock-Based Compensation ” to the consolidated financial statements in this Annual Report on Form 10-K. 
+49 
+Table of Contents 
+Share Performance Graph 
+The following graph compares the cumulative return on a $100 investment in our common stock from February 2, 2012, the date our common stock began trading on the NYSE, through December 31, 2013 , to that of the cumulative return on a $100 investment in the Russell 2000 Index and the Russell 2000 Energy Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance. 
+Comparison of Cumulative Total Return Among 
+Matador Resources Company, the Russell 2000 Index 
+and the Russell 2000 Energy Index 
+Repurchase of Equity by the Company or Affiliates 
+None. 
+50 
+Table of Contents 
+Item 6. Selected Financial Data. 
+You should read the following selected financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this Annual Report on Form 10-K. The financial information included in this Annual Report on Form 10-K may not be indicative of our future results of operations, financial position or cash flows. 
+The following selected financial information is summarized from our results of operations for the five-year period ended December 31, 2013 and selected consolidated balance sheet data at December 31, 2013, 2012, 2011, 2010 and 2009 and should be read in conjunction with the consolidated financial statements for the years ended December 31, 2013, 2012 and 2011 included herewith. 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+(In thousands, except per share data) 
+Statement of operations data: 
+Revenues: 
+Oil and natural gas revenues 
+$ 
+269,030 
+$ 
+155,998 
+$ 
+67,000 
+$ 
+34,042 
+$ 
+19,039 
+Realized (loss) gain on derivatives 
+(909 
+) 
+13,960 
+7,106 
+5,299 
+7,625 
+Unrealized (loss) gain on derivatives 
+(7,232 
+) 
+(4,802 
+) 
+5,138 
+3,139 
+(2,375 
+) 
+Total revenues 
+260,889 
+165,156 
+79,244 
+42,480 
+24,289 
+Expenses: 
+Production taxes and marketing 
+20,973 
+11,672 
+6,278 
+1,982 
+1,077 
+Lease operating 
+38,720 
+28,184 
+7,244 
+5,284 
+4,725 
+Depletion, depreciation and amortization 
+98,395 
+80,454 
+31,754 
+15,596 
+10,743 
+Accretion of asset retirement obligations 
+348 
+256 
+209 
+155 
+137 
+Full-cost ceiling impairment 
+21,229 
+63,475 
+35,673 
+— 
+25,244 
+General and administrative 
+20,779 
+14,543 
+13,394 
+9,702 
+7,115 
+Total expenses 
+200,444 
+198,584 
+94,552 
+32,719 
+49,041 
+Operating income (loss) 
+60,445 
+(33,428 
+) 
+(15,308 
+) 
+9,761 
+(24,752 
+) 
+Other income (expense): 
+Net loss on asset sales and inventory impairment 
+(192 
+) 
+(485 
+) 
+(154 
+) 
+(224 
+) 
+(379 
+) 
+Interest expense 
+(5,687 
+) 
+(1,002 
+) 
+(683 
+) 
+(3 
+) 
+— 
+Interest and other income 
+225 
+224 
+315 
+364 
+781 
+Total other (expense) income 
+(5,654 
+) 
+(1,263 
+) 
+(522 
+) 
+137 
+402 
+Net income (loss) 
+$ 
+45,094 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Class B 
+$ 
+— 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+Diluted 
+Class A 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+$ 
+0.15 
+$ 
+(0.37 
+) 
+Class B 
+$ 
+— 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+$ 
+0.42 
+$ 
+(0.10 
+) 
+Class B dividend declared, per share 
+$ 
+— 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+$ 
+0.27 
+51 
+Table of Contents 
+At December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+(In thousands) 
+Balance sheet data: 
+Cash and cash equivalents 
+$ 
+6,287 
+$ 
+2,095 
+$ 
+10,284 
+$ 
+21,060 
+$ 
+104,230 
+Certificates of deposit 
+— 
+230 
+1,335 
+2,349 
+15,675 
+Net property and equipment 
+845,877 
+591,090 
+399,865 
+303,880 
+142,078 
+Total assets 
+890,330 
+632,029 
+439,469 
+346,382 
+277,400 
+Current liabilities 
+100,327 
+96,492 
+74,576 
+30,097 
+8,868 
+Long-term liabilities 
+221,079 
+156,433 
+93,378 
+34,408 
+4,211 
+Total shareholders’ equity 
+$ 
+568,924 
+$ 
+379,104 
+$ 
+271,515 
+$ 
+281,877 
+$ 
+264,321 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+(In thousands) 
+Other financial data: 
+Net cash provided by operating activities 
+$ 
+179,470 
+$ 
+124,228 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+Net cash used in investing activities 
+(366,939 
+) 
+(306,916 
+) 
+(160,088 
+) 
+(147,334 
+) 
+(49,415 
+) 
+Oil and natural gas properties capital expenditures 
+(363,192 
+) 
+(300,689 
+) 
+(156,431 
+) 
+(159,050 
+) 
+(54,244 
+) 
+Expenditures for other property and equipment 
+(3,977 
+) 
+(7,332 
+) 
+(4,671 
+) 
+(1,610 
+) 
+(307 
+) 
+Net cash provided by financing activities 
+191,661 
+174,499 
+87,444 
+36,891 
+1,086 
+Adjusted EBITDA (1) 
+$ 
+191,771 
+$ 
+115,923 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+__________________ 
+(1) 
+Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “ – Non-GAAP Financial Measures” below. 
+Non-GAAP Financial Measures 
+We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. 
+Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA, because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which certain assets were acquired. 
+Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively. 
+52 
+Table of Contents 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+(In thousands) 
+Unaudited Adjusted EBITDA Reconciliation to Net Income (Loss): 
+Net income (loss) 
+$ 
+45,094 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+$ 
+6,377 
+$ 
+(14,425 
+) 
+Interest expense 
+5,687 
+1,002 
+683 
+3 
+— 
+Total income tax provision (benefit) 
+9,697 
+(1,430 
+) 
+(5,521 
+) 
+3,521 
+(9,925 
+) 
+Depletion, depreciation and amortization 
+98,395 
+80,454 
+31,754 
+15,596 
+10,743 
+Accretion of asset retirement obligations 
+348 
+256 
+209 
+155 
+137 
+Full-cost ceiling impairment 
+21,229 
+63,475 
+35,673 
+— 
+25,244 
+Unrealized loss (gain) on derivatives 
+7,232 
+4,802 
+(5,138 
+) 
+(3,139 
+) 
+2,375 
+Stock-based compensation expense 
+3,897 
+140 
+2,406 
+898 
+656 
+Net loss on asset sales and inventory impairment 
+192 
+485 
+154 
+224 
+379 
+Adjusted EBITDA 
+$ 
+191,771 
+$ 
+115,923 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+2010 
+2009 
+(In thousands) 
+Unaudited Adjusted EBITDA Reconciliation to Net Cash Provided by 
+Operating Activities: 
+Net cash provided by operating activities 
+$ 
+179,470 
+$ 
+124,228 
+$ 
+61,868 
+$ 
+27,273 
+$ 
+1,791 
+Net change in operating assets and liabilities 
+6,210 
+(9,307 
+) 
+(12,594 
+) 
+(2,230 
+) 
+15,717 
+Interest expense 
+5,687 
+1,002 
+683 
+3 
+— 
+Current income tax provision (benefit) 
+404 
+— 
+(46 
+) 
+(1,411 
+) 
+(2,324 
+) 
+Adjusted EBITDA 
+$ 
+191,771 
+$ 
+115,923 
+$ 
+49,911 
+$ 
+23,635 
+$ 
+15,184 
+Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 
+The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in oil or natural gas prices, the timing of planned capital expenditures, availability under our Credit Agreement borrowing base, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of gathering, processing and transportation facilities, availability of acquisitions, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Note Regarding Forward-Looking Statements.” 
+Overview 
+We are an independent energy company founded in July 2003 and engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, we have a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where we are testing the Meade Peak shale. 
+On February 2, 2012, our common stock began trading on the NYSE under the symbol “MTDR.” On February 7, 2012, we completed our initial public offering of 14,883,334 shares of common stock at $12.00 per share (the “Initial Public Offering”). We sold 12,209,167 shares of common stock in this offering and certain selling shareholders sold 2,674,167 shares of common stock, including shares sold pursuant to the partial exercise of the underwriters’ over-allotment option on March 7, 2012. Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+53 
+Table of Contents 
+On September 10, 2013 , we completed an underwritten public offering of 9,775,000 shares of our common stock, including 1,275,000 shares issued pursuant to the underwriters’ exercise of their option to purchase additional shares. After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million , we received net proceeds of approximately $141.7 million . We are using the net proceeds from this offering primarily to fund a portion of our capital expenditures, including for the addition of the third rig to our drilling program. We are also using the net proceeds from this offering to fund the acquisition of additional acreage in the Eagle Ford shale, the Permian Basin and the Haynesville shale and for other general working capital needs. Pending such uses, we used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under our Credit Agreement in September 2013, which amounts may be reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. 
+Our business success and financial results are dependent on many factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Commodity price volatility, in particular, is a significant risk factor for us. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, oil and natural gas price differentials and other factors. Prices for oil, natural gas and natural gas liquids will affect the cash flows available to us for capital expenditures and our ability to borrow and raise additional capital. Declines in oil, natural gas or natural gas liquids prices would not only reduce our revenues, but could also reduce the amount of oil, natural gas and/or natural gas liquids that we can produce economically, and as a result, could have an adverse effect on our financial condition, results of operations, cash flows and reserves. 
+In 2013 , almost all of our operated drilling activities and approximately 70% of our total capital expenditures of $373.5 million were directed to our operations in South Texas, primarily in the Eagle Ford shale, as we continued to increase our oil production and oil reserves. We also increased our leasehold position significantly in the Permian Basin in Southeast New Mexico and West Texas during 2013. At December 31, 2013, we held approximately 70,800 gross ( 44,800 net) acres in the Permian Basin, as compared to approximately 15,900 gross (7,600 net) acres at December 31, 2012. We also initiated our exploratory drilling activities in the Permian Basin during 2013 to begin the evaluation and delineation of our acreage position. Approximately 27% of our 2013 capital expenditures were directed to our three-well exploration program testing portions of our leasehold position in the Permian Basin and to the acquisition of additional interests prospective for the Wolfcamp, Bone Spring and other oil and liquids-rich plays in the Permian Basin. For the year ended December 31, 2013 , approximately 50% of our total production by volume (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) and almost 80% of our total oil and natural gas revenues were attributable to oil production, primarily in the Eagle Ford shale. 
+During the first quarter of 2013, we had two contracted drilling rigs operating full-time in South Texas and all of our operated drilling and completion activities were focused on the Eagle Ford shale. In late April 2013, we moved one of these contracted drilling rigs to Southeast New Mexico to begin a three-well exploration program testing portions of our leasehold acreage in the Permian Basin, while the second contracted drilling rig continued to operate in the Eagle Ford shale. In mid-August 2013, we added a third contracted drilling rig to our drilling program and returned to operating two contracted drilling rigs in the Eagle Ford shale. We expect to operate two contracted drilling rigs in the Eagle Ford shale and one rig in the Permian Basin throughout 2014. At March 13, 2014 , our two Eagle Ford rigs were operating in La Salle and Wilson Counties, Texas, respectively, and our Permian Basin rig was operating in Lea County, New Mexico. 
+During the year ended December 31, 2013 , we completed and began producing oil and natural gas from 25 gross (25.0 net) operated and seven gross (2.6 net) non-operated Eagle Ford shale wells. We also participated in 11 gross (0.4 net) non-operated Haynesville shale wells in Northwest Louisiana and one non-operated test of the Buda formation in South Texas (approximately 21% working interest). During 2013, we also initiated an exploration program testing portions of our growing leasehold position in the Permian Basin. We drilled three wells on this acreage in 2013, including one vertical data well, where we collected extensive well log and whole core data, and one horizontal well testing the Second Bone Spring formation, both in Lea County, New Mexico. We began producing oil and natural gas from the Second Bone Spring horizontal well in late October 2013. We also drilled a horizontal well testing the Wolfcamp “A” formation in Loving County, Texas. This well was completed and began producing oil and natural gas in January 2014. 
+Our average daily oil equivalent production for the year ended December 31, 2013 was the best in Matador's history at 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, an increase of 30% as compared to 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, for the year ended December 31, 2012 . Our average daily oil production of 5,843 Bbl of oil per day was an increase of 76% , as compared to an average daily oil production of 3,317 Bbl of oil per day during the year ended December 31, 2012 . This increase in oil production was a direct result of our drilling operations in the Eagle Ford shale. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2013 , as compared to 37% for the year ended December 31, 2012 and only 6% for the year ended December 31, 2011 . 
+54 
+Table of Contents 
+Our oil and natural gas revenues and Adjusted EBITDA for the year ended December 31, 2013 were also the highest achieved for any year in our history. For the year ended December 31, 2013 , our oil and natural gas revenues were $269.0 million , an increase of 72% from oil and natural gas revenues of $156.0 million for the year ended December 31, 2012 . Our oil revenues and natural gas revenues increased 72% and 74% to approximately $212.8 million and $56.2 million , respectively, for the year ended December 31, 2013 , as compared to $123.7 million and $32.3 million , respectively, for the year ended December 31, 2012 . Adjusted EBITDA for the year ended December 31, 2013 was $191.8 million , an increase of 65% from an Adjusted EBITDA of $115.9 million reported for the year ended December 31, 2012 . Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” 
+At December 31, 2013 , our estimated total proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, with a PV-10 of $655.2 million and a Standardized Measure of $578.7 million . At December 31, 2012 , our estimated proved oil and natural gas reserves were 23.8 million BOE, including 10.5 million Bbl of oil and 80.0 Bcf of natural gas, with a PV-10 of $423.2 million and a Standardized Measure of $394.6 million . Our estimated proved oil reserves of 16.4 million Bbl at December 31, 2013 increased 56% , as compared to 10.5 million Bbl at December 31, 2012 . These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “Business — Estimated Proved Reserves.” 
+The unweighted arithmetic average of the first-day-of-the-month natural gas price used to estimate natural gas reserves at December 31, 2013 increased to $3.670 per MMBtu, as compared to $2.757 per MMBtu for 2012 . Primarily as a result of continued improvement in natural gas prices over the past year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013 . We had removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves from our estimated total proved reserves at June 30, 2012 because the natural gas price used to estimate natural gas reserves at June 30, 2012 had declined to $3.146 per MMBtu, a price at which the natural gas volumes associated with almost all of our identified Haynesville shale well locations could no longer be classified as proved undeveloped reserves. 
+As we continue to explore and develop our leasehold positions in the Eagle Ford shale and as we continue to explore and develop our leasehold positions in the Wolfcamp and Bone Spring plays in the Permian Basin, we may face various challenges in establishing operations in new areas, including securing the necessary services to drill and complete wells and securing the necessary facilities to gather, process, transport and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during the years ended December 31, 2013 or December 31, 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and reducing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play, as well as the Wolfcamp and Bone Spring plays in the Permian Basin. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which have, among other things, required us to flare natural gas occasionally. To alleviate a portion of such interruptions and processing capacity constraints, effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in or flare our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may experience similar interruptions and processing 
+55 
+Table of Contents 
+capacity constraints as we explore and develop our leasehold position in the Permian Basin in 2014 , although we experienced no material issues in 2013 . See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+About one-third of our acreage in the core area of the Haynesville shale play in Northwest Louisiana is operated by a subsidiary of Chesapeake Energy Corporation. During the fourth quarter of 2013, we notified Chesapeake that we would be electing to take in kind the anticipated natural gas production from most of the wells operated by Chesapeake effective January 1, 2014. In addition, in December 2013, we entered into a five-year natural gas gathering agreement effective January 1, 2014 for this anticipated natural gas production. This agreement has no firm transportation commitments and no natural gas volume commitments. We believe that taking our natural gas production in kind and transporting through this gathering agreement will improve our natural gas price realizations and reduce marketing and transportation fees and other costs associated with this natural gas production by an average of approximately $0.70 or more per MMBtu. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Our estimated capital expenditure budget for 2014 is $440 million , and 97% is expected to be directed towards oil and liquids-rich opportunities. Development of our Eagle Ford shale assets will continue to be the primary driver of our growth in 2014 and approximately $318 million , or 72% , of our estimated 2014 capital expenditures will be directed to increasing our oil production and oil reserves in South Texas. Approximately $109 million , or 25% , of our 2014 estimated capital expenditures will be allocated to further exploration of our growing leasehold position in the Permian Basin. The objective of our Permian Basin drilling program in 2014 is to further evaluate and delineate our acreage, both geographically and geologically, in order to better define an expanded development plan for this acreage in 2015 and beyond. Although we do not plan to drill any operated Haynesville shale natural gas wells during 2014 , approximately $12 million , or 3% , of our 2014 estimated capital expenditures will be allocated to participation in non-operated Haynesville shale wells in Northwest Louisiana. We believe that we should be able to fund our 2014 drilling program through operating cash flows and borrowings under our Credit Agreement. We anticipate that our borrowing capacity will continue to increase during 2014 as a result of the addition of proved reserves resulting from our drilling activities, particularly in the Eagle Ford shale and the Permian Basin. While we have budgeted approximately $440 million for 2014, the aggregate amount of capital we expend may fluctuate materially based on market conditions, the actual costs to drill scheduled wells, wells drilled on properties we do not operate, our drilling results, other opportunities that may become available to us and our ability to obtain capital. 
+56 
+Table of Contents 
+Revenues 
+Our revenues are derived primarily from the sale of oil, natural gas and natural gas liquids production. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in oil, natural gas or natural gas liquids prices. 
+The following table summarizes our revenues and production data for the periods indicated: 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Operating Data: 
+Revenues (in thousands): (1) 
+Oil 
+$ 
+212,833 
+$ 
+123,654 
+$ 
+14,457 
+Natural gas 
+56,197 
+32,344 
+52,543 
+Total oil and natural gas revenues 
+269,030 
+155,998 
+67,000 
+Realized (loss) gain on derivatives 
+(909 
+) 
+13,960 
+7,106 
+Unrealized (loss) gain on derivatives 
+(7,232 
+) 
+(4,802 
+) 
+5,138 
+Total revenues 
+$ 
+260,889 
+$ 
+165,156 
+$ 
+79,244 
+Net Production Volumes: (1) 
+Oil (MBbl) 
+2,133 
+1,214 
+154 
+Natural gas (Bcf) 
+12.9 
+12.5 
+14.5 
+Total oil equivalent (MBOE) (2) 
+4,285 
+3,294 
+2,573 
+Average daily production (BOE/d) (2) 
+11,740 
+9,000 
+7,049 
+Average Sales Prices: 
+Oil, with realized derivatives (per Bbl) 
+$ 
+98.67 
+$ 
+103.55 
+$ 
+93.80 
+Oil, without realized derivatives (per Bbl) 
+$ 
+99.79 
+$ 
+101.86 
+$ 
+93.80 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+4.47 
+$ 
+3.55 
+$ 
+4.11 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+4.35 
+$ 
+2.59 
+$ 
+3.62 
+________________ 
+(1) 
+We report our production volumes in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Revenues associated with natural gas liquids are included with our natural gas revenues. 
+(2) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+Year Ended December 31, 2013 as Compared to Year Ended December 31, 2012 
+Oil and natural gas revenues . Our oil and natural gas revenues increased $113.0 million to $269.0 million , or an increase of 72% for the year ended December 31, 2013 , as compared to $156.0 million for the year ended December 31, 2012 . This increase in oil and natural gas revenues corresponds with an increase of 30% in our oil and natural gas production to 4.3 million BOE for the year ended December 31, 2013 from 3.3 million BOE for the year ended December 31, 2012 . Our oil revenues increased $89.2 million , an increase of 72% , to $212.8 million for the year ended December 31, 2013 , as compared to $123.7 million for the year ended December 31, 2012 . Our oil production increased 76% to over 2.1 million Bbl of oil, or about 5,843 Bbl of oil per day, as compared to approximately 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, for the year ended December 31, 2013 due to our drilling operations in the Eagle Ford shale. The increase in our oil revenues in 2013 was mostly attributable to the increase in oil production, but was partially offset by a slightly lower oil price of $99.79 per Bbl realized for the year ended December 31, 2013 , as compared to $101.86 per Bbl realized for the year ended December 31, 2012 . Our natural gas revenues increased $23.9 million , an increase of 74% , to $56.2 million for the year ended December 31, 2013 , as compared to $32.3 million for the year ended December 31, 2012 , due to higher prices and increased production. The vast majority of the increase in natural gas revenues, or $22.7 million , resulted from a significantly higher weighted average natural gas price of $4.35 per Mcf realized during the year ended December 31, 2013 , as compared to a weighted average natural gas price of $2.59 per Mcf realized during the year ended December 31, 2012 . The 3% increase in our natural gas production to approximately 12.9 Bcf for the year ended December 31, 2013 , as compared to approximately 12.5 Bcf for the year ended December 31, 2012 , resulted in an increase in natural gas revenues of $1.1 million during 2013, as compared to 2012. This slight increase in natural gas production is due to an increase in natural gas production from our Eagle Ford shale wells during 2013, which was sufficient to offset the decline in natural gas production for our Haynesville and Cotton Valley wells in Northwest Louisiana and East Texas. 
+Realized gain (loss) on derivatives . Our realized net loss on derivatives was approximately $0.9 million for the year ended December 31, 2013 , as compared to a realized net gain of approximately $14.0 million for the year ended December 31, 2012 . We realized a loss from our oil contracts of approximately $2.4 million for the year ended December 31, 2013 due to oil 
+57 
+Table of Contents 
+prices in excess of the ceiling price of some of our costless collar contracts and the fixed price of our swap contracts. This loss was partially offset by gains of approximately $0.8 million and $0.7 million on our natural gas and NGL derivatives contracts, respectively, due to the respective commodity prices being below the floor prices of our natural gas costless collars and the fixed prices of our NGL swap contracts. During the year ended December 31, 2012 , we realized a gain of approximately $2.0 million , $11.9 million and $21,000 on our oil, natural gas and NGL derivative contracts, respectively. These gains were the result of the respective commodity prices being below the floor and fixed prices of our oil costless collar and swap contracts, natural gas costless collar contracts and NGL swap contracts. We realized an average loss of approximately $1.42 per Bbl hedged on all of our oil costless collar and swap contracts during the year ended December 31, 2013 , as compared to an average gain of $1.74 per Bbl hedged for the year ended December 31, 2012 . Our oil volumes hedged for the year ended December 31, 2013 were also 44% higher as compared to the year ended December 31, 2012 . We realized an average gain of approximately $0.10 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2013 , as compared to an average gain of approximately $1.45 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2012 . Our total natural gas volumes hedged for the year ended December 31, 2013 were also 5% higher than the total natural gas volumes hedged for the year ended December 31, 2012 . 
+Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $7.2 million for the year ended December 31, 2013 , as compared to an unrealized loss of approximately $4.8 million for the year ended December 31, 2012 . During the year ended December 31, 2013 , the net fair value of our open oil, natural gas and natural gas liquids derivatives contracts decreased to approximately $(2.8) million , from $4.5 million for the year ended December 31, 2012 , resulting in an unrealized loss on derivatives of approximately $7.2 million for the year ended December 31, 2013 . During the year ended year ended December 31, 2013 , the net fair value of our open oil, natural gas and NGL derivative contracts decreased by $5.3 million , $1.6 million and $0.3 million , respectively, due primarily to the increase in the underlying commodities’ futures prices as compared to the year ended December 31, 2012 . 
+Year Ended December 31, 2012 as Compared to Year Ended December 31, 2011 
+Oil and natural gas revenues . Our oil and natural gas revenues increased by $89.0 million to $156.0 million , or an increase of about 133% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . This increase in oil and natural gas revenues reflects an increase in our oil revenues of $109.2 million and a decrease in our natural gas revenues of $20.2 million for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . Our oil revenues increased over eight-fold to $123.7 million for the year ended December 31, 2012 , as compared to $14.5 million for the year ended December 31, 2011 . Our oil production also increased almost eight-fold to just over 1.2 million Bbl of oil, or about 3,317 Bbl of oil per day, from approximately 154,000 Bbl of oil, or about 422 Bbl of oil per day, during the comparable periods due to our drilling operations in the Eagle Ford shale. A portion of this increase in oil revenue also reflects a higher weighted average oil price of $101.86 per Bbl realized during the year ended December 31, 2012 , as compared to a weighted average oil price of $93.80 per Bbl realized during the year ended December 31, 2011 . The decrease in our natural gas revenues reflects a decline in our natural gas production by about 14% to approximately 12.5 Bcf for the year ended December 31, 2012 , as compared to approximately 14.5 Bcf for the year ended December 31, 2011 . This decline in natural gas production was due to several factors, including (i) the natural decline in natural gas production primarily from our existing Haynesville shale and Cotton Valley wells in Northwest Louisiana and East Texas, coupled with our decision not to drill any operated Haynesville shale or Cotton Valley wells in 2012 , (ii) the voluntary curtailment by the operators of natural gas production from some of our non-operated Haynesville shale wells in Northwest Louisiana at various times during 2012 and (iii) delays in natural gas production from our newly completed Eagle Ford shale wells in South Texas as a result of natural gas pipeline and production facility constraints. This decrease in natural gas revenues also results from a significantly lower weighted average natural gas price of $2.59 per Mcf realized during the year ended December 31, 2012 , as compared to a weighted average natural gas price of $3.62 per Mcf realized during the year ended December 31, 2011 . 
+Realized gain on derivatives . Our realized gain on derivatives increased by approximately $6.9 million to $14.0 million for the year ended December 31, 2012 from $7.1 million for the year ended December 31, 2011 . For the year ended December 31, 2012 , we realized a gain of approximately $11.9 million on our open natural gas derivative contracts and a gain of approximately $2.0 million on our open oil derivative contracts. As a result of declining natural gas prices between the comparable periods, we realized an average gain of approximately $1.45 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2012 , as compared to an average gain of $1.03 per MMBtu hedged on all of our open natural gas costless collar contracts during the year ended December 31, 2011 . Our total natural gas volumes hedged for the year ended December 31, 2012 were also approximately 19% higher than the total natural gas volumes hedged for the year ended December 31, 2011 . We realized an average gain of $1.74 per Bbl hedged on all of our open oil contracts during the year ended December 31, 2012 . We had no open oil or NGL derivative contracts during the year ended December 31, 2011 . 
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+Unrealized gain (loss) on derivatives. Our unrealized loss on derivatives was approximately $4.8 million for the year ended December 31, 2012 , as compared to an unrealized gain of $5.1 million for the year ended December 31, 2011 . During the period from December 31, 2011 to December 31, 2012 , the net fair value of our open oil, natural gas and natural gas liquids derivative contracts decreased from approximately $9.3 million to approximately $4.5 million , resulting in an unrealized loss on derivatives of approximately $4.8 million for the year ended December 31, 2012 . During the year ended December 31, 2012 , the net fair value of our open natural gas costless collar contracts decreased by $8.7 million due primarily to the gains realized on these contracts during 2012 . The net fair value of our open oil derivative contracts increased $3.7 million during the year ended December 31, 2012 as a result of a decrease in oil futures prices at December 31, 2012 compared to December 31, 2011 and also as a result of two additional oil derivatives contracts we entered into during 2012 . During the year ended December 31, 2012 , we also entered into various NGL swap contracts which had a net fair value of approximately $0.2 million at December 31, 2012 . We had no open NGL swap contracts during the year ended December 31, 2011 . 
+Expenses 
+The following table summarizes our operating expenses and other income (expense) for the periods indicated. 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+(In thousands, except expenses per BOE) 
+Expenses: 
+Production taxes and marketing 
+$ 
+20,973 
+$ 
+11,672 
+$ 
+6,278 
+Lease operating 
+38,720 
+28,184 
+7,244 
+Depletion, depreciation and amortization 
+98,395 
+80,454 
+31,754 
+Accretion of asset retirement obligations 
+348 
+256 
+209 
+Full-cost ceiling impairment 
+21,229 
+63,475 
+35,673 
+General and administrative 
+20,779 
+14,543 
+13,394 
+Total expenses 
+200,444 
+198,584 
+94,552 
+Operating income (loss) 
+60,445 
+(33,428 
+) 
+(15,308 
+) 
+Other (expense) income: 
+Net loss on asset sales and inventory impairment 
+(192 
+) 
+(485 
+) 
+(154 
+) 
+Interest expense 
+(5,687 
+) 
+(1,002 
+) 
+(683 
+) 
+Interest and other income 
+225 
+224 
+315 
+Total other expense 
+(5,654 
+) 
+(1,263 
+) 
+(522 
+) 
+Income (loss) before income taxes 
+54,791 
+(34,691 
+) 
+(15,830 
+) 
+Total income tax provision (benefit) 
+9,697 
+(1,430 
+) 
+(5,521 
+) 
+Net income (loss) 
+$ 
+45,094 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+Expenses per BOE: 
+Production taxes and marketing 
+$ 
+4.89 
+$ 
+3.54 
+$ 
+2.44 
+Lease operating 
+$ 
+9.04 
+$ 
+8.56 
+$ 
+2.82 
+Depletion, depreciation and amortization 
+$ 
+22.96 
+$ 
+24.43 
+$ 
+12.34 
+General and administrative 
+$ 
+4.85 
+$ 
+4.42 
+$ 
+5.21 
+Year Ended December 31, 2013 as Compared to Year Ended December 31, 2012 
+Production taxes and marketing. Our production taxes and marketing expenses increased by $9.3 million to $21.0 million , an increase of 80% , for the year ended December 31, 2013 , as compared to $11.7 million for the year ended December 31, 2012 . The majority of this increase was attributable to increased production taxes associated with the large increase in our oil production during 2013 resulting from our drilling operations in the Eagle Ford shale in South Texas. Our total production was comprised of approximately 50% oil and 50% natural gas during the year ended December 31, 2013 , as compared to approximately 37% oil and 63% natural gas during the year ended December 31, 2012 . On a unit-of-production basis, our production taxes and marketing expenses increased by 38% to $4.89 per BOE for the year ended December 31, 2013 , as compared to $3.54 per BOE for the year ended December 31, 2012 . Production taxes on a unit-of-production basis on our oil and natural gas production in Texas are effectively higher than the production taxes on a unit-of-production basis on our production in Louisiana. As a result, the shift in our focus from the Haynesville shale in Northwest Louisiana to the Eagle Ford shale in South Texas has also resulted in an increase in our production taxes. 
+Lease operating expenses. Our lease operating expenses increased by $10.5 million to $38.7 million , an increase of 37% , for the year ended December 31, 2013 , as compared to $28.2 million for the year ended December 31, 2012 . Our total oil and natural gas production increased by 30% to approximately 4.3 million BOE for the year ended December 31, 2013 from approximately 3.3 million BOE for the year ended December 31, 2012 , and our oil production increased by 76% to over 2.1 
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+million Bbl for the year ended December 31, 2013 , as compared to 1.2 million Bbl for the year ended December 31, 2012 . Our lease operating expenses per unit of production increased 6% to $9.04 per BOE for the year ended December 31, 2013 , as compared to $8.56 per BOE for the year ended December 31, 2012 . This increase in lease operating expenses was primarily attributable to the overall increase in oil production and the higher lifting costs associated with oil production between the two years, as well as to the increased percentage of oil being produced, which was approximately 50% of total production by volume for the year ended December 31, 2013 , as compared to 37% of total production by volume for the year ended December 31, 2012 . 
+Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $17.9 million to $98.4 million , an increase of 22% , for the year ended December 31, 2013 , as compared to $80.5 million for the year ended December 31, 2012 . On a unit-of-production basis, our depletion, depreciation and amortization expenses were $22.96 per BOE for the year ended December 31, 2013 , a decrease of 6% , from $24.43 per BOE for the year ended December 31, 2012 . The decrease in our depletion, depreciation and amortization expenses reflects an increase of approximately 30% in our total oil and natural gas production to 4.3 million BOE for the year ended December 31, 2013 from 3.3 million BOE for the year ended December 31, 2012 . Because we use the unit-of-production method for calculating depletion, depreciation and amortization expense, the impact of the increased production experienced in the year ended December 31, 2013 , as compared to the year ended December 31, 2012 , on our depletion, depreciation and amortization expenses was offset by the increase in our proved oil and natural gas reserves to 51.7 million BOE at December 31, 2013 from 23.8 million BOE at December 31, 2012 . Primarily as a result of continued improvement in natural gas prices over the past year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013. We had removed a large portion of these proved undeveloped natural gas reserves from our estimated total proved reserves at June 30, 2012 because the unweighted arithmetic average natural gas price had declined to $3.146 per MMBtu, a price at which the natural gas volumes associated with almost all of our identified Haynesville shale well locations could no longer be classified as proved undeveloped reserves. 
+Full-cost ceiling impairment. No impairment to the net carrying value of our oil and natural gas properties and no corresponding charge resulting from a full-cost ceiling impairment was recorded during the quarters ended December 31, 2013, September 30, 2013 or June 30, 2013. During the quarter ended March 31, 2013, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . As a result, we recorded an impairment charge of $21.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $7.5 million . This full-cost ceiling impairment of $21.2 million is reflected in our operating expenses for the year ended December 31, 2013 , and resulted primarily from the continued low weighted average index price for natural gas used to estimate proved natural gas reserves at March 31, 2013, which was $2.95 per MMBtu for the period of time from April 2012 through March 2013. At June 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . As a result, we recorded an impairment charge of $33.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $11.9 million . At September 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . As a result, we recorded an impairment charge of $3.6 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $1.3 million . At December 31, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million . As a result, we recorded an impairment charge of $26.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $9.4 million . These full-cost ceiling impairment charges in 2012 were primarily attributable to declining natural gas prices throughout much of the year. As a result of substantially lower natural gas prices in 2012 , we had downward revisions of our natural gas reserves totaling 103.4 Bcf (17.2 million BOE), including the removal of 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012. These impairment charges are reflected in our operating expenses for the year ended December 31, 2012 . 
+General and administrative. Our general and administrative expenses increased by $6.2 million to $20.8 million , an increase of 43% , for the year ended December 31, 2013 , as compared to $14.5 million for the year ended December 31, 2012 . The increase in our general and administrative expenses was primarily attributable to a $3.8 million increase in stock-based compensation costs to $3.9 million for the year ended December 31, 2013 , as compared to $0.1 million for the year ended December 31, 2012 . The increase in our stock-based compensation expense was primarily attributable to the continued vesting of awards granted in 2012 and 2013, as well as the increased fair value of our liability-based stock options during the year ended December 31, 2013 due to the increase in our stock price from $8.20 per share at December 31, 2012 to $18.64 per share at December 31, 2013 . The remaining increase in our general and administrative expenses was primarily due to additional payroll expenses associated with personnel added between the respective periods to support our increased operations, some of which was offset by $1.0 million of our general and administrative expenses for the year ended December 31, 2013 that was 
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+Table of Contents 
+capitalized in connection with the permanent production facilities being constructed on certain of our properties in the Eagle Ford shale in South Texas during the second quarter of 2013. Our general and administrative expenses increased by only 10% on a unit-of-production basis to $4.85 per BOE for the year ended December 31, 2013 , as compared to $4.42 for the year ended December 31, 2012 . On a unit-of-production basis, the increase in general and administrative expenses was partially offset by the increase of approximately 30% in our total oil and natural gas production to 4.3 million BOE from 3.3 million BOE during the respective periods. 
+Interest expense. For the year ended December 31, 2013 , we incurred total interest expense of approximately $7.6 million . We capitalized approximately $1.9 million of our interest expense on certain qualifying projects for the year ended December 31, 2013 and expensed the remaining $5.7 million to operations. For the year ended December 31, 2012 , we incurred total interest expense of approximately $2.6 million . We capitalized approximately $1.6 million of our interest expense on certain qualifying projects for the year ended December 31, 2012 and expensed the remaining $1.0 million to operations. The increase in interest expense for the year ended December 31, 2013 of $4.7 million , as compared to the year ended December 31, 2012 , was primarily attributable to higher average outstanding borrowings under our Credit Agreement during 2013, as compared to average outstanding borrowings under our Credit Agreement during 2012. In September 2013, we used a portion of the net proceeds of our public equity offering to repay $130.0 million of outstanding borrowings under our Credit Agreement. At December 31, 2013 , we had $200.0 million in borrowings and $0.3 million in letters of credit outstanding under our Credit Agreement, and the effective interest rate on our borrowings was approximately 3.3% per annum. In February 2012, we used a portion of the net proceeds of our Initial Public Offering to repay our then outstanding borrowings of $123.0 million . At December 31, 2012, we had $150.0 million in borrowings and $1.1 million in letters of credit outstanding under our Credit Agreement. 
+Total income tax provision (benefit) . We recorded a total income tax provision of approximately $9.7 million for the year ended December 31, 2013 , as compared to a total income tax benefit of approximately $1.4 million for the year ended December 31, 2012 . For the year ended December 31, 2013 , we incurred an AMT liability of $0.4 million , which represents the current portion of the income tax provision. The remaining tax provision of $9.3 million represents deferred taxes for the year ended December 31, 2013 . Our effective tax rate for the year ended December 31, 2013 was 17.7% . Total income tax expense for the year ended December 31, 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to (i) the reversal of the valuation allowance of approximately $8.9 million on our federal deferred tax assets at December 31, 2012, as our federal deferred tax liability exceeded our federal deferred tax assets for the year ended December 31, 2013 , (ii) the reversal of a state valuation allowance of approximately $1.3 million , as we now believe we will be able to utilize the state net operating losses prior to their expiration, and (iii) the impact of permanent differences between book and taxable income. During the year ended December 31, 2012 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $40.9 million . We recorded an impairment charge of $63.5 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $22.6 million . The increase in our deferred tax assets as a result of the impairment charges recorded during the year ended December 31, 2012 caused our deferred tax assets to exceed our deferred tax liabilities, resulting in the establishment of a valuation allowance of $10.3 million due to uncertainties regarding the future realization of our deferred tax assets. As a result, we recorded an income tax benefit of $1.4 million for the year ended December 31, 2012 . We had a net loss for the year ended December 31, 2012. 
+Year Ended December 31, 2012 as Compared to Year Ended December 31, 2011 
+Production taxes and marketing. Our production taxes and marketing expenses increased by $5.4 million to $11.7 million , or an increase of approximately 86% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . The increase in our production taxes and marketing expenses primarily reflects the increase in our total oil and natural gas revenues by 133% for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . The majority of this increase was attributable to increased production taxes associated with the large increase in our oil production during 2012 resulting from our drilling operations in the Eagle Ford shale in South Texas. Our total production was comprised of approximately 37% oil and 63% natural gas during the year ended December 31, 2012 , as compared to approximately 6% oil and 94% natural gas during the year ended December 31, 2011 . On a unit-of-production basis, our production taxes and marketing expenses increased by 45% to $3.54 per BOE for the year ended December 31, 2012 , as compared to $2.44 per BOE for the year ended December 31, 2011 . 
+Lease operating expenses. Our lease operating expenses increased by $20.9 million to $28.2 million , or an increase of about 289% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . Our total oil and natural gas production increased by about 28% to approximately 3.3 million BOE for the year ended December 31, 2012 from approximately 2.6 million BOE for the year ended December 31, 2011 , but our oil production increased almost eight-fold to just over 1.2 million Bbl from approximately 154,000 Bbl during the respective period. The increase in lease operating expenses was primarily attributable to the increased costs associated with operating oil production resulting from drilling operations in the Eagle Ford shale in 2012 , as compared to the lower lease operating expenses associated with operating 
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+Table of Contents 
+primarily dry natural gas production from the Haynesville and Cotton Valley in 2011. In addition, oil production comprised 37% of our total production during the year ended December 31, 2012 , as compared to only 6% for the year ended December 31, 2011 , resulting in higher overall lease operating expenses during the year ended December 31, 2012 . During the year ended December 31, 2012 , we completed and initiated oil and natural gas production from 28 gross (24.5 net) wells in the Eagle Ford shale (plus two gross (2.0 net) Austin Chalk/“Chalkleford” wells), most of which were on properties where new production facilities were being installed or natural gas pipelines were awaiting completion. While these new facilities were being installed and tested, much of the oil and natural gas was produced through rental equipment monitored by 24-hour contract personnel, resulting in higher operating costs from these properties during the year ended December 31, 2012 . Approximately one-third of our total lease operating expenses in 2012 were attributable to these extended flowback operations. Our lease operating expenses per unit of production increased 204% to $8.56 per BOE for the year ended December 31, 2012 , as compared to $2.82 per BOE for the year ended December 31, 2011 . 
+Depletion, depreciation and amortization. Our depletion, depreciation and amortization expenses increased by $48.7 million to $80.5 million , or an increase of about 153% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . On a unit-of-production basis, our depletion, depreciation and amortization expenses increased to $24.43 per BOE for the year ended December 31, 2012 , as compared to $12.34 per BOE for the year ended December 31, 2011 . This increase in our depletion, depreciation and amortization expenses was primarily attributable to the decrease in our total proved oil and natural gas reserves to 23.8 million BOE at December 31, 2012, as compared to 32.2 million BOE at December 31, 2011. As a result of substantially lower natural gas prices in 2012 , we removed 97.8 Bcf ( 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012, and these proved undeveloped reserves were likewise not included in our total proved reserves at December 31, 2012. The increase in depletion, depreciation and amortization expenses was also partially attributable to the increase of approximately 28% in our oil and natural gas production to approximately 3.3 million BOE for the year ended December 31, 2012 , as compared to approximately 2.6 million BOE for the year ended December 31, 2011 , as well as to the higher drilling and completion costs on a per BOE basis associated with oil reserves added in the Eagle Ford shale in South Texas as compared with our Haynesville shale natural gas assets in Northwest Louisiana. 
+Accretion of asset retirement obligations . Our accretion of asset retirement obligations expenses increased by approximately $47,000 to $256,000 , or an increase of about 23% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . The increase in the accretion of our asset retirement obligations was due primarily to the addition of new wells through our drilling of operated wells and our participation in the drilling of non-operated wells, although, on the whole, this item is an insignificant component of our overall expenses. 
+Full-cost ceiling impairment. At June 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . As a result, we recorded an impairment charge of $33.2 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $11.9 million . At September 30, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . As a result, we recorded an impairment charge of $3.6 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $1.3 million . At December 31, 2012, the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million . As a result, we recorded an impairment charge of $26.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $9.4 million . These full-cost ceiling impairment charges in 2012 were primarily attributable to declining natural gas prices throughout much of the year. As a result of substantially lower natural gas prices in 2012 , we had downward revisions of our natural gas reserves totaling 103.4 Bcf ( 17.2 million BOE), including the removal of 97.8 Bcf ( 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our total proved reserves at June 30, 2012. These impairment charges are reflected in our operating expenses for the year ended December 31, 2012 . During the first quarter of 2011 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $23.0 million . As a result, we recorded an impairment charge of $35.7 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $12.7 million , which is reflected in our operating expenses for the year ended December 31, 2011 . 
+General and administrative. Our general and administrative expenses increased by $1.1 million to $14.5 million , or an increase of about 9% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . Our general and administrative expenses decreased by 15% on a unit-of-production basis to $4.42 per BOE for the year ended December 31, 2012 , as compared to $5.21 per BOE for the year ended December 31, 2011 . The increase in our general and administrative expenses was attributable to increased compensation, accounting, legal and other administrative expenses, most of which was associated with becoming a public company in February 2012, partially offset by a net decrease in non-cash stock-based compensation expense of $2.3 million for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . 
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+Table of Contents 
+Net gain (loss) on asset sales and inventory impairment . We incurred a loss on asset sales and inventory impairment of approximately $0.5 million for the year ended December 31, 2012 , as compared to a loss of $0.2 million for the year ended December 31, 2011 . The loss during 2012 was primarily related to the impairment of certain equipment held in inventory, mostly consisting of drilling rig parts. During the year ended December 31, 2011 , the loss was primarily related to the sale of pipe and other equipment and the impairment of certain equipment held in inventory, mostly consisting of drilling rig parts. 
+Interest expense. For the year ended December 31, 2012 , we incurred total interest expense of approximately $2.6 million . We capitalized approximately $1.6 million of our interest expense on certain qualifying projects for the year ended December 31, 2012 and expensed the remaining $1.0 million to operations. In February 2012, we repaid our borrowings then outstanding of $123.0 million under our Credit Agreement using a portion of the net proceeds received from our Initial Public Offering. From March 1 through December 31, 2012, we borrowed $150.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. Our total outstanding borrowings at December 31, 2012 were $150.0 million , and the effective interest rate on the borrowings was approximately 3.3%. At December 31, 2011 , we had total borrowings of $113.0 million outstanding under our Credit Agreement, and we incurred total interest expense of approximately $2.0 million . We capitalized approximately $1.3 million of our interest expense on certain qualifying projects for the year ended December 31, 2011 and expensed the remaining $0.7 million to operations. 
+Interest and other income. Our interest and other income decreased by approximately $0.1 million to approximately $0.2 million , or a decrease of about 29% , for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . The decrease in our interest and other income was due primarily to a decrease in the natural gas transportation income received from third parties during the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . Our cash and certificates of deposit decreased to approximately $2.3 million at December 31, 2012 from approximately $11.6 million at December 31, 2011 . 
+Total income tax provision (benefit) . We recorded a total income tax benefit of approximately $1.4 million for the year ended December 31, 2012 , as compared to a total income tax benefit of approximately $5.5 million for the year ended December 31, 2011 . During the year ended December 31, 2012 , the net capitalized costs of our oil and natural gas properties less related deferred income taxes exceeded the cost center ceiling by $40.9 million . We recorded an impairment charge of $63.5 million to the net capitalized costs of our oil and natural gas properties and a deferred income tax credit of $22.6 million . The increase in our deferred tax assets as a result of the impairment charges recorded during the year ended December 31, 2012 caused our deferred tax assets to exceed our deferred tax liabilities, resulting in the establishment of a valuation allowance of $10.3 million due to uncertainties regarding the future realization of our deferred tax assets. As a result, we recorded an income tax benefit of $1.4 million for the year ended December 31, 2012 . The total income tax benefit for the year ended December 31, 2011 reflected deferred income taxes almost entirely, with the exception of a state of Louisiana income tax refund of approximately $46,000 recorded during this period. We had a net loss for the years ended December 31, 2012 and 2011 . 
+Liquidity and Capital Resources 
+Prior to the consummation of our Initial Public Offering on February 7, 2012, our primary sources of liquidity were capital contributions from private investors, our cash flows from operations, borrowings under our Credit Agreement and the proceeds from a significant sale of a portion of our assets in the Haynesville shale in 2008. Our primary use of capital has been, and we expect will continue to be during 2014 and for the foreseeable future, for the acquisition, exploration and development of oil and natural gas properties. We continually evaluate potential capital sources, including additional borrowings, equity and debt financings and joint ventures, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital and to continue to grow our operating cash flows. 
+At December 31, 2013 , we had cash totaling approximately $6.3 million , the borrowing base under our Credit Agreement was $350.0 million and we had $200.0 million of outstanding long-term borrowings and approximately $0.3 million in outstanding letters of credit. These borrowings bore interest at an effective interest rate of approximately 3.3% per annum. On March 12, 2014 we amended our Credit Agreement to, among other things, increase the borrowing base to $385.0 million . From January 1 through March 13, 2014, we borrowed an additional $50.0 million under our Credit Agreement to finance a portion of our working capital requirements and capital expenditures. At March 13, 2014 , we had $250.0 million of outstanding long-term borrowings and approximately $0.3 million in outstanding letters of credit. 
+On September 28, 2012, we entered into the third amended and restated credit agreement (the “Credit Agreement”), which increased the maximum facility amount to $500.0 million from $400.0 million . The borrowing base under the Credit Agreement is scheduled to be redetermined automatically on May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may each request an unscheduled redetermination of the borrowing base once between scheduled redetermination 
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+Table of Contents 
+dates. On August 7, 2013, the borrowing base under the Credit Agreement was increased to $350.0 million from $280.0 million , based on the lenders’ review of our proved oil and natural gas reserves at June 30, 2013. This August 2013 redetermination constituted the regularly scheduled November 1 redetermination. During the first quarter of 2014 , our lenders completed their review of our estimated total proved oil and natural gas reserves at December 31, 2013 , and as a result, on March 12, 2014 , the borrowing base under our Credit Agreement was increased to $385.0 million , and the conforming borrowing base was increased to $310.0 million . At that time, we amended the Credit Agreement to provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by us of senior unsecured notes in an amount greater than or equal to $10.0 million . This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. We expect additional increases to the borrowing base will be primarily as a result of anticipated increases in our proved oil and natural gas reserves, and particularly our proved developed oil and natural gas reserves. 
+On September 10, 2013, we completed an underwritten public offering of 9,775,000 shares of our common stock, including 1,275,000 shares issued pursuant to the underwriters’ exercise of their option to purchase additional shares. After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million , we received net proceeds of approximately $141.7 million . We are using the net proceeds from this offering primarily to fund a portion of our capital expenditures, including for the addition of the third rig to our drilling program. We are also using the net proceeds from this offering to fund the acquisition of additional acreage in the Eagle Ford shale, the Permian Basin and the Haynesville shale and for other general working capital needs. Pending such uses, we used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under our Credit Agreement in September 2013, which amounts may be reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. 
+Our 2014 capital expenditure budget is estimated at $440.0 million and includes approximately $394.0 million for drilling and completing oil and natural gas exploration and development wells, with the remainder allocated to lease acquisitions, seismic data, pipelines and other infrastructure. As a result of the receipt of the net proceeds of our September 2013 public equity offering, current availability and anticipated increases in the borrowing base under our Credit Agreement and our anticipated increases in oil and natural gas production and related revenues, excluding any possible significant acquisitions, we expect to have sufficient future borrowing capacity under our Credit Agreement and cash flows from operations to fund our capital expenditure requirements for 2014. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices and to partially offset reductions in our cash flows from operations resulting from declines in commodity prices. However, should our drilling activities be less successful than we anticipate or result in less growth in our proved oil and natural gas reserves or less cash flows than we anticipate, or should oil and natural gas prices decline substantially, we may require additional sources of financing, including through additional borrowings under our Credit Agreement (assuming availability under our borrowing base) or additional credit arrangements, potential joint ventures, the sale of assets or acreage and potential issuances of equity or debt securities, which may not be available on terms reasonably acceptable to us or at all. To the extent such sources of financing are not available on terms reasonably acceptable to us, we may need to reduce our capital spending and rate of growth. 
+Exploration and development activities are subject to a number of risks and uncertainties, which could cause these activities to be less successful than we anticipate and could impact our ability to sufficiently increase our reserves, cash flows from operations and borrowing base under our Credit Agreement. Although a significant portion of our anticipated cash flows from operations for 2014 is expected to come from development activities on currently proved properties in the Eagle Ford shale in South Texas, these development activities may be less successful than we anticipate. Further, a portion of our anticipated cash flows from operations during the year ending December 31, 2014 is expected to come from exploration activities in the Eagle Ford shale and in the Wolfcamp and Bone Spring plays in the Permian Basin, and these exploration activities may not be as successful as we anticipate. Additionally, our anticipated cash flows from operations are based upon current expectations of oil and natural gas prices for 2014 and the hedges we currently have in place. 
+If our exploration and development activities result in less cash flows than anticipated, we may seek additional sources of capital, including through additional borrowings under our Credit Agreement, the sale of assets or acreage or entering into one or more joint ventures, none of which may be available. In addition to future borrowings under our Credit Agreement, we may also seek to raise additional funds by issuing debt securities or selling shares of our common stock or securities convertible or exercisable into our common stock (including debt securities or other preferential securities) in the public markets or otherwise. Any such sales of equity or convertible securities would dilute the ownership interest of our existing shareholders. There is no guarantee that we would be able to sell such debt or equity securities on terms acceptable to us. It is also possible that, to the extent we are not able to obtain additional sources of capital, we may modify our planned capital expenditure budget for 2014 accordingly to reduce our capital spending and rate of growth or enter into one or more joint ventures or other alternative financings. Exploration and development activities are subject to a number of risks and uncertainties that could impact our ability to sufficiently increase our reserves, cash flows from operations and the borrowing base under our Credit Agreement. 
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+See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth,” “Risk Factors — Drilling for and Producing Oil and Natural Gas Are Highly Speculative and Involve a High Degree of Risk, with Many Uncertainties That Could Adversely Affect Our Business” and “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling.” 
+Our cash flows for the years ended December 31, 2013, 2012 and 2011 are presented below: 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+(In thousands) 
+Net cash provided by operating activities 
+$ 
+179,470 
+$ 
+124,228 
+$ 
+61,868 
+Net cash used in investing activities 
+(366,939 
+) 
+(306,916 
+) 
+(160,088 
+) 
+Net cash provided by financing activities 
+191,661 
+174,499 
+87,444 
+Net change in cash 
+$ 
+4,192 
+$ 
+(8,189 
+) 
+$ 
+(10,776 
+) 
+Cash Flows Provided by Operating Activities 
+Net cash provided by operating activities increased by $55.2 million to $179.5 million for the year ended December 31, 2013 , as compared to net cash provided by operating activities of $124.2 million for the year ended December 31, 2012 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $185.7 million for the year ended December 31, 2013 from $114.9 million for the year ended December 31, 2012 . This increase is primarily attributable to the increase of approximately 76% in our oil production to just over 2.1 million Bbl from approximately 1.2 million Bbl during the respective periods. Changes in our operating assets and liabilities between December 31, 2012 and December 31, 2013 also resulted in a net decrease of approximately $15.5 million in net cash provided by operating activities for the year ended December 31, 2013 , as compared to the year ended December 31, 2012 . 
+Net cash provided by operating activities increased by $62.3 million to $124.2 million for the year ended December 31, 2012 , as compared to net cash provided by operating activities of $61.9 million for the year ended December 31, 2011 . Excluding changes in operating assets and liabilities, net cash provided by operating activities increased significantly to $114.9 million for the year ended December 31, 2012 from $49.3 million for the year ended December 31, 2011 . This increase is primarily attributable to the almost eight-fold increase in our oil production to just over 1.2 million Bbl from approximately 154,000 Bbl during the respective periods. A portion of the increase in net cash provided by operating activities also reflects the higher weighted average oil price of $101.86 per Bbl realized during 2012 , as compared to a weighted average oil price of $93.80 per Bbl realized during 2011 . Changes in our operating assets and liabilities between December 31, 2011 and December 31, 2012 also resulted in a net decrease of approximately $3.3 million in net cash provided by operating activities for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 . Our accounts payable and accrued liabilities increased to approximately $87.3 million at December 31, 2012 from approximately $44.3 million at December 31, 2011 due to our increased operating activity in South Texas. Our accounts receivable increased to $29.5 million at December 31, 2012 , as compared to $13.2 million at December 31, 2011 , due primarily to the increase in our oil production and associated revenues. 
+Our operating cash flows are sensitive to a number of variables, including changes in our production and volatility of oil and natural gas prices between reporting periods. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of oil and natural gas. These factors are beyond our control and are difficult to predict. We use commodity derivative financial instruments to mitigate our exposure to fluctuations in oil, natural gas and natural gas liquids prices. In addition, we attempt to avoid long-term service agreements in order to minimize ongoing future commitments. For additional information on the impact of changing prices on our financial position, see “Quantitative and Qualitative Disclosures About Market Risk” below. See also “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+Cash Flows Used in Investing Activities 
+Net cash used in investing activities increased by $60.0 million to $366.9 million for the year ended December 31, 2013 from $306.9 million for the year ended December 31, 2012 . This increase in net cash used in investing activities reflected an increase of $62.5 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2013 , as 
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+compared to the year ended December 31, 2012 , and a decrease of approximately $3.4 million in expenditures for other property and equipment, which includes new pipeline infrastructure associated with our properties in the Eagle Ford shale. 
+Approximately 83% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 17% to the acquisition of additional acreage for the year ended December 31, 2013 , as compared to approximately 91% allocated to drilling and completion operations and associated infrastructure and 9% allocated to acquisition of additional acreage for the year ended December 31, 2012 . Cash used for oil and natural gas properties capital expenditures for the year ended December 31, 2013 was primarily attributable to our operated and non-operated drilling and completion activities in the Eagle Ford shale play, as well as to our initial operated drilling activities in the Permian Basin. We also used a portion of this cash to acquire approximately 55,400 gross (38,900 net) additional acres in the Permian Basin during 2013, along with 1,720 gross (1,660 net) acres in the Eagle Ford shale and 1,190 gross (1,190 net) acres in the Haynesville shale. 
+Net cash used in investing activities increased by $146.8 million to $306.9 million for the year ended December 31, 2012 from $160.1 million for the year ended December 31, 2011 . This increase in net cash used in investing activities reflected an increase of $144.3 million in our oil and natural gas properties capital expenditures for the year ended December 31, 2012 , as compared to the year ended December 31, 2011 , and an increase of approximately $2.7 million in expenditures for other property and equipment, which included new pipeline infrastructure associated with our initial wells in the Eagle Ford shale. Approximately 91% of our capital expenditures were allocated to drilling and completion operations and associated infrastructure and 9% to the acquisition of additional acreage for the year ended December 31, 2012 , as compared to approximately 75% allocated to drilling and completion operations and associated infrastructure and 25% allocated to acquisition of additional acreage for the year ended December 31, 2011 . Our oil and natural gas properties capital expenditures for the year ended December 31, 2012 were primarily due to expenditures associated with our operated drilling and completion activities in the Eagle Ford shale, non-operated drilling and completion activities and acreage acquisitions in the Eagle Ford and Haynesville shale plays and our acreage acquisitions in the Permian Basin. 
+Expenditures for the acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We anticipate investing approximately $440.0 million in capital for acquisition, exploration and development activities in 2014 as follows: 
+Amount 
+(in millions) 
+Exploration, development drilling and completion costs 
+$ 
+394.0 
+Pipeline and infrastructure expenditures 
+16.0 
+Leasehold acquisition and 2-D and 3-D seismic data 
+30.0 
+Total 
+$ 
+440.0 
+For further information regarding our anticipated 2014 capital expenditure budget, see “Business — General.” 
+Our 2014 capital expenditures may be adjusted as business conditions warrant. The amount, timing and allocation of our capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline or costs increase significantly, we could defer a significant portion of our anticipated capital expenditures until later periods to conserve cash or to focus on those projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling, completion and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in our exploration and development activities, contractual obligations, drilling plans for properties we do not operate and other factors both within and outside our control. 
+Cash Flows Provided by Financing Activities 
+Net cash provided by financing activities was $191.7 million for the year ended December 31, 2013 , as compared to net cash provided by financing activities of $174.5 million for the year ended December 31, 2012 . The net cash provided by financing activities for the year ended December 31, 2013 was primarily attributable to the total proceeds of our September 2013 public equity offering of $149.1 million and borrowings under our Credit Agreement of $180.0 million , offset by the costs of the offering of $7.4 million paid during the period and by the repayment of $130.0 million in borrowings under our Credit Agreement during the period. 
+Net cash provided by financing activities was $174.5 million for the year ended December 31, 2012 , as compared to net cash provided by financing activities of $87.4 million for the year ended December 31, 2011 . The net cash provided by financing activities for the year ended December 31, 2012 was principally due to the total proceeds from the Initial Public Offering of $146.5 million and total borrowings of $160.0 million under our Credit Agreement to fund a portion of our working 
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+Table of Contents 
+capital requirements during the period, offset by the costs of the Initial Public Offering of $11.6 million incurred during the period and by the repayment of $123.0 million in borrowings during the period. We also received approximately $2.7 million from the exercise of stock options during the year ended December 31, 2012 . 
+Net cash provided by financing activities was $87.4 million for the year ended December 31, 2011 . The net cash provided by financing activities for the year ended December 31, 2011 was due almost entirely to additional borrowings of $88.0 million under our Credit Agreement to fund a portion of our working capital requirements as well as our acquisition of acreage prospective for the Eagle Ford shale play in DeWitt, Gonzales, Karnes and Wilson Counties, Texas. In January 2011, we sold 53,772 shares of our Class A common stock in a private placement and received net proceeds of approximately $0.6 million . During 2011, we also received proceeds from the exercise of stock options totaling approximately $0.8 million . For the year ended December 31, 2011 , we also incurred cash expenditures related to preparation for our Initial Public Offering of approximately $1.7 million . 
+Credit Agreement 
+On September 28, 2012, we entered into the Credit Agreement, which increased the maximum facility amount from $400.0 million to $500.0 million . The Credit Agreement matures December 29, 2016. MRC Energy Company is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of our oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. 
+The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of our proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both we and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2013, the lenders completed their review of our proved oil and natural gas reserves at December 31, 2012, and on March 11, 2013, the borrowing base was increased from $215.0 million to $255.0 million . In connection with this borrowing base redetermination, the conforming borrowing base was increased to $220.0 million . At that time, we also amended the Credit Agreement to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and Iberia Bank in our lending group, which also included Royal Bank of Canada (RBC), as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. This March 2013 redetermination constituted the regularly scheduled May 1 redetermination. In late April 2013, we requested an unscheduled redetermination of the borrowing base, and on June 4, 2013, the borrowing base was increased from $255.0 million to $280.0 million , and the conforming borrowing base was increased to $245.0 million . On August 7, 2013, the borrowing base under the Credit Agreement was increased to $350.0 million and the conforming borrowing base was increased to $275.0 million . At that time, we amended the Credit Agreement to provide that the borrowing base would automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2014 or (ii) concurrent with the issuance by us of senior unsecured notes in an amount greater than or equal to $10.0 million . This August 2013 redetermination constituted the regularly scheduled November 1 redetermination. 
+During the first quarter of 2014 , our lenders completed their review of our estimated total proved oil and natural gas reserves at December 31, 2013 , and as a result, on March 12, 2014 , the borrowing base under our Credit Agreement was increased to $385.0 million , and the conforming borrowing base was increased to $310.0 million . At that time, Wells Fargo, N.A. replaced Capital One, N.A. in our lending group, and we amended the Credit Agreement to provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by us of senior unsecured notes in an amount greater than or equal to $10.0 million . The Credit Agreement was also amended to eliminate the current ratio covenant and to increase the debt to EBITDA ratio covenant, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, to 4.25 or less. Furthermore, the interest rate charged to us based on our outstanding level of borrowings was reduced by 0.25% across the borrowing grid as a result of this amendment. This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. We may request one additional unscheduled redetermination of our borrowing base prior to the next scheduled redetermination. We expect additional increases to the borrowing base will be primarily as a result of anticipated increases in our proved oil and natural gas reserves, and particularly our proved developed oil and natural gas reserves. 
+In the event of a borrowing base increase, we are required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, we would be required to provide additional 
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+Table of Contents 
+collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months. 
+On September 12, 2013, using a portion of the net proceeds from our public equity offering, we repaid $130.0 million of outstanding borrowings under the Credit Agreement. At December 31, 2013 , we had $200.0 million in borrowings outstanding under the Credit Agreement and approximately $0.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. At December 31, 2013 , our outstanding borrowings bore interest at an effective interest rate of approximately 3.3% per annum. We expect to access future borrowings under our Credit Agreement to fund our 2014 capital expenditure requirements in excess of amounts available from our operating cash flows. From January 1, 2014 through March 13, 2014 , we borrowed an additional $50.0 million under the Credit Agreement to finance a portion of our working capital requirements and capital expenditures and the acquisition of additional leasehold interests. At March 13, 2014 , we had $250.0 million in borrowings outstanding under the Credit Agreement and approximately $0.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. 
+Under the terms of our Credit Agreement as of December 31, 2013 and until the March 12, 2014 amendment described above, if we borrowed funds as a base rate loan, such borrowings bore interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 3.00% of such outstanding loan depending on the level of borrowings under the agreement. If we borrowed funds as a Eurodollar loan, such borrowings bore interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.75% to 4.00% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by us. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. We include this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees as interest expense and in our interest rate calculations and related disclosures. At December 31, 2013, the key financial covenants under the Credit Agreement required us to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater to be measured at the end of each fiscal quarter beginning June 30, 2014 and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less. 
+Subject to certain exceptions, our Credit Agreement contains various covenants that limit our ability to take certain actions, including, but not limited to, the following: 
+• 
+incur indebtedness or grant liens on any of our assets; 
+• 
+enter into commodity hedging agreements; 
+• 
+declare or pay dividends, distributions or redemptions; 
+• 
+merge or consolidate; 
+• 
+make any loans or investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+engage in certain asset dispositions, including a sale of all or substantially all of our assets. 
+If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: 
+• 
+failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; 
+• 
+failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; 
+• 
+bankruptcy or insolvency events involving us or our subsidiaries; and 
+• 
+a change of control, as defined in the Credit Agreement. 
+At December 31, 2013 , we believe that we were in compliance with the terms of our Credit Agreement. 
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+Table of Contents 
+Off-Balance Sheet Arrangements 
+At December 31, 2013 , we did not have any off-balance sheet arrangements. 
+Obligations and Commitments 
+We had the following material contractual obligations and commitments at December 31, 2013 : 
+Payments Due by Period 
+Total 
+Less Than 1 Year 
+1-3 Years 
+3-5 Years 
+More Than 5 Years 
+(In thousands) 
+Contractual Obligations: 
+Revolving credit borrowings and term loan, including letters of credit (1) 
+$ 
+200,300 
+$ 
+250 
+$ 
+200,050 
+$ 
+— 
+$ 
+— 
+Office lease 
+7,589 
+812 
+1,684 
+1,764 
+3,329 
+Non-operated drilling commitments (2) 
+5,666 
+5,666 
+— 
+— 
+— 
+Drilling rig contracts (3) 
+9,884 
+8,781 
+1,103 
+— 
+— 
+Asset retirement obligations 
+7,484 
+175 
+657 
+954 
+5,698 
+Natural gas processing and transportation agreement (4) 
+10,718 
+4,731 
+4,792 
+1,195 
+— 
+Total contractual cash obligations 
+$ 
+241,641 
+$ 
+20,415 
+$ 
+208,286 
+$ 
+3,913 
+$ 
+9,027 
+__________________ 
+(1) 
+At December 31, 2013 , we had $200.0 million in revolving borrowings outstanding under our Credit Agreement and approximately $0.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. These borrowings mature in December 2016. These amounts do not include estimated interest on the obligations, because our revolving borrowings had short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods. 
+(2) 
+At December 31, 2013 , we had outstanding commitments to participate in the drilling and completion of various non-operated wells. Our working interests in these wells are typically small, and most of these wells were in progress at December 31, 2013 . If all of these wells are drilled and completed, we will have minimum outstanding aggregate commitments for our participation in these wells of approximately $5.7 million at December 31, 2013 , which we expect to incur within the next few months. 
+(3) 
+From time to time, we enter into contracts with third parties for drilling rigs. These contracts establish daily rates for the drilling rigs and the term of our commitments for the drilling services to be provided, which are typically for one year or less. Should we elect to terminate a contract and if the drilling contractor were unable to secure work for the contracted drilling rigs or if the drilling contractor were unable to secure work for the contracted drilling rigs at the same daily rates being charged to us prior to the end of their respective contract terms, we would incur termination obligations. Our maximum outstanding aggregate termination obligations under our drilling rig contracts were approximately $9.9 million at December 31, 2013 . 
+(4) 
+Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement for a significant portion of our operated natural gas production in South Texas. The undiscounted minimum commitments under this agreement total approximately $10.7 million at December 31, 2013 . 
+General Outlook and Trends 
+For the year ended December 31, 2013 , oil prices ranged from a low of approximately $86.68 per Bbl in mid-April to a high of approximately $110.53 per Bbl in early September , based upon the NYMEX West Texas Intermediate oil futures contract price for the earliest delivery date. The oil price at December 31, 2013 was $98.42 per Bbl. We realized a weighted average oil price of $99.79 per Bbl ( $98.67 per Bbl including realized losses from oil derivatives) for our oil production for the year ended December 31, 2013 , as compared to $101.86 per Bbl ($103.55 per Bbl including realized gains from oil derivatives)for the year ended December 31, 2012. At March 13, 2014 , the NYMEX West Texas Intermediate oil futures contract for the earliest delivery date closed at $98.20 per Bbl, as compared to $92.52 per Bbl at March 13, 2013. 
+For the year ended December 31, 2013 , natural gas prices ranged from a low of approximately $3.11 per MMBtu in early January to a high of approximately $4.46 per MMBtu in late December , based upon the NYMEX Henry Hub natural gas futures contract price for the earliest delivery date. We realized a weighted average natural gas price of $4.35 per Mcf ( $4.47 per Mcf including realized gains from natural gas derivatives) for our natural gas production for the year ended December 31, 2013 , as compared to $2.59 per Mcf ( $3.55 per Mcf including realized gains from natural gas derivatives) for the year ended December 31, 2012 . At March 13, 2014 , the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $4.38 per MMBtu, as compared to $3.68 per MMBtu at March 13, 2013. 
+Most of our Eagle Ford shale oil production in South Texas is sold based on a Louisiana Light Sweet oil price index less transportation costs. Although we realized significant uplifts to West Texas Intermediate oil prices at times during 2013, the differential between these two benchmark prices has decreased since early 2013. We may not realize similar, or any, uplifts to 
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+Table of Contents 
+West Texas Intermediate oil prices in future periods, which could result in a decrease in our weighted average oil price realized and associated oil revenues. Additionally, we expect oil production from our properties in the Permian Basin will be sold on a West Texas Intermediate oil price index less transportation costs. 
+The prices we receive for oil, natural gas and natural gas liquids heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil, natural gas and natural gas liquids are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. Declines in oil, natural gas or natural gas liquids prices not only reduce our revenue, but could also reduce the amount of oil, natural gas and natural gas liquids we can produce economically. From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. Even so, decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil, natural gas and natural gas liquids prices, and we may not always employ the optimal hedging strategy. Should oil, natural gas or natural gas liquids prices decrease to economically unattractive levels and remain there for an extended period of time, we may elect to delay some of our exploration and development plans for our prospects, or cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition, results of operations and reserves. This, in turn, may affect the liquidity that can be accessed through the borrowing base under our Credit Agreement and through the capital markets. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+Like other oil and natural gas producing companies, our properties are subject to natural production declines. By their nature, our oil and natural gas wells will experience rapid initial production declines. We attempt to overcome these production declines by drilling to develop and identify additional reserves, by exploring for new sources of reserves and, at times, by acquisitions. During times of severe oil, natural gas and natural gas liquids price declines, however, drilling additional oil or natural gas wells may not be economical, and we may find it necessary to reduce capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially impact our production volumes, revenues, reserves, cash flows and our availability under our Credit Agreement. See “Risk Factors — Our Exploration, Development and Exploitation Projects Require Substantial Capital Expenditures That May Exceed Our Cash Flows from Operations and Potential Borrowings, and We May Be Unable to Obtain Needed Capital on Satisfactory Terms, Which Could Adversely Affect Our Future Growth.” 
+We strive to focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our ability to find and develop sufficient quantities of oil and natural gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the costs of acquiring, drilling and completing our prospects. 
+Critical Accounting Policies and Estimates 
+The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, revenues and expenses during each reporting period. We believe that our estimates and assumptions are reasonable and reliable, and believe that the actual results will not differ significantly from those reported; however, such estimates and assumptions are subject to a number of risks and uncertainties, and such risks and uncertainties could cause the actual results to differ materially from our estimates. We consider the following to be our most critical accounting policies and estimates involving significant judgment or estimates by our management. See “Note 2 — Summary of Significant Accounting Policies” to the consolidated financial statements in this Annual Report on Form 10-K for further details on our accounting policies at December 31, 2013. Such information is incorporated herein by reference. 
+Property and Equipment 
+We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred. These costs are accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses 
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+directly related to exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. 
+The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling”. The cost center ceiling is defined as the sum of: 
+(a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus 
+(b) unproved and unevaluated property costs not being amortized, plus 
+(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less 
+(d) income tax effects related to the properties involved. 
+Any excess of our net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of our derivative instruments is not included in the ceiling test computation as we do not designate these instruments as hedge instruments for accounting purposes. 
+The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using commodity prices that represent the arithmetic average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period, and the guidelines further dictate that a 10% discount factor be used to determine the present value of future net revenues. 
+Because the cost center ceiling calculation is based on the average of historical prices, which may or may not be representative of future prices, and requires a 10% discount factor, the resulting estimated value may not be indicative of the fair market value of our properties. Any impairment related to the excess of our net capitalized costs above the resulting cost center ceiling should not be viewed as an absolute indicator of a reduction in the ultimate value of the related reserves. 
+Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. 
+Impairment 
+Unproved and unevaluated properties are assessed for impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon the determination that the well is not productive. 
+Derivative Financial Instruments 
+From time to time, we use derivative financial instruments to mitigate our exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. 
+Prior to settlement, our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for our existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in our consolidated statement of operations. Such changes in fair value are reported under “Revenue” as “Unrealized gain (loss) on derivatives”. Changes in the fair value of these open derivative financial instruments can have a significant impact on our reported results from period to period but do not impact our cash flow from operations, liquidity or capital resources. The fair value of our derivative financial 
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+instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. 
+Realized gains and realized losses from the settlement of derivative financial instruments do have a direct impact on our cash flow from operations and liquidity. The impact of these settlements is also reported under “Revenue” as “Realized gain (loss) on derivatives”. 
+Revenue Recognition 
+We follow the sales method of accounting for our oil, natural gas and natural gas liquids revenue, whereby we recognize revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to our ownership in the property. Under this method, revenue is recognized at the time the oil, natural gas and natural gas liquids are produced and sold, and we accrue for revenue earned but not yet received. 
+Stock-based Compensation 
+We account for stock-based compensation in accordance with ASC 718. During 2013 and 2012 , all stock option awards were granted under our 2012 Long-Term Incentive Plan and were equity instruments. We did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under our 2003 Stock and Incentive Plan, and since November 22, 2010, these awards have been accounted for as liability instruments. We used the fair value method to measure and recognize the liability associated with our outstanding liability-based stock options and to measure and recognize the equity associated with our equity-based stock options. Stock options typically vest over three or four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Restricted stock and restricted stock units typically vest over a period of one to four years, and compensation expense is recognized on a straight line basis over the vesting period. As our shares were not publicly traded prior to February 2, 2012, we estimated the future volatility of our stock using the historical volatility of the common stock of a group of companies we consider to be a representative peer group. Management believes that these average historical volatility rates are currently the best available indicator of future volatility. 
+We have adopted the “simplified method” as outlined in Staff Accounting Bulletin Topic 14 for estimating the expected term of awards. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. 
+Assumptions are reviewed each time new equity-based option awards are granted and quarterly for outstanding liability-based option awards. The assumptions used may be impacted by actual fluctuations in our stock price, movements in market interest rates and option terms. The use of different assumptions produces a different fair value for equity-based option awards and outstanding liability-based option awards and can significantly impact the amount of stock compensation expense recognized in our consolidated statement of operations. We use the Black Scholes Merton model to determine the fair value of service-based option awards and the Monte Carlo method to determine the fair value of option awards that contain a market condition. The fair value of restricted stock and restricted stock unit awards are recognized based on the fair value of our stock on the date of the grant. See “Note 8 — Stock-Based Compensation” to the consolidated financial statements in this Annual Report on Form 10-K for further details on our stock-based compensation at December 31, 2013. Such information is incorporated herein by reference. 
+Income Taxes 
+We account for income taxes using the asset and liability approach for financial accounting and reporting. The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state taxing authorities. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and tax carryforwards. We evaluate the probability of realizing the future benefits of our deferred tax assets and provide a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. 
+We account for uncertainty in income taxes by recognizing the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. 
+Oil and Natural Gas Reserves Quantities and Standardized Measure of Future Net Revenue 
+Our engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the applicable rules allow us to disclose proved, probable and possible reserves, we have elected to present only proved 
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+reserves in this Annual Report on Form 10-K. The applicable rules define proved reserves as the quantities of oil and natural gas, 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 economic 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 
+Our engineers and technical staff must make many subjective assumptions based on their professional judgment in developing reserves estimates. Reserves estimates are updated at least annually and consider recent production levels and other technical information about each well. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, development expenditures, operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas will most likely vary from our estimates. Accordingly, reserves estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Any significant variance could materially and adversely affect our future reserves estimates, financial position, results of operations and cash flows. We cannot predict the amounts or timing of future reserves revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. See “Risk Factors — Our Oil and Natural Gas Reserves Are Estimated and May Not Reflect the Actual Volumes of Oil and Natural Gas We Will Recover, and Significant Inaccuracies in These Reserves Estimates or Underlying Assumptions Will Materially Affect the Quantities and Present Value of Our Reserves.” 
+Recent Accounting Pronouncements 
+Balance Sheet. In January 2013, the FASB issued Accounting Standards Update, or ASU, 2013-01, Balance Sheet. The ASU clarifies the scope of ASU 2011-11 to limit the application of ASU 2011-11 to derivatives accounted for in accordance with Accounting Standards Codification, or ASC, 815, Derivatives and Hedging , including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. We adopted ASU 2013-01 effective January 1, 2013, together with the adoption of ASU 2011-11. The adoption of ASUs 2013-01 and 2011-11 did not have a material effect on our consolidated financial statements, but did require certain additional disclosures (see “Note 11 — Derivative Financial Instruments” to the consolidated financial statements in this Annual Report on Form 10-K). 
+Balance Sheet. In December 2011, the FASB issued ASU 2011-11, Balance Sheet . The requirements amend the disclosure requirements to offsetting in ASC 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting agreement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. We adopted ASU 2011-11 effective January 1, 2013, together with the adoption of ASU 2013-01. The adoption of ASUs 2011-11 and 2013-01 did not have a material effect on our consolidated financial statements, but did require certain additional disclosures (see “Note 11 — Derivative Financial Instruments” to the consolidated financial statements in this Annual Report on Form 10-K). 
+Item 7A. Quantitative and Qualitative Disclosures about Market Risk. 
+We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative financial instruments, but we do not enter into derivative financial instruments for trading purposes. 
+Commodity price exposure. We are exposed to market risk as the prices of oil, natural gas and natural gas liquids fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative financial instruments in the past and expect to enter into derivative financial instruments in the future to cover a significant portion of our future anticipated production. 
+We use costless (or zero-cost) collars and/or swap contracts to manage risks related to changes in oil, natural gas and natural gas liquids prices. Costless collars provide us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to us. In the case of a costless collar, the put option and the call option have different 
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+fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. 
+We record all derivative financial instruments at fair value. The fair value of our derivative financial instruments is determined using purchase and sale information available for similarly traded securities. At December 31, 2013 , Comerica Bank, RBC, The Bank of Nova Scotia and SunTrust Bank (or affiliates thereof) were the counterparties for all of our derivative instruments. We have evaluated the credit standing of the counterparties in determining the fair value of our derivative financial instruments. 
+We have entered into various costless collar contracts to mitigate our exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these oil hedging transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. 
+We have entered into various costless collar contracts to mitigate our exposure to fluctuations in natural gas prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to us pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. When the settlement price is below the price floor established by one or more of these collars, we receive from our counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, we pay our counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. 
+We have entered into various swap contracts to mitigate our exposure to fluctuations in NGL prices, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to us pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity on the pricing date. When the settlement price is below the fixed price established by one or more of these swaps, we receive from our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, we pay to our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. 
+See “Note 11 — Derivative Financial Instruments” to the consolidated financial statements in this Annual Report on Form 10-K for a summary of our open derivative financial instruments at December 31, 2013. Such information is incorporated herein by reference. 
+Effect of Recent Derivatives Legislation. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which is intended to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, establishes federal oversight and regulation of certain derivative products including commodity hedges of the type we use. The Dodd-Frank Act requires the Commodity Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on our derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. See “Risk Factors — The Derivatives Legislation Adopted by Congress Could Have an Adverse Impact on Our Ability to Hedge Risks Associated with Our Business.” 
+Interest rate risk. We do not and have not used interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense on existing debt since we borrowed under our Credit Agreement for the first time in December 2010. At December 31, 2013 we had $200.0 million in revolving borrowings outstanding under our Credit Agreement at an interest rate of approximately 3.3% per annum. If we incur additional indebtedness in the future and at higher interest rates, we 
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+may use interest rate derivatives. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio. 
+Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial position, results of operations and cash flows. In addition, our oil, natural gas and natural gas liquids derivative arrangements expose us to credit risk in the event of nonperformance by our counterparties. 
+While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation requires us to conduct the due diligence necessary to determine credit terms and credit limits, which may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record and the financial ability of its parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative financial instruments in place at March 13, 2014 were RBC, Comerica Bank, The Bank of Nova Scotia and SunTrust Bank (or affiliates thereof) and we are likely to enter into any future derivative instruments with RBC, Comerica Bank, The Bank of Nova Scotia, SunTrust Bank or other lenders (or affiliates thereof) party to the Credit Agreement. 
+Impact of Inflation . Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 and 2011 . Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the U.S. economy and we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations, including the Eagle Ford shale play, the Wolfcamp and Bone Spring plays in the Permian Basin, and the Haynesville shale play. See “Business — General.” See also “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+Item 8. Financial Statements and Supplementary Data. 
+Our financial statements appear at the end of this Annual Report on Form 10-K. See the index to the financial statements in Item 15. 
+Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. 
+Not applicable. 
+Item 9A. Controls and Procedures. 
+Evaluation of Disclosure Controls and Procedures 
+As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2013 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. 
+Changes in Internal Control over Financial Reporting 
+During the quarter ended December 31, 2013 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. 
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+Management’s Report on Internal Control over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in 1992 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. 
+Grant Thornton LLP, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2013 as included herein. 
+Important Considerations 
+The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. 
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+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Matador Resources Company 
+We have audited the internal control over financial reporting of Matador Resources Company (a Texas corporation) and subsidiaries (collectively 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 March 17, 2014 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas 
+March 17, 2014 
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+Item 9B. Other Information. 
+None. 
+PART III 
+Item 10. Directors, Executive Officers and Corporate Governance. 
+The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 11. Executive Compensation. 
+The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. 
+Certain information regarding securities authorized for issuance under our equity compensation plans is included under the caption “Equity Compensation Plan Information” in Part II, Item 5, above, of this Annual Report on Form 10-K and is incorporated by reference herein. Other information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
+Item 14. Principal Accounting Fees and Services. 
+The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. 
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+PART IV 
+Item 15. Exhibits and Financial Statement Schedules. 
+The following documents are filed as part of this Annual Report on Form 10-K: 
+1. Index to Consolidated Financial Statements, Report of Independent Registered Public Accounting Firm, Consolidated Balance Sheets as of December 31, 2013 and 2012 , Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011 , Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011 and Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011 . 
+2. Exhibits : The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K. 
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+EXHIBIT INDEX 
+Exhibit 
+Number 
+Description 
+2.1 
+Agreement and Plan of Merger, by and among Matador Resources Company (now known as MRC Energy Company), Matador Holdco, Inc. (now known as Matador Resources Company) and Matador Merger Co., dated August 8, 2011 (incorporated by reference to Exhibit 2.1 to our Registration Statement on Form S-1 filed on August 12, 2011). 
+3.1 
+Certificate of Merger between Matador Resources Company (now known as MRC Energy Company) and Matador Merger Co. (incorporated by reference to Exhibit 3.4 to our Registration Statement on Form S-1 filed on August 12, 2011). 
+3.2 
+Amended and Restated Certificate of Formation of Matador Resources Company (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on February 13, 2012). 
+3.3 
+Amended and Restated Bylaws of Matador Resources Company (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on February 13, 2012). 
+4.1 
+Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to our Registration Statement on Form S-1 filed on January 19, 2012). 
+10.1† 
+Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.3 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.2† 
+Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.4 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.3† 
+Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.5 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.4† 
+Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.6 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.5† 
+Independent Contractor Agreement between Matador Resources Company and David F. Nicklin (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.6† 
+First Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.7† 
+First Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.8† 
+First Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.9† 
+First Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.10† 
+Second Amendment to the Employment Agreement between Matador Resources Company and Joseph Wm. Foran (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.11† 
+Second Amendment to the Employment Agreement between Matador Resources Company and David E. Lancaster (incorporated by reference to Exhibit 10.13 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.12† 
+Second Amendment to the Employment Agreement between Matador Resources Company and Matthew Hairford (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+80 
+Table of Contents 
+10.13† 
+Second Amendment to the Employment Agreement between Matador Resources Company and Bradley M. Robinson (incorporated by reference to Exhibit 10.15 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.14† 
+First Amendment to the Independent Contractor Agreement between Matador Resources Company and David F. Nicklin (incorporated by reference to Exhibit 10.16 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.15† 
+2012 Long-Term Incentive Plan of Matador Resources Company (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.16† 
+First Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated April 16, 2012 (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.17† 
+Second Amendment to the Matador Resources Company 2012 Long-Term Incentive Plan dated March 8, 2013 (incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended December 31, 2012). 
+10.18† 
+Matador Resources Company Annual Incentive Plan for Management and Key Employees (incorporated by reference to Exhibit 10.18 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.19† 
+Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated October 23, 2003 (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.20† 
+First Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated January 29, 2004 (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.21† 
+Second Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 3, 2005 (incorporated by reference to Exhibit 10.17 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.22† 
+Third Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 1, 2006 (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.23† 
+Fourth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated May 1, 2006 (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.24† 
+Fifth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated February 13, 2008 (incorporated by reference to Exhibit 10.20 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.25† 
+Sixth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated August 5, 2008 (incorporated by reference to Exhibit 10.21 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.26† 
+Seventh Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated December 12, 2011 (incorporated by reference to Exhibit 10.26 to Amendment No. 2 to our Registration Statement on Form S-1 filed on December 30, 2011). 
+10.27† 
+Eighth Amendment to Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan, dated March 8, 2013 (incorporated by reference to Exhibit 10.27 to the Annual Report on Form 10-K for the year ended December 31, 2012). 
+10.28† 
+Form of Indemnification Agreement between Matador Resources Company and each of the directors and executive officers thereof (incorporated by reference to Exhibit 10.22 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.29 
+Participation Agreement, by and among MRC Rockies Company, Matador Resources Company (now known as MRC Energy Company), Matador Production Company, Roxanna Rocky Mountains, LLC, Roxanna Oil, Inc., Alliance Capital Real Estate, Inc. and AllianceBernstein L.P., dated at May 14, 2010 (incorporated by reference to Exhibit 10.23 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+81 
+Table of Contents 
+10.30 
+Amendment, dated as of September 11, 2012, to Participation Agreement dated May 14, 2010, by and among MRC Rockies Company, Matador Resources Company (now known as MRC Energy Company), Matador Production Company, Roxanna Rocky Mountains, LLC, Roxanna Oil, Inc., Alliance Capital Real Estate, Inc. and Kimmeridge Energy Exploration Fund, L.P. (successor in interest to AllianceBernstein L.P.) (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2012). 
+10.31 
+Purchase, Sale and Participation Agreement, by and between Matador Resources Company (now known as MRC Energy Company) and Orca ICI Development, JV, dated at May 16, 2011 (incorporated by reference to Exhibit 10.25 to Amendment No. 1 to our Registration Statement on Form S-1 filed on November 14, 2011). 
+10.32 
+First Amendment to Purchase Sale and Participation Agreement, dated as of June 12, 2013, by and between MRC Energy Company and Orca/ICI Development (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). 
+10.33† 
+Form of Non-Qualified Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.34† 
+Form of Incentive Stock Option Agreement granted pursuant to the Matador Resources Company (now known as MRC Energy Company) 2003 Stock and Incentive Plan (incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.35† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.38 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.36† 
+Form of Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.37† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to the Annual Report on Form 10-K for the year ended December 31, 2011). 
+10.38† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.39† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.40† 
+Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees without employment agreements (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.41† 
+Form of Nonqualified Stock Option Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.42† 
+Form of Restricted Stock Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.43† 
+Form of Performance Restricted Stock and Restricted Stock Unit Award Agreement relating to the Matador Resources Company 2012 Long-Term Incentive Plan for employees with employment agreements (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). 
+10.44 
+Third Amended and Restated Credit Agreement, dated as of September 28, 2012, by and among MRC Energy Company, as Borrower, the Lending Entities from time to time parties thereto, as Lenders, and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 4, 2012). 
+10.45 
+Second Amended and Restated Pledge and Security Agreement, by and among MRC Energy Company, Longwood Gathering and Disposal Systems GP, Inc. and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the year ended December 31, 2012). 
+82 
+Table of Contents 
+10.46 
+Second Amended, Restated and Consolidated Unconditional Guaranty, by and among MRC Permian Company, MRC Rockies Company, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., Longwood Gathering and Disposal Systems, LP, Matador Resources Company and Royal Bank of Canada, as Administrative Agent, dated as of September 28, 2012 (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the year ended December 31, 2012). 
+10.47 
+First Amendment to Third Amended and Restated Credit Agreement dated as of March 11, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the year ended December 31, 2012). 
+10.48 
+Second Amendment to Third Amended and Restated Credit Agreement dated as of June 4, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed June 6, 2013). 
+10.49 
+Third Amendment to Third Amended and Restated Credit Agreement, dated as of August 7, 2013, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). 
+10.50 
+Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of March 12, 2014, by and among MRC Energy Company, as Borrower, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (filed herewith). 
+10.51† 
+Form of Employment Agreement between Matador Resources Company and each of Craig N. Adams and Ryan C. London (filed herewith). 
+21.1 
+List of Subsidiaries of Matador Resources Company (filed herewith). 
+23.1 
+Consent of Grant Thornton LLP (filed herewith). 
+23.2 
+Consent of Netherland, Sewell & Associates, Inc. (filed herewith). 
+31.1 
+Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+31.2 
+Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+32.1 
+Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+32.2 
+Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). 
+99.1 
+Audit report of Netherland, Sewell & Associates, Inc. (filed herewith). 
+101* 
+The following financial information from Matador Resources Company’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statement of Changes in Shareholders’ Equity, (iv) the Consolidated Statements of Cash Flows and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith). 
+† 
+Indicates a management contract or compensatory plan or arrangement. 
+* 
+In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this Annual Report on Form 10-K shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. 
+83 
+Table of Contents 
+SIGNATURES 
+Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. 
+MATADOR RESOURCES COMPANY 
+March 17, 2014 
+By: 
+/s/ Joseph Wm. Foran 
+Joseph Wm. Foran 
+Chairman and Chief Executive Officer 
+Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K 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/ Joseph Wm. Foran 
+Chairman and Chief Executive Officer (Principal Executive Officer) 
+March 17, 2014 
+Joseph Wm. Foran 
+/s/ David E. Lancaster 
+Executive Vice President, 
+Chief Operating Officer and 
+Chief Financial Officer 
+(Principal Financial Officer) 
+March 17, 2014 
+David E. Lancaster 
+/s/ Sandra K. Fendley 
+Vice President and Chief Accounting Officer (Principal Accounting Officer) 
+March 17, 2014 
+Sandra K. Fendley 
+/s/ Stephen A. Holditch 
+Director 
+March 17, 2014 
+Stephen A. Holditch 
+/s/ David M. Laney 
+Director 
+March 17, 2014 
+David M. Laney 
+/s/ Gregory E. Mitchell 
+Director 
+March 17, 2014 
+Gregory E. Mitchell 
+/s/ Steven W. Ohnimus 
+Director 
+March 17, 2014 
+Steven W. Ohnimus 
+/s/ Michael C. Ryan 
+Director 
+March 17, 2014 
+Michael C. Ryan 
+/s/ Carlos M. Sepulveda, Jr. 
+Director 
+March 17, 2014 
+Carlos M. Sepulveda, Jr. 
+/s/ Margaret B. Shannon 
+Director 
+March 17, 2014 
+Margaret B. Shannon 
+84 
+Table of Contents 
+GLOSSARY OF OIL AND NATURAL GAS TERMS 
+The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. 
+Bbl . One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report on Form 10-K in reference to crude oil or other liquid hydrocarbons. 
+Bcf . One billion cubic feet. 
+BOE . Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. 
+BOE/d . BOE per day. 
+Btu or British thermal unit . The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. 
+Completion . The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. 
+Condensate . Liquid hydrocarbons associated with the production of a primarily natural gas reservoir. 
+Conventional resources . Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore. 
+Coring . The act of taking a core. A core is a solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation. It is common practice to take cores from wells in the process of being drilled. A core bit is attached to the end of the drill pipe. The core bit then cuts a column of rock from the formation being penetrated. The core is then removed and tested for evidence of oil or natural gas, and its characteristics (porosity, permeability, etc.) are determined. 
+Developed acreage . The number of acres that are allocated or assignable to productive wells. 
+Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. 
+Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production-related expenses and taxes. 
+Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. 
+Farmin or farmout . An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.” 
+FERC . Federal Energy Regulatory Commission. 
+Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 
+Gross acres or gross wells . The total acres or wells in which a working interest is owned. 
+Held by production . An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property. 
+Horizontal drilling or well . A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption. 
+85 
+Table of Contents 
+Hydraulic fracturing . The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to prop the channel open, so that fluids or gases may more easily flow from the formation, through the fracture channel and into the wellbore. This technique may also be referred to as fracture stimulation. 
+Liquids . Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane and pentane resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility. 
+MBbl . One thousand barrels of crude oil or other liquid hydrocarbons. 
+MBOE . One thousand BOE. 
+Mcf . One thousand cubic feet of natural gas. 
+Mcfe . One thousand cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. 
+MMBtu . One million British thermal units. 
+MMcf . One million cubic feet of natural gas. 
+NGL . Natural gas liquids. 
+Net acres or net wells . The sum of the fractional working interest owned in gross acres or wells. 
+Net revenue interest . The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well. 
+NYMEX . New York Mercantile Exchange. 
+Overriding royalty interest . A fractional interest in the gross production of oil and natural gas under a lease, in addition to the usual royalties paid to the lessor, free of any expense for exploration, drilling, development, operating, marketing and other costs incident to the production and sale of oil and natural gas produced from the lease. It is an interest carved out of the lessee’s working interest, as distinguished from the lessor’s reserved royalty interest. 
+Permeability . A reference to the ability of oil and/or natural gas to flow through a reservoir. 
+Petrophysical analysis . The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties. 
+Play . A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type. 
+Possible reserves . Additional reserves that are less certain to be recognized than probable reserves. 
+Probable reserves . Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. 
+Producing well, or productive well . A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes. 
+Properties . Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee, leasehold and related interests. 
+Prospect . A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons. 
+Proved developed non-producing . Hydrocarbons in a potentially producing horizon penetrated by a wellbore, the production of which has been postponed pending installation of surface equipment or gathering facilities, or pending the production of hydrocarbons from another formation penetrated by the wellbore. The hydrocarbons are classified as proved but non-producing reserves. 
+86 
+Table of Contents 
+Proved developed reserves . Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. 
+Proved reserves . Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. 
+Proved undeveloped reserves . 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. 
+Recompletion . Completing in the same wellbore to reach a new reservoir after production from the original reservoir has been abandoned. 
+Repeatability . The potential ability to drill multiple wells within a prospect or trend. 
+Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 
+Royalty interest . An interest in an oil and natural gas 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. 
+2-D seismic . The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile. 
+3-D seismic . The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production. 
+Spud . The act of beginning to drill an oil or natural gas well. 
+Trend . A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations. 
+Unconventional resource play . A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (i) low-permeability sandstone and shale formations and (ii) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources. 
+Undeveloped acreage . Lease 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. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells. 
+Unproved and unevaluated properties . Properties where no drilling or other actions have been undertaken that permit such property to be classified as proved. 
+Vertical well . A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped. 
+Visualization . An exploration technique in which the size and shape of subsurface features are mapped and analyzed based upon information derived from well logs, seismic data and other well information. 
+Volumetric reserve analysis . A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for rock porosity, hydrocarbon saturation, formation volume factor and recovery factor. 
+Wellbore . The hole made by a well. 
+Working interest . The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. 
+87 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED FINANCIAL STATEMENTS 
+December 31, 2013, 2012 and 2011 
+Contents 
+Report of Independent Registered Public Accounting Firm 
+F-2 
+Consolidated Financial Statements 
+Consolidated Balance Sheets as of December 31, 2013 and 2012 
+F-3 
+Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011 
+F-4 
+Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2013, 2012 and 2011 
+F-5 
+Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011 
+F-6 
+Notes to Consolidated Financial Statements 
+F-7 
+Unaudited Supplementary Information 
+F-42 
+F- 1 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Matador Resources Company 
+We have audited the accompanying consolidated balance sheets of Matador Resources Company (a Texas corporation) and subsidiaries (collectively the “Company”) as of December 31, 2013 and 2012 , and the related consolidated statements of operations, changes in shareholders’ 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 Matador Resources Company 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 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 17, 2014 expressed an unqualified opinion thereon. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas 
+March 17, 2014 
+F- 2 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED BALANCE SHEETS 
+(In thousands, except par value and share data) 
+December 31, 
+2013 
+2012 
+ASSETS 
+Current assets 
+Cash 
+$ 
+6,287 
+$ 
+2,095 
+Certificates of deposit 
+— 
+230 
+Accounts receivable 
+Oil and natural gas revenues 
+25,823 
+24,422 
+Joint interest billings 
+4,785 
+4,118 
+Other 
+1,066 
+974 
+Derivative instruments 
+19 
+4,378 
+Deferred income taxes 
+1,636 
+— 
+Lease and well equipment inventory 
+785 
+877 
+Prepaid expenses 
+1,771 
+1,103 
+Total current assets 
+42,172 
+38,197 
+Property and equipment, at cost 
+Oil and natural gas properties, full-cost method 
+Evaluated 
+1,090,656 
+763,527 
+Unproved and unevaluated 
+194,306 
+149,675 
+Other property and equipment 
+29,910 
+27,258 
+Less accumulated depletion, depreciation and amortization 
+(468,995 
+) 
+(349,370 
+) 
+Net property and equipment 
+845,877 
+591,090 
+Other assets 
+Derivative instruments 
+173 
+771 
+Deferred income taxes 
+— 
+411 
+Other assets 
+2,108 
+1,560 
+Total other assets 
+2,281 
+2,742 
+Total assets 
+$ 
+890,330 
+$ 
+632,029 
+LIABILITIES AND SHAREHOLDERS’ EQUITY 
+Current liabilities 
+Accounts payable 
+$ 
+25,358 
+$ 
+28,120 
+Accrued liabilities 
+63,987 
+59,179 
+Royalties payable 
+7,798 
+6,541 
+Derivative instruments 
+2,692 
+670 
+Advances from joint interest owners 
+— 
+1,515 
+Deferred income taxes 
+— 
+411 
+Income taxes payable 
+404 
+— 
+Other current liabilities 
+88 
+56 
+Total current liabilities 
+100,327 
+96,492 
+Long-term liabilities 
+Borrowings under Credit Agreement 
+200,000 
+150,000 
+Asset retirement obligations 
+7,309 
+5,109 
+Derivative instruments 
+253 
+— 
+Deferred income taxes 
+10,929 
+— 
+Other long-term liabilities 
+2,588 
+1,324 
+Total long-term liabilities 
+221,079 
+156,433 
+Commitments and contingencies (Note 13) 
+Shareholders’ equity 
+Common stock — Class A, $0.01 par value, 80,000,000 shares authorized; 66,958,867 and 56,778,718 shares issued; and 65,652,690, and 55,577,667 shares outstanding, respectively 
+670 
+568 
+Additional paid-in capital 
+548,935 
+404,311 
+Retained earnings (deficit) 
+30,084 
+(15,010 
+) 
+Treasury stock, at cost, 1,306,177 and 1,201,051 shares, respectively 
+(10,765 
+) 
+(10,765 
+) 
+Total shareholders’ equity 
+568,924 
+379,104 
+Total liabilities and shareholders’ equity 
+$ 
+890,330 
+$ 
+632,029 
+The accompanying notes are an integral part of these financial statements. 
+F- 3 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF OPERATIONS 
+(In thousands, except per share data) 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Revenues 
+Oil and natural gas revenues 
+$ 
+269,030 
+$ 
+155,998 
+$ 
+67,000 
+Realized (loss) gain on derivatives 
+(909 
+) 
+13,960 
+7,106 
+Unrealized (loss) gain on derivatives 
+(7,232 
+) 
+(4,802 
+) 
+5,138 
+Total revenues 
+260,889 
+165,156 
+79,244 
+Expenses 
+Production taxes and marketing 
+20,973 
+11,672 
+6,278 
+Lease operating 
+38,720 
+28,184 
+7,244 
+Depletion, depreciation and amortization 
+98,395 
+80,454 
+31,754 
+Accretion of asset retirement obligations 
+348 
+256 
+209 
+Full-cost ceiling impairment 
+21,229 
+63,475 
+35,673 
+General and administrative 
+20,779 
+14,543 
+13,394 
+Total expenses 
+200,444 
+198,584 
+94,552 
+Operating income (loss) 
+60,445 
+(33,428 
+) 
+(15,308 
+) 
+Other income (expense) 
+Net loss on asset sales and inventory impairment 
+(192 
+) 
+(485 
+) 
+(154 
+) 
+Interest expense 
+(5,687 
+) 
+(1,002 
+) 
+(683 
+) 
+Interest and other income 
+225 
+224 
+315 
+Total other expense 
+(5,654 
+) 
+(1,263 
+) 
+(522 
+) 
+Income (loss) before income taxes 
+54,791 
+(34,691 
+) 
+(15,830 
+) 
+Income tax provision (benefit) 
+Current 
+404 
+— 
+(46 
+) 
+Deferred 
+9,293 
+(1,430 
+) 
+(5,475 
+) 
+Total income tax provision (benefit) 
+9,697 
+(1,430 
+) 
+(5,521 
+) 
+Net income (loss) 
+$ 
+45,094 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Class B 
+$ 
+— 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+Diluted 
+Class A 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Class B 
+$ 
+— 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+Weighted average common shares outstanding 
+Basic 
+Class A 
+58,777 
+53,852 
+41,687 
+Class B 
+— 
+105 
+1,031 
+Total 
+58,777 
+53,957 
+42,718 
+Diluted 
+Class A 
+58,929 
+53,852 
+41,687 
+Class B 
+— 
+105 
+1,031 
+Total 
+58,929 
+53,957 
+42,718 
+The accompanying notes are an integral part of these financial statements. 
+F- 4 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY 
+For the Years Ended December 31, 2013, 2012 and 2011 
+(In thousands) 
+Common Stock 
+Additional 
+paid-in 
+capital 
+Retained earnings (deficit ) 
+Treasury Stock 
+Total 
+Class A 
+Class B 
+Shares 
+Amount 
+Shares 
+Amount 
+Shares 
+Amount 
+Balance at January 1, 2011 
+42,750 
+$ 
+427 
+1,031 
+$ 
+10 
+$ 
+263,342 
+$ 
+28,863 
+1,179 
+$ 
+(10,765 
+) 
+$ 
+281,877 
+Issuance of Class A common stock 
+54 
+1 
+— 
+— 
+591 
+— 
+— 
+— 
+592 
+Cost to issue equity 
+— 
+— 
+— 
+— 
+(1,667 
+) 
+— 
+— 
+— 
+(1,667 
+) 
+Issuance of Class A common stock to Board members and advisors 
+20 
+— 
+— 
+— 
+230 
+— 
+— 
+— 
+230 
+Stock options exercised 
+93 
+1 
+— 
+— 
+1,022 
+— 
+— 
+— 
+1,023 
+Restricted stock vested 
+— 
+— 
+— 
+— 
+44 
+— 
+— 
+— 
+44 
+Class B dividends declared 
+— 
+— 
+— 
+— 
+— 
+(275 
+) 
+— 
+— 
+(275 
+) 
+Current period net loss 
+— 
+— 
+— 
+— 
+— 
+(10,309 
+) 
+— 
+— 
+(10,309 
+) 
+Balance at December 31, 2011 
+42,917 
+429 
+1,031 
+10 
+263,562 
+18,279 
+1,179 
+(10,765 
+) 
+271,515 
+Issuance of Class A common stock 
+12,209 
+122 
+— 
+— 
+146,388 
+— 
+— 
+— 
+146,510 
+Cost to issue equity 
+— 
+— 
+— 
+— 
+(11,268 
+) 
+— 
+— 
+— 
+(11,268 
+) 
+Conversion of Class B common stock to Class A common stock 
+1,031 
+10 
+(1,031 
+) 
+(10 
+) 
+— 
+— 
+— 
+— 
+— 
+Issuance of Class A common stock to Board members and advisors 
+7 
+— 
+— 
+— 
+71 
+— 
+— 
+— 
+71 
+Stock options expense related to equity- based awards 
+— 
+— 
+— 
+— 
+432 
+— 
+— 
+— 
+432 
+Stock options exercised 
+296 
+3 
+— 
+— 
+3,541 
+— 
+— 
+— 
+3,544 
+Liability-based stock option awards settled 
+— 
+— 
+— 
+— 
+216 
+— 
+— 
+— 
+216 
+Changes in fair value for liability-based awards for which grant date fair value is in excess of fair value 
+— 
+— 
+— 
+— 
+620 
+— 
+— 
+— 
+620 
+Restricted stock issued 
+319 
+4 
+— 
+— 
+(4 
+) 
+— 
+— 
+— 
+— 
+Restricted stock forfeited 
+— 
+— 
+— 
+— 
+(29 
+) 
+— 
+22 
+— 
+(29 
+) 
+Restricted stock and restricted stock units expense 
+— 
+— 
+— 
+— 
+758 
+— 
+— 
+— 
+758 
+Swing sale profit contribution 
+— 
+— 
+— 
+— 
+24 
+— 
+— 
+— 
+24 
+Class B dividends declared 
+— 
+— 
+— 
+— 
+— 
+(28 
+) 
+— 
+— 
+(28 
+) 
+Current period net loss 
+— 
+— 
+— 
+— 
+— 
+(33,261 
+) 
+— 
+— 
+(33,261 
+) 
+Balance at December 31, 2012 
+56,779 
+568 
+— 
+— 
+404,311 
+(15,010 
+) 
+1,201 
+(10,765 
+) 
+379,104 
+Issuance of common stock 
+9,780 
+98 
+— 
+— 
+148,971 
+— 
+— 
+— 
+149,069 
+Cost to issue equity 
+— 
+— 
+— 
+— 
+(7,390 
+) 
+— 
+— 
+— 
+(7,390 
+) 
+Common stock issued to Board advisors 
+22 
+— 
+— 
+— 
+57 
+— 
+— 
+— 
+57 
+Stock options expense related to equity-based awards 
+— 
+— 
+— 
+— 
+1,232 
+— 
+— 
+— 
+1,232 
+Liability-based stock option awards settled 
+— 
+— 
+— 
+— 
+162 
+— 
+— 
+— 
+162 
+Restricted stock issued 
+378 
+4 
+— 
+— 
+(4 
+) 
+— 
+— 
+— 
+— 
+Restricted stock forfeited 
+— 
+— 
+— 
+— 
+(22 
+) 
+— 
+105 
+— 
+(22 
+) 
+Restricted stock and restricted stock units expense 
+— 
+— 
+— 
+— 
+1,618 
+— 
+— 
+— 
+1,618 
+Current period net income 
+— 
+— 
+— 
+— 
+— 
+45,094 
+— 
+— 
+45,094 
+Balance at December 31, 2013 
+66,959 
+$ 
+670 
+— 
+$ 
+— 
+$ 
+548,935 
+$ 
+30,084 
+1,306 
+$ 
+(10,765 
+) 
+$ 
+568,924 
+The accompanying notes are an integral part of these financial statements. 
+F- 5 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+CONSOLIDATED STATEMENTS OF CASH FLOWS 
+(In thousands) 
+For the Years Ended December 31, 
+2013 
+2012 
+2011 
+Operating activities 
+Net income (loss) 
+$ 
+45,094 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+Adjustments to reconcile net income (loss) to net cash provided by operating activities 
+Unrealized loss (gain) on derivatives 
+7,232 
+4,802 
+(5,138 
+) 
+Depletion, depreciation and amortization 
+98,395 
+80,454 
+31,754 
+Accretion of asset retirement obligations 
+348 
+256 
+209 
+Full-cost ceiling impairment 
+21,229 
+63,475 
+35,673 
+Stock-based compensation expense 
+3,897 
+140 
+2,406 
+Deferred income tax provision (benefit) 
+9,293 
+(1,430 
+) 
+(5,475 
+) 
+Loss on asset sales and inventory impairment 
+192 
+485 
+154 
+Changes in operating assets and liabilities 
+Accounts receivable 
+(2,160 
+) 
+(16,342 
+) 
+(1,523 
+) 
+Lease and well equipment inventory 
+243 
+50 
+21 
+Prepaid expenses 
+(668 
+) 
+50 
+650 
+Other assets 
+(548 
+) 
+(673 
+) 
+(814 
+) 
+Accounts payable, accrued liabilities and other current liabilities 
+(3,638 
+) 
+19,740 
+13,497 
+Royalties payable 
+1,257 
+4,685 
+873 
+Advances from joint interest owners 
+(1,515 
+) 
+1,515 
+(723 
+) 
+Income taxes payable 
+404 
+— 
+— 
+Other long-term liabilities 
+415 
+282 
+613 
+Net cash provided by operating activities 
+179,470 
+124,228 
+61,868 
+Investing activities 
+Oil and natural gas properties capital expenditures 
+(363,192 
+) 
+(300,689 
+) 
+(156,431 
+) 
+Expenditures for other property and equipment 
+(3,977 
+) 
+(7,332 
+) 
+(4,671 
+) 
+Purchases of certificates of deposit 
+(61 
+) 
+(496 
+) 
+(4,298 
+) 
+Maturities of certificates of deposit 
+291 
+1,601 
+5,312 
+Net cash used in investing activities 
+(366,939 
+) 
+(306,916 
+) 
+(160,088 
+) 
+Financing activities 
+Repayments of borrowings under Credit Agreement 
+(130,000 
+) 
+(123,000 
+) 
+(103,000 
+) 
+Borrowings under Credit Agreement 
+180,000 
+160,000 
+191,000 
+Proceeds from issuance of common stock 
+149,069 
+146,510 
+592 
+Swing sale profit contribution 
+— 
+24 
+— 
+Cost to issue equity 
+(7,390 
+) 
+(11,599 
+) 
+(1,710 
+) 
+Proceeds from stock options exercised 
+— 
+2,660 
+837 
+Taxes paid related to net share settlement of stock-based compensation 
+(18 
+) 
+— 
+— 
+Payment of dividends — Class B 
+— 
+(96 
+) 
+(275 
+) 
+Net cash provided by financing activities 
+191,661 
+174,499 
+87,444 
+Increase (decrease) in cash 
+4,192 
+(8,189 
+) 
+(10,776 
+) 
+Cash at beginning of year 
+2,095 
+10,284 
+21,060 
+Cash at end of year 
+$ 
+6,287 
+$ 
+2,095 
+$ 
+10,284 
+Supplemental disclosures of cash flow information (Note 14) 
+The accompanying notes are an integral part of these financial statements. 
+F- 6 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
+December 31, 2013, 2012 and 2011 
+NOTE 1 — NATURE OF OPERATIONS 
+Matador Resources Company (“Matador” and, collectively with its subsidiaries, the “Company”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Matador’s current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. The Company also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, Matador has a large exploratory leasehold position in Southwest Wyoming and adjacent areas in Utah and Idaho where the Company is testing the Meade Peak shale. 
+On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of a corporate reorganization that was completed on August 9, 2011 and in connection with its initial public offering, the former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company. 
+MRC Energy Company holds the primary assets of the Company and has four wholly-owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts oil and natural gas exploration and development activities in Southeast New Mexico and West Texas. MRC Rockies Company conducts oil and natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal Systems, LP, which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations, transports limited quantities of third-party natural gas and disposes of limited quantities of third-party salt water. 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
+Basis of Presentation 
+The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned subsidiary, MRC Energy Company, as well as the accounts of MRC Energy Company’s four wholly-owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts of Longwood Gathering and Disposal Systems, LP. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The Company’s operations are conducted in the one segment generally referred to as the oil and natural gas exploration and production industry. All significant intercompany balances and transactions have been eliminated in consolidation. 
+Reclassifications 
+Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings. 
+Use of Estimates 
+The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. 
+The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash 
+F- 7 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. 
+Certificates of Deposit 
+Certificates of deposit (“CDs”) are highly liquid, short-term investments with an original maturity of more than 30 days but not more than one year. Each CD was recorded at market and was fully insured by the Federal Deposit Insurance Corporation. 
+Accounts Receivable 
+The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ — Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date, respectively, and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. 
+The Company reviews its need for an allowance for doubtful accounts on a periodic basis, and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. 
+Lease and Well Equipment Inventory 
+Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future well operations or equipment held for sale. 
+Property and Equipment 
+The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $3.7 million , $2.6 million and $2.0 million of its general and administrative costs in 2013 , 2012 and 2011 , respectively. The Company capitalized $1.9 million , $1.6 million and $1.3 million of its interest expense for the years ended December 31, 2013, 2012 and 2011 , respectively. 
+The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling”. The cost center ceiling is defined as the sum of: 
+(a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus 
+(b) unproved and unevaluated property costs not being amortized, plus 
+(c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less 
+F- 8 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+(d) income tax effects related to the properties involved. 
+Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. Since January 1, 2011, the need for a full-cost ceiling impairment is required to be assessed on a quarterly basis. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. 
+The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic average of the first-day-of-the-month price for the 12 -month period prior to the end of each quarterly period and dictate that a 10 % discount factor be used. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.670 per MMBtu, respectively. For the period from January through December 2012 , these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period from January through December 2011 , these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. 
+At March 31, 2013, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . The Company recorded an impairment charge of $21.2 million to its net capitalized costs and a deferred income tax credit of $7.5 million related to the full-cost ceiling limitation. These charges are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2013. 
+At June 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . The Company recorded an impairment charge of $33.2 million to its net capitalized costs and a deferred income tax credit of $11.9 million related to the full-cost ceiling limitation. At September 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . The Company recorded an impairment charge of $3.6 million to its net capitalized costs and a deferred income tax credit of $1.3 million related to the full-cost ceiling limitation. At December 31, 2012, the Company’s net capitalized costs exceeded the full-cost center ceiling by $17.3 million . The Company recorded an impairment charge of $26.7 million to its net capitalized costs and a deferred income tax credit of $9.4 million related to the full-cost ceiling limitation. These charges for the second, third and fourth quarters of 2012 are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2012. 
+At March 31, 2011, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $23.0 million . The Company recorded an impairment charge of $35.7 million to its net capitalized costs and a deferred income tax credit of $12.7 million related to the full-cost ceiling limitation. These charges are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2011. 
+As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. 
+Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties 
+F- 9 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. 
+Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. 
+Other property and equipment are recorded at historical cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life ( five to 10 years) using the straight-line method. Support equipment and facilities include the pipelines and salt water disposal systems owned by Longwood Gathering and Disposal Systems, LP and are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. 
+Asset Retirement Obligations 
+The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statement of operations. In general, the Company’s future asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in its estimate or if federal or state regulators enact new plugging and abandonment requirements. At the time of actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent that the actual costs are different from the estimated liability. 
+Derivative Financial Instruments 
+From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide the Company with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. The Company’s derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations (see Note 11). The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statement of operations. 
+Revenue Recognition 
+The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. 
+For the year ended December 31, 2013, the Company had five significant purchasers that accounted for approximately 87% of its total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2012 and 2011, the 
+F- 10 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Company had three significant purchasers that accounted for approximately 74% and 60% , respectively, of its total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial position, results of operations or cash flows for any significant period of time. At December 31, 2013, 2012 and 2011 , approximately 81% , 67% and 52% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. 
+Stock-Based Compensation 
+Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. During 2013 and 2012 , all stock option awards granted under the 2012 Incentive Plan were non-qualified options and the associated compensation expense is recognized over the vesting period, which is typically three or four years. All stock option awards granted in 2013 and 2012 are classified as equity instruments due to the methods of exercise specified in the 2012 Incentive Plan. Compensation expense for restricted stock and restricted stock unit grants awarded in 2013 and 2012 was recognized immediately or over the vesting period, which is typically one to four years. 
+The Company did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under the 2003 Stock and Incentive Plan (the “2003 Plan”), and since November 22, 2010, these awards have been accounted for as liability instruments. No additional stock-based compensation will be awarded under the 2003 Plan. Non-qualified stock option grants awarded under the 2003 Plan typically vested upon issuance, while incentive stock option grants awarded under the 2003 Plan typically vest over four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Compensation expense for restricted stock grants awarded under the 2003 Plan was recognized immediately or over the vesting period, which was typically three years. 
+At December 31, 2013, 2012 and 2011 , the Company used the fair value method to measure and recognize the liability and equity associated with its outstanding stock options. 
+Prior to November 22, 2010, all of the Company’s then-outstanding stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, the Company changed its method of accounting for its then-outstanding stock options, reclassifying all of its then-outstanding stock options from equity to liability instruments. This change was made as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s Class A common stock. At December 31, 2013 , the Company continues to account for all outstanding stock options granted under the 2003 Plan as liability instruments. 
+The Company’s consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 include a stock-based compensation (non-cash) expense of $3.9 million , $0.1 million and $2.4 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.3 million , $0.1 million and $0.2 million in 2013 , 2012 and 2011 , respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company. 
+Income Taxes 
+The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and provides a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition. 
+The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. Management believes that the material positions taken by the Company would more likely than not be sustained by examination. At December 31, 2013 and 
+F- 11 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+2012 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. 
+When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income tax for the years ended December 31, 2013, 2012 and 2011 . 
+Earnings Per Common Share 
+The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. 
+Prior to consummation of the Company’s initial public offering (the “Initial Public Offering”) (see Note 10) in February 2012, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26 -2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during 2012 totaled $27,643 . Dividends declared during 2011 totaled $274,853 . Class B dividends declared during the fourth quarter of 2011 and the first quarter of 2012 were paid during the first quarter of 2012 totaling $96,356 . As of December 31, 2013, the Company has not paid any dividends to holders of the Class A shares. Concurrent with the completion of the Initial Public Offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. The Class A common stock is now referred to as the “common stock.” 
+The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted distributed and undistributed earnings per common share as reported for the years ended December 31, 2013, 2012 and 2011 (in thousands, except per share data). 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Net income (loss) — numerator 
+Net income (loss) 
+$ 
+45,094 
+$ 
+(33,261 
+) 
+$ 
+(10,309 
+) 
+Less dividends to Class B shareholders — distributed earnings 
+— 
+(28 
+) 
+(275 
+) 
+Undistributed earnings (loss) 
+$ 
+45,094 
+$ 
+(33,289 
+) 
+$ 
+(10,584 
+) 
+Weighted average common shares outstanding — denominator 
+Basic 
+Class A 
+58,777 
+53,852 
+41,687 
+Class B 
+— 
+105 
+1,031 
+Total 
+58,777 
+53,957 
+42,718 
+Diluted 
+Class A 
+Weighted average common shares outstanding for basic earnings (loss) per share 
+58,777 
+53,852 
+41,687 
+Dilutive effect of options and restricted stock units 
+152 
+— 
+— 
+Class A weighted average common shares outstanding — diluted 
+58,929 
+53,852 
+41,687 
+Class B 
+Weighted average common shares outstanding — no associated dilutive shares 
+— 
+105 
+1,031 
+Total diluted weighted average common shares outstanding 
+58,929 
+53,957 
+42,718 
+F- 12 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Earnings (loss) per common share 
+Basic 
+Class A 
+Distributed earnings 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Undistributed earnings (loss) 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Total 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Class B 
+Distributed earnings 
+$ 
+— 
+$ 
+0.27 
+$ 
+0.27 
+Undistributed earnings (loss) 
+$ 
+— 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Total 
+$ 
+— 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+Diluted 
+Class A 
+Distributed earnings 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Undistributed earnings (loss) 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Total 
+$ 
+0.77 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Class B 
+Distributed earnings 
+$ 
+— 
+$ 
+0.27 
+$ 
+0.27 
+Undistributed earnings (loss) 
+$ 
+— 
+$ 
+(0.62 
+) 
+$ 
+(0.25 
+) 
+Total 
+$ 
+— 
+$ 
+(0.35 
+) 
+$ 
+0.02 
+A total of 1,067,069 and 1,024,500 options to purchase shares of the Company’s Class A common stock and 162,368 and zero restricted stock units were excluded from the calculations above for the years ended December 31, 2012 and 2011, respectively, because their effects were anti-dilutive. Additionally, 305,807 restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2012 as the security holders do not have the obligation to share in the losses of the Company. There were no participating securities at December 31, 2011. 
+Fair Value Measurements 
+The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company follows Financial Accounting Standards Board (“FASB”) guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. 
+Credit Risk 
+The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. 
+The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company believes that any credit risk posed is insignificant and is offset by the creditworthiness of its customer base and industry partners. 
+Risks and Uncertainties 
+As an oil and natural gas exploration and production company focused on finding and developing its own prospects and reserves, the Company’s success is highly dependent on the results of its exploration and development program. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reserves will be discovered. In addition, there are uncertainties as to the future costs or timing of drilling, completing and producing wells. Poor 
+F- 13 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — Continued 
+results from the Company’s exploration and development activities could limit the Company’s ability to replace and grow reserves and materially and adversely affect the Company’s financial position, results of operations and cash flows. 
+Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. Any significant variance could materially and adversely affect the Company’s future reserves estimates, financial position, results of operations and cash flows. 
+Historically, the market for oil, natural gas and natural gas liquids has experienced significant price fluctuations, and this has been particularly evident in recent years. Oil, natural gas and natural gas liquids prices are impacted by supply and demand, both domestic and international, seasonal variations caused by changing weather conditions, political conditions, governmental regulations, the availability, proximity and capacity of gathering, processing and transportation systems for natural gas and natural gas liquids and numerous other factors. Increases or decreases in prices received could have a significant and material impact on the Company’s future reserves estimates, financial position, results of operations and cash flows. 
+To mitigate its exposure to fluctuations in oil, natural gas and natural gas liquids prices, the Company, from time to time, enters into hedging arrangements with respect to a portion of its oil, natural gas and natural gas liquids production. Decisions as to whether, at what price and what production volumes to hedge are difficult and depend on market conditions and the Company’s forecast of future production and commodity prices, and the Company may not always employ the optimal hedging strategy. 
+The federal, state and local governments in the areas in which the Company operates or has assets impose taxes on the oil and natural gas products sold, and sales and use taxes are charged on significant portions of the Company’s drilling, completion and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like the Company. Among other issues, President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could materially and adversely affect the Company’s future financial position, results of operations and cash flows. 
+Recent Accounting Pronouncements 
+Balance Sheet. In January 2013, the FASB issued Accounting Standards Update, or ASU, 2013-01, Balance Sheet. The ASU clarifies the scope of ASU 2011-11 to limit the application of ASU 2011-11 to derivatives accounted for in accordance with Accounting Standards Codification, or ASC, 815, Derivatives and Hedging , including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The Company adopted ASU 2013-01 effective January 1, 2013, together with the adoption of ASU 2011-01. The adoption of ASUs 2013-01 and 2011-11 did not have a material effect on the Company’s consolidated financial statements, but did require certain additional disclosures (see Note 11). 
+Balance Sheet. In December 2011, the FASB issued ASU 2011-11, Balance Sheet . The requirements amend the disclosure requirements to offsetting in ASC 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting agreement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The Company adopted ASU 2011-11 effective January 1, 2013, together with the adoption of ASU 2013-01. The adoption of ASUs 2011-11 and 2013-01 did not have a material effect on the Company’s consolidated financial statements, but did require certain additional disclosures (see Note 11). 
+F- 14 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 3 — PROPERTY AND EQUIPMENT 
+The following table presents a summary of the Company’s property and equipment balances as of December 31, 2013 and 2012 (in thousands). 
+December 31, 
+2013 
+2012 
+Oil and natural gas properties 
+Evaluated (subject to amortization) 
+$ 
+1,090,656 
+$ 
+763,527 
+Unproved and unevaluated (not subject to amortization) 
+Incurred in 2013 
+82,628 
+— 
+Incurred in 2012 
+23,341 
+36,488 
+Incurred in 2011 
+10,982 
+24,138 
+Incurred in 2010 and prior 
+77,355 
+89,049 
+Total unproved and unevaluated 
+194,306 
+149,675 
+Total oil and natural gas properties 
+1,284,962 
+913,202 
+Accumulated depletion 
+(463,091 
+) 
+(344,609 
+) 
+Net oil and natural gas properties 
+821,871 
+568,593 
+Other property and equipment 
+Computer equipment 
+1,044 
+834 
+Furniture 
+1,057 
+793 
+Software 
+1,456 
+1,355 
+Other equipment 
+252 
+196 
+Leasehold improvements 
+991 
+644 
+Support equipment and facilities 
+25,110 
+23,436 
+Total other property and equipment 
+29,910 
+27,258 
+Accumulated depreciation 
+(5,904 
+) 
+(4,761 
+) 
+Net other property and equipment 
+24,006 
+22,497 
+Net property and equipment 
+$ 
+845,877 
+$ 
+591,090 
+The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2013 and the year in which these costs were incurred (in thousands). 
+Description 
+2013 
+2012 
+2011 
+2010 and 
+prior 
+Total 
+Costs incurred for 
+Property acquisition 
+$ 
+66,582 
+$ 
+22,944 
+$ 
+9,050 
+$ 
+77,355 
+$ 
+175,931 
+Exploration wells 
+12,901 
+247 
+1,932 
+— 
+15,080 
+Development wells 
+3,145 
+— 
+— 
+— 
+3,145 
+Capitalized interest 
+— 
+150 
+— 
+— 
+150 
+Total 
+$ 
+82,628 
+$ 
+23,341 
+$ 
+10,982 
+$ 
+77,355 
+$ 
+194,306 
+Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. 
+F- 15 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 3 — PROPERTY AND EQUIPMENT — Continued 
+Property acquisition costs incurred in 2013 were related primarily to the Company’s leasehold acquisitions in the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, but also include costs associated with additional leasehold acquisitions in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana and East Texas. 
+Property acquisition costs incurred in 2012 were related primarily to the Company’s leasehold acquisitions in the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. Property acquisition costs incurred in 2011 were related primarily to the Company’s leasehold acquisitions in the Eagle Ford shale play in South Texas. These costs are associated with acreage for which proved reserves have yet to be assigned. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. The Company estimates that the evaluation of most of these properties and the inclusion of their costs in the amortization base should be completed within three to five years or less. 
+Property acquisition costs incurred in 2010 and prior years were related primarily to the Company’s leasehold acquisitions in the Eagle Ford shale play in South Texas and in the Haynesville shale play in Northwest Louisiana. These costs are associated with acreage for which proved reserves have yet to be assigned. Almost all of these costs are associated with properties which are held by production and have no near-term expiration risk. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base should be completed within three to five years or less. 
+Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $16.0 million for 2013 . Of this total, $12.9 million was associated with exploration wells and $3.1 million was associated with development wells. The Company anticipates that the entire $16.0 million associated with these wells in progress at December 31, 2013 will be transferred to the amortization base during 2014 . At December 31, 2013 , there were $2.2 million in exploratory well costs excluded from amortization that were incurred in years prior to 2013 , all associated with the Company’s initial exploration well in the Meade Peake shale in Southwest Wyoming. The Company completed the horizontal lateral section of this exploratory well during the fall of 2013, but initial testing was still in progress at December 31, 2013. The Company plans to finalize the testing of this well in 2014 and expects that all exploration costs incurred on this well will be transferred to the amortization base during 2014 . 
+NOTE 4 — ASSET RETIREMENT OBLIGATIONS 
+The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2013 and 2012 (in thousands). 
+Year Ended December 31, 
+2013 
+2012 
+Beginning asset retirement obligations 
+$ 
+5,769 
+$ 
+4,270 
+Liabilities incurred during period 
+936 
+1,243 
+Liabilities settled during period 
+(103 
+) 
+— 
+Revisions in estimated cash flows 
+534 
+— 
+Accretion expense 
+348 
+256 
+Ending asset retirement obligations 
+7,484 
+5,769 
+Less: current asset retirement obligations (1) 
+(175 
+) 
+(660 
+) 
+Long-term asset retirement obligations 
+$ 
+7,309 
+$ 
+5,109 
+__________________ 
+(1) 
+Included in accrued liabilities in the Company’s consolidated balance sheet at December 31, 2013 and 2012. 
+F- 16 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 5 — ASSET SALES AND IMPAIRMENT 
+In March 2013, the Company recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of pipe, was less than the cost. The carrying value was reduced by $192,000 on the consolidated balance sheet, and a corresponding charge was recorded to the consolidated statement of operations for the year ended December 31, 2013 . 
+In December 2012, the Company recorded an impairment to reduce the remaining balance of its drilling rig parts held in inventory to zero following a determination that there was no current market for these parts. The carrying value of the inventory was reduced to zero and a charge of $425,000 was recorded to the consolidated statement of operations. In addition, the Company recorded a loss of approximately $60,000 on certain other equipment that was sold during 2012. 
+In December 2011, the Company recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the inventory was reduced by $17,500 on the consolidated balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In December 2011, the Company also recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of pipe and other equipment, was less than the cost. The carrying value of the inventory was reduced by $22,276 on the consolidated balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In addition, the Company recorded a loss of $113,757 on certain other equipment that was sold during 2011. 
+NOTE 6 — REVOLVING CREDIT AGREEMENT 
+On September 28, 2012 , the Company amended and restated its revolving credit agreement. This third amended and restated credit agreement (the “Credit Agreement”) increased the maximum facility amount from $400.0 million to $500.0 million . The Credit Agreement matures December 29, 2016 . MRC Energy Company is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of the Company's oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company. 
+The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the first quarter of 2013, the lenders completed their review of the Company's proved oil and natural gas reserves at December 31, 2012, and on March 11, 2013, the borrowing base was increased from $215.0 million to $255.0 million . In connection with this borrowing base redetermination, the conforming borrowing base was increased to $220.0 million . At that time, the Company also amended the Credit Agreement to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and Iberia Bank in its lending group, which also includes Royal Bank of Canada (RBC), as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. This March 2013 redetermination constituted the regularly scheduled May 1 redetermination. In late April 2013, the Company requested an unscheduled redetermination of the borrowing base, and on June 4, 2013, the borrowing base was increased from $255.0 million to $280.0 million , and the conforming borrowing base was increased to $245.0 million . On August 7, 2013, the borrowing base under the Credit Agreement was increased to $350.0 million and the conforming borrowing base was increased to $275.0 million . At that time, the Company amended the Credit Agreement to provide that the borrowing base would automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2014 or (ii) concurrent with the issuance by the Company of senior unsecured notes in an amount greater than or equal to $10.0 million . This August 2013 redetermination constituted the regularly scheduled November 1 redetermination. 
+During the first quarter of 2014 , the lenders completed their review of the Company's estimated total proved oil and natural gas reserves at December 31, 2013 , and as a result, on March 12, 2014 , the borrowing base under the Credit Agreement was increased to $385.0 million , and the conforming borrowing base was increased to $310.0 million . At that time, Wells Fargo Bank, N.A. replaced Capital One, N.A., in the Company’s lending group, and the Company amended the Credit Agreement to provide that the borrowing base will automatically be reduced to the conforming borrowing base at the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by the Company of senior unsecured notes in an amount greater than or equal to $10.0 million . The Credit Agreement was also amended to eliminate the current ratio covenant and to increase the debt to EBITDA 
+F- 17 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+ratio covenant, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, to 4.25 or less. In addition, the interest rate charged to the Company based on its outstanding level of borrowings was reduced by 0.25% across the borrowing grid as a result of this amendment to the Credit Agreement. This March 2014 redetermination constituted the regularly scheduled May 1 redetermination. The Company may request one additional unscheduled redetermination of its borrowing base prior to the next scheduled redetermination. The Company expects additional increases to the borrowing base primarily as a result of anticipated increases in its proved oil and natural gas reserves, and particularly its proved developed oil and natural gas reserves. 
+In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the borrowing base increase. If, upon a redetermination or the automatic reduction of the borrowing base to the conforming borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . 
+In connection with the March, June and August 2013 borrowing base redeterminations, the Company incurred $1.1 million of additional deferred loan costs. These costs were included with the remaining unamortized balance of the deferred loan costs incurred previously. As a result, total deferred loan costs were $2.1 million at December 31, 2013 , and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. The Company incurred an additional $0.8 million of deferred loan costs associated with the March 2014 borrowing base redetermination. 
+On September 12, 2013, using a portion of the net proceeds from the Company's public equity offering, the Company repaid $130.0 million of its outstanding borrowings under the Credit Agreement. At December 31, 2013 , the Company had $200.0 million in borrowings outstanding under the Credit Agreement and approximately $0.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. At December 31, 2013 , the Company's outstanding borrowings bore interest at an effective interest rate of approximately 3.3% per annum. From January 1, 2014 through March 13, 2014 , the Company borrowed an additional $50.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures and the acquisition of additional leasehold interests. At March 13, 2014 , the Company had $250.0 million in borrowings outstanding under the Credit Agreement and approximately $0.3 million in outstanding letters of credit issued pursuant to the Credit Agreement. 
+Under the terms of the Credit Agreement as of December 31, 2013 and until the March 12, 2014 amendment described above, if the Company borrowed funds as a base rate loan, such borrowings bore interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 3.00% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrowed funds as a Eurodollar loan, such borrowings bore interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.75% to 4.00% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50% , depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees as interest expense and in its interest rate calculations and related disclosures. 
+At December 31, 2013, the key financial covenants under the Credit Agreement required the Company to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at the end of each fiscal quarter beginning December 31, 2014 and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.00 or less. 
+F- 18 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 6 — REVOLVING CREDIT AGREEMENT — Continued 
+Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company's ability to take certain actions, including, but not limited to, the following: 
+• 
+incur indebtedness or grant liens on any of the Company's assets; 
+• 
+enter into commodity hedging agreements; 
+• 
+declare or pay dividends, distributions or redemptions; 
+• 
+merge or consolidate; 
+• 
+make any loans or investments; 
+• 
+engage in transactions with affiliates; and 
+• 
+engage in certain asset dispositions, including a sale of all or substantially all of the Company's assets. 
+If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: 
+• 
+failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; 
+• 
+failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; 
+• 
+bankruptcy or insolvency events involving the Company or its subsidiaries; and 
+• 
+a change of control, as defined in the Credit Agreement. 
+At December 31, 2013 , the Company believes that it was in compliance with the terms of its Credit Agreement. 
+F- 19 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 7 — INCOME TAXES 
+Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2013 and 2012 , respectively, is as follows (in thousands). 
+December 31, 
+2013 
+2012 
+Current deferred tax assets 
+Property and equipment 
+$ 
+62 
+$ 
+233 
+Unrealized loss on derivatives 
+965 
+— 
+Other 
+609 
+869 
+Total current deferred tax assets 
+1,636 
+1,102 
+Valuation allowance on current deferred tax assets 
+— 
+(202 
+) 
+Total current deferred tax assets, net of valuation allowance 
+1,636 
+900 
+Current deferred tax liabilities 
+Unrealized gain on derivatives 
+— 
+(1,311 
+) 
+Net current deferred tax assets (liabilities) 
+$ 
+1,636 
+$ 
+(411 
+) 
+Non-current deferred tax assets 
+Unrealized loss on derivatives 
+$ 
+28 
+$ 
+— 
+Net operating loss carryforwards 
+63,007 
+44,654 
+Alternative minimum tax carryforward 
+7,064 
+6,660 
+Total non-current deferred tax assets 
+70,099 
+51,314 
+Valuation allowance on non-current deferred tax assets 
+(30 
+) 
+(10,058 
+) 
+Total non-current deferred tax assets, net of valuation allowance 
+70,069 
+41,256 
+Non-current deferred tax liabilities 
+Unrealized gain on derivatives 
+— 
+(262 
+) 
+Property and equipment 
+(76,719 
+) 
+(36,363 
+) 
+Other 
+(4,279 
+) 
+(4,220 
+) 
+Total non-current deferred tax liabilities 
+(80,998 
+) 
+(40,845 
+) 
+Net non-current deferred tax (liabilities) assets 
+$ 
+(10,929 
+) 
+$ 
+411 
+The Company had an effective tax rate of 17.7% for the year ended December 31, 2013 . Total income tax expense for the year ended December 31, 2013 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to (i) the reversal of a valuation allowance of approximately $8.9 million on the Company’s federal deferred tax assets at December 31, 2012 , as the Company’s federal deferred tax liabilities exceeded its federal deferred tax assets for the year ended December 31, 2013 , (ii) the reversal of a state valuation allowance of approximately $1.3 million as the Company now believes it will be able to utilize the state net operating losses prior to their expiration and (iii) the impact of permanent differences between book and taxable income. The Company reported a net loss for the years ended December 31, 2012 and 2011. 
+At December 31, 2013 , the Company had net operating loss carryforwards of $171.3 million for federal income tax purposes and $3.1 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the state of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . 
+At March 31, 2013, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $13.7 million . As a result, the Company recorded an impairment charge of $21.2 million to its net capitalized costs and a deferred income tax credit of $7.5 million for the three months ended March 31, 2013. The Company established a valuation allowance at September 30, 2012 and retained full valuation allowances of approximately 
+F- 20 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 7 — INCOME TAXES — Continued 
+$15.8 million at March 31, 2013 and $6.7 million at June 30, 2013 due to uncertainties regarding the future realization of the net deferred tax assets. 
+At June 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million . As a result, the Company recorded an impairment charge of $33.2 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $11.9 million . At September 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million . As a result, the Company recorded an impairment charge of $3.6 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $1.3 million . This deferred income tax credit exceeded the Company’s deferred tax liabilities at September 30, 2012. As a result, the Company established a valuation allowance of $2.4 million at September 30, 2012 due to uncertainties regarding the future realization of its deferred tax assets. At December 31, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million . As a result, the Company recorded an impairment charge of $26.7 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $9.4 million . This deferred income tax credit exceeded the Company’s deferred tax liabilities at December 31, 2012. As a result, the Company increased the previously established valuation allowance by $7.9 million to maintain a full valuation allowance of $10.3 million against the Company’s net deferred tax assets. 
+At March 31, 2011, the Company recorded an impairment charge of $23.0 million to its net capitalized costs, net of a deferred income tax credit of $12.7 million related to the full-cost ceiling limitation. This deferred income tax credit exceeded the Company’s deferred tax liabilities at March 31, 2011. As a result, the Company established a valuation allowance at March 31, 2011 and retained a valuation allowance until the quarter ended December 31, 2011 due to uncertainties regarding the future realization of its deferred tax assets. At December 31, 2011, the Company assessed the valuation allowance and determined that the allowance was no longer required. 
+The income tax expense reconciled to the tax computed at the statutory federal rate for the years ended December 31, 2013, 2012 and 2011 , respectively, is as follows (in thousands). 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Current income tax provision (benefit) 
+State income tax 
+$ 
+— 
+$ 
+— 
+$ 
+(46 
+) 
+Federal alternative minimum tax 
+404 
+— 
+— 
+Net current income tax provision (benefit) 
+404 
+— 
+(46 
+) 
+Deferred income tax provision (benefit) 
+Federal tax expense at statutory rate (1) 
+19,177 
+(11,767 
+) 
+(5,319 
+) 
+Statutory depletion carryforward 
+— 
+— 
+231 
+State income tax 
+431 
+(819 
+) 
+(435 
+) 
+Nondeductible expense 
+— 
+(122 
+) 
+48 
+Permanent differences (2) 
+319 
+1,018 
+— 
+Federal alternative minimum tax 
+(404 
+) 
+— 
+— 
+Change in federal valuation allowance 
+(8,885 
+) 
+10,260 
+— 
+Change in state valuation allowance 
+(1,345 
+) 
+— 
+— 
+Net deferred income tax provision (benefit) 
+9,293 
+(1,430 
+) 
+(5,475 
+) 
+Total income tax provision (benefit) 
+$ 
+9,697 
+$ 
+(1,430 
+) 
+$ 
+(5,521 
+) 
+__________________ 
+(1) 
+The statutory federal tax rate was 35% for the year ended December 31, 2013 and 34% for the years ended December 31, 2012 and 2011. 
+(2) 
+Amount is primarily attributable to stock-based compensation. 
+F- 21 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 7 — INCOME TAXES — Continued 
+The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The tax years open for examination for the federal tax return are 2010 , 2011 , 2012 and 2013 . The tax years open for examination by the state of Texas are 2009, 2010 , 2011 , 2012 and 2013 . The tax years open for examination by the state of New Mexico are 2010 , 2011 , 2012 and 2013 . The tax years open for examination by the state of Louisiana are 2010 , 2011 , 2012 and 2013 . As of December 31, 2013, the Company's 2009, 2010, 2011 and 2012 franchise tax returns are under examination by the state of Texas. This examination is in the preliminary stage and no additional income taxes or refunds of previous tax payments for these tax years have been recorded as a result of this examination at December 31, 2013. 
+The Company has evaluated all tax positions for which the statute of limitations remained open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2013 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. 
+NOTE 8 — STOCK-BASED COMPENSATION 
+Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards 
+In 2003 the Company’s Board of Directors and shareholders approved the 2003 Plan. The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of Class A common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. 
+Effective January 1, 2012, the Board of Directors adopted the 2012 Incentive Plan. The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. The 2012 Incentive Plan provides for a maximum of 4,000,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. 
+The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which determines the number of options or restricted shares to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted during 2013 and 2012 were granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at every reporting period. 
+Stock Options 
+Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five or ten years. 
+Effective upon filing its initial Registration Statement with the SEC in August 2011, the Company adopted the fair value method and used an estimated fair value of $12.00 per share to measure and recognize the liability associated with its outstanding stock options. The Company recorded $1.1 million in additional general and administrative expenses during 2011 due to this change in the valuation method from the intrinsic value method to the fair value method. 
+F- 22 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+The Company granted no stock option awards during the year ended December 31, 2011. The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2013, 2012 and 2011 . 
+2013 
+2012 
+2011 
+Stock option pricing model 
+Black Scholes Merton 
+Black Scholes Merton 
+Black Scholes Merton 
+Expected option life 
+2.44 years 
+0.89 years 
+1.04 years 
+Risk-free interest rate 
+0.69% 
+0.25% 
+0.37% 
+Volatility 
+51.51% 
+54.28% 
+61.41% 
+Dividend yield 
+—% 
+—% 
+—% 
+Estimated forfeiture rate 
+0.79% 
+0.70% 
+1.04% 
+The weighted average grant date fair value for stock option awards outstanding under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2013 and 2012 . 
+2013 
+2012 
+Stock option pricing model 
+Black Scholes Merton 
+Black Scholes Merton 
+Expected option life 
+4.0 years 
+4.4 years 
+Risk-free interest rate 
+0.69% 
+0.71% 
+Volatility 
+58.65% 
+71.16% 
+Dividend yield 
+—% 
+—% 
+Estimated forfeiture rate 
+6.37% 
+5.46% 
+Weighted average fair value of stock option awards granted during the year 
+$3.91 
+$5.95 
+The Company estimated the future volatility of its common stock using the historical value of its peer group for a period of time commensurate with the expected term of the stock option due to the lack of historical trading data available for its common stock. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. 
+Summarized information about stock options outstanding at December 31, 2013 under the Company’s 2003 Plan and the 2012 Incentive Plan is as follows (in thousands, except price data). 
+Number of 
+options 
+Weighted 
+average 
+exercise price 
+Options outstanding at December 31, 2012 
+1,067 
+$ 
+10.19 
+Options granted 
+874 
+8.78 
+Options exercised 
+(5 
+) 
+7.77 
+Options forfeited 
+(59 
+) 
+9.86 
+Options expired 
+(449 
+) 
+10.30 
+Options outstanding at December 31, 2013 
+1,428 
+$ 
+9.32 
+F- 23 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+Options outstanding at 
+December 31, 2013 
+Options exercisable at 
+December 31, 2013 
+Range of exercise prices 
+Shares 
+outstanding 
+Weighted 
+average 
+remaining 
+contractual 
+life 
+Weighted 
+average 
+exercise 
+price 
+Shares 
+exercisable 
+Weighted 
+average 
+exercise 
+price 
+$7.50 - $10.00 
+938 
+4.30 years 
+$ 
+8.33 
+79 
+$ 
+8.90 
+$10.39 - $13.03 
+451 
+3.50 years 
+$ 
+10.56 
+15 
+$ 
+11.00 
+$17.80 - $19.05 
+39 
+4.89 years 
+$ 
+18.73 
+— 
+$ 
+— 
+At December 31, 2013 , the aggregate intrinsic value was $13.3 million for outstanding options and $0.9 million for exercisable options, based on the Company’s quoted closing market price of $18.64 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2013 was 5.97 years. 
+The total intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $36,000 , $0.9 million and $0.2 million , respectively. The tax related benefit realized from the exercise of stock options totaled zero , zero and zero for the years ended December 31, 2013, 2012 and 2011 , respectively. 
+During the years ended December 31, 2013, 2012 and 2011 , the Company recognized $2.2 million , $(0.7) million and $2.1 million , respectively, in stock-based compensation expense attributable to stock options. At December 31, 2013, 2012 and 2011 , the Company had recorded $1.2 million , $0.3 million and $0.3 million of long-term liabilities and $0.1 million , $0.1 million and $2.9 million of current liabilities, respectively, related to its outstanding liability-based stock options. The Company paid zero , zero and $0.1 million in settlement of liability-based awards for the years ended December 31, 2013, 2012 and 2011 , respectively. 
+At December 31, 2013 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $4.1 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 1.90 years. 
+The fair value of options vested during 2013, 2012 and 2011 was $0.3 million , $0.3 million and $1.0 million , respectively. 
+Restricted Stock, Restricted Stock Units and Common Stock 
+The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a term no longer than two years after vesting. No such elections were made with respect to the 2012 restricted stock unit awards; two directors elected to defer the issuance of their awards in 2013. All awards granted in 2013 were service based awards and vest over the service period which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2013 were granted under the 2012 Incentive Plan. 
+The 2012 restricted stock awards included 116,841 shares of performance based restricted stock and 116,841 performance based restricted stock units with a combined weighted average fair value of $13.24 per combined share and unit. These awards vest based on the outcome of the Company’s total shareholder return over a three -year period beginning March 19, 2012 and ending April 15, 2015 as compared to a designated peer group. These awards may result in the vesting of an aggregate of up to 116,841 restricted stock units in addition to the 116,841 shares of restricted stock. If the performance conditions are not met, however, these awards may result in no performance based restricted stock vesting and no restricted stock units vesting. The fair value of these awards was estimated based on the most likely outcome of the award as determined by the Monte Carlo method. A total of 206,842 service based restricted stock awards were granted during the year ended December 31, 2012, with a weighted average fair value of $9.66 per share. Of these awards, 13,833 shares of restricted stock vested immediately upon grant, and the remaining restricted stock vests over the service period, which ranges from one year to a maximum of four years . A total of 54,166 service based restricted stock unit awards were granted during the year ended December 31, 2012, with a weighted average fair value of $10.04 per unit. No restricted stock awards or restricted stock unit awards were granted during the year ended December 31, 2011. 
+F- 24 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+A summary of the non-vested restricted stock and restricted stock units as of December 31, 2013 is presented below (in thousands, except fair value). 
+Restricted Stock 
+Restricted Stock Units 
+Service Based 
+Performance Based 
+Service Based 
+Performance Based 
+Non-vested restricted stock and 
+restricted stock units 
+Shares 
+Weighted 
+average 
+fair 
+value 
+Shares 
+Weighted 
+average 
+fair 
+value (1) 
+Shares 
+Weighted 
+average 
+fair 
+value 
+Shares 
+Weighted 
+average 
+fair 
+value (1) 
+Non-vested at 
+December 31, 2012 
+182 
+$ 
+9.72 
+110 
+$ 
+13.24 
+52 
+$ 
+10.00 
+110 
+$ 
+— 
+Granted 
+378 
+9.07 
+— 
+— 
+51 
+11.31 
+— 
+— 
+Vested 
+(1 
+) 
+8.43 
+— 
+— 
+(17 
+) 
+10.00 
+— 
+— 
+Forfeited 
+(95 
+) 
+8.57 
+(10 
+) 
+13.24 
+— 
+— 
+(10 
+) 
+— 
+Non-vested at 
+December 31, 2013 
+464 
+$ 
+9.43 
+100 
+$ 
+13.24 
+86 
+$ 
+10.79 
+100 
+$ 
+— 
+__________________ 
+(1) 
+The fair value of these restricted stock units is reflected in the fair value of the performance based restricted stock, which was estimated based on the most likely outcome of the award as determined by the Monte Carlo method. 
+At December 31, 2013 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $14.0 million as calculated based on the maximum number of shares of restricted stock, performance based restricted stock and restricted stock units vesting, using the stock price on December 31, 2013 . 
+During the years ended December 31, 2013, 2012 and 2011 , the Company recognized approximately $1.6 million , $0.7 million and $44,000 , respectively, in stock-based compensation expense attributable to restricted stock and restricted stock units. 
+At December 31, 2013 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $4.6 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 1.82 years. 
+The fair value of restricted stock and restricted stock units vested during 2013, 2012 and 2011 was $182,000 , $44,000 and $44,000 , respectively. 
+The total tax benefit recognized for all stock-based compensation was $1.1 million , $0.3 million and $0.9 million for the years ended December 31, 2013, 2012 and 2011 , respectively. 
+During the years ended December 31, 2013, 2012 and 2011 , the Company issued shares of common stock to certain members of its Board of Directors. The Company also issued shares of common stock to certain outside advisors who do not meet the definition of employees under ASC 718. The Company used the fair value of the stock issued on the grant date to recognize the expense related to these awards. The Company recognized $0.1 million , $0.1 million and $0.2 million in stock-based compensation expense attributable to these awards for the years ended December 31, 2013, 2012 and 2011 , respectively. 
+In October 2008, the Company’s Board of Directors approved the adoption of the Employee Option Exercise Loan Program (“Loan Program”), authorizing the Company to establish a loan program with a financial institution to assist its employees, directors and officers in the exercise of their outstanding options to purchase shares of Class A common stock, subject to certain conditions and restrictions outlined in the Loan Program. As part of the Loan Program, the Company provided the financial institution with a guaranty of repayment of the loan and made deposits of funds in certificates of deposit to secure its guaranty. Notwithstanding the guaranty, these loans were fully recourse obligations of each loan recipient, and each loan recipient agreed to indemnify and reimburse the Company in full for all liabilities incurred by the Company in the event of the recipient’s default on the loan. Each loan recipient also pledged all shares purchased from the Company with the loan proceeds to further secure his or her obligations to the Company in return for its guaranty. No director nor the Company’s Chairman and Chief Executive Officer participated in the Loan Program. 
+F- 25 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 8 — STOCK-BASED COMPENSATION — Continued 
+As of December 31, 2013 all of these loans had been repaid. As of December 31, 2012, the Company had secured the loans of four employees pursuant to this Loan Program in the aggregate amount of $0.2 million . The Company considered the fair value of this aggregate guaranty to be minimal and recorded no liability provision associated with this guaranty on its consolidated balance sheet in any reporting period presented. The Company’s Board of Directors terminated the Loan Program in April 2011, and the Company is no longer authorized to provide financial guaranties for additional loans. No new loans were guaranteed in 2011 prior to the termination of the Loan Program by the Board of Directors. 
+NOTE 9 — EMPLOYEE BENEFIT PLANS 
+401(k) Plan 
+Effective July 3, 2003, the Company established a defined contribution retirement plan. All full-time Company employees are eligible to join the plan the first day of the calendar month immediately following their date of employment. Each Participant may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution. The Company’s Safe Harbor match was approximately $0.2 million in each of 2013 , 2012 and 2011 . In addition, each year, the Company may make a discretionary matching contribution as well as additional contributions. The Company’s discretionary matching contributions totaled $0.3 million , $0.3 million and $0.2 million in 2013 , 2012 and 2011 , respectively. The Company made no additional discretionary contributions in any reporting period presented. 
+NOTE 10 — COMMON STOCK 
+Dividends 
+At December 31, 2011 , the Company had issued two classes of common stock, Class A and Class B. In February 2012, upon the consummation of the Company’s Initial Public Offering, the Class B shares were converted to Class A shares, which are now referred to as common stock. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26 -2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared and paid during 2012 were $27,643 . Dividends declared during 2011 totaled $0.3 million . Dividends for the fourth quarter of 2011 were accrued and paid in January 2012. Dividends for the fourth quarter of 2010 were accrued and paid in January 2011. As of December 31, 2013 , the Company has not paid any dividends to holders of the Class A shares. In addition, certain covenants in the Company’s Credit Agreement may limit the Company’s ability to pay dividends on its common stock. 
+Stock Offerings, Retirement and Issuances 
+In April 2013, the Company filed with the SEC a universal shelf registration statement on Form S-3 (the “Shelf Registration Statement”), which provides the Company with the ability to offer and sell up to $300.0 million of debt and equity securities, subject to market conditions and its capital needs. The SEC declared the Shelf Registration Statement effective on May 9, 2013. As of December 31, 2013, the Company had approximately $151.0 million of securities available for issuance under the Shelf Registration Statement. 
+On September 10, 2013, the Company completed an underwritten public offering of 9,775,000 shares of its common stock, including 1,275,000 shares issued pursuant to the underwriters’ exercise of their option to purchase additional shares. After deducting underwriting discounts, commissions and direct offering costs totaling approximately $7.4 million , the Company received net proceeds of approximately $141.7 million . The Company is using the net proceeds from this offering primarily to fund a portion of its capital expenditures, including for the addition of the third rig to its drilling program. The Company is also using the net proceeds from this offering to fund the acquisition of additional acreage in the Permian Basin, the Eagle Ford shale and the Haynesville shale. Pending such uses, the Company used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under its Credit Agreement (see Note 6) in September 2013, which amounts may be reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. The remaining $11.7 million of the offering net proceeds was used to fund working capital requirements. 
+On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the Initial Public Offering. The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC; 
+F- 26 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 10 — COMMON STOCK — Continued 
+Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc. and Comerica Securities, Inc. 
+On February 2, 2012, shares of the Company’s common stock began trading on the New York Stock Exchange under the symbol “MTDR” at an initial offering price of $12.00 per share. 
+Pursuant to its prospectus dated February 1, 2012 , the Company offered 11,666,667 shares of its common stock for sale, and the selling shareholders offered 1,550,000 shares for sale. On February 7, 2012 , the Company closed the Initial Public Offering and issued 11,666,667 shares of its common stock pursuant to the Initial Public Offering. 
+The Company and the selling shareholders granted the underwriters the right to purchase up to an additional 2,000,000 shares of the Company’s common stock at the initial offering price of $12.00 per share, less the underwriters’ discounts and commissions, for a period of 30 days following the Initial Public Offering to cover over-allotments, with the Company offering 700,000 shares and the selling shareholders offering 1,300,000 shares. On March 2, 2012, the underwriters exercised their option to purchase an additional 1,550,000 shares, including the purchase of 542,500 shares from the Company and the purchase of 1,007,500 shares from the selling shareholders. On March 7, 2012 , the Company closed this transaction and issued 542,500 shares of its common stock pursuant to the underwriters’ exercise of the over-allotment. 
+Pursuant to the Initial Public Offering and the over-allotment, the Company issued a total of 12,209,167 shares of its common stock at $12.00 per share and received estimated net proceeds of approximately $133.6 million after deducting the underwriters’ discounts and commissions and the estimated legal, accounting and other fees associated with the offering. The Company did not receive any proceeds from the sale of shares of its common stock by the selling shareholders. On February 8, 2012, the Company used the net proceeds of the offering to repay the $123.0 million in borrowings then outstanding under its Credit Agreement in full. The Company used the remaining net proceeds of the offering to fund a portion of its 2012 capital expenditures. 
+Concurrent with the completion of the Initial Public Offering, all 1,030,700 outstanding shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. In addition, in February 2012, the Company issued an additional 295,500 shares of its Class A common stock pursuant to the exercise of stock options and received net proceeds of $2.7 million . The Class A common stock is now referred to as the common stock. 
+In October 2010, the Board of Directors approved and authorized the private offering and sale of additional shares of the Company’s Class A common stock at $11.00 per share in the period from October 2010 through January 2011. As of December 31, 2010, the Company sold approximately 1.9 million shares and received net proceeds of $20.5 million . In January 2011, the Company sold an additional 53,772 shares as part of this offering and received net proceeds of approximately $0.6 million . 
+Treasury Stock 
+The increase of 105,126 and 21,876 shares in treasury stock outstanding during 2013 and 2012 , respectively, represents forfeitures of non-vested restricted stock awards. 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS 
+From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless collars and swap contracts. The Company records derivative financial instruments on its consolidated balance sheet as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using purchase and sale information available for similarly traded securities. Comerica Bank, RBC, The Bank of Nova Scotia and SunTrust Bank (or affiliates thereof) were the counterparties for the Company’s commodity derivatives at December 31, 2013 . The Company has considered the credit standings of the counterparties in determining the fair value of its derivative financial instruments. 
+F- 27 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The Company has entered into various costless collar contracts to mitigate its exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume. 
+The Company has entered into various swap contracts to mitigate its exposure to fluctuations in oil prices, each with an established fixed price. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions was the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price was below the fixed price established by one or more of these swaps, the Company received from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price was above the fixed price established by one or more of these swaps, the Company paid to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. These oil price swap contracts expired on December 31, 2013 . 
+The Company has entered into various costless collar transactions for natural gas, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to the Company pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the settlement date of that contract period. When the settlement price is below the price floor established by one or more of these collars, the Company receives from the counterparty an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by one or more of these collars, the Company pays to the counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume. 
+The Company has entered into various swap contracts to mitigate its exposure to fluctuations in natural gas liquids (“NGL”) prices, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to the Company pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET prop” on the pricing date. When the settlement price is below the fixed price established by one or more of these swaps, the Company receives from the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by one or more of these swaps, the Company pays to the counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. 
+At December 31, 2013 , the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2014 and 2015. 
+At December 31, 2013 , the Company had various swap contracts open and in place to mitigate its exposure to NGL price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and fixed price. Each contract is set to expire at varying times during 2014 and 2015. 
+F- 28 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following is a summary of the Company’s open costless collar contracts for oil and natural gas and open swap contracts for NGL at December 31, 2013 . 
+Notional Quantity (Bbl/month) 
+Price Floor ($/Bbl) 
+Price Ceiling ($/Bbl) 
+Fair Value of Asset (Liability) (thousands) 
+Commodity 
+Calculation Period 
+Oil 
+01/01/2014 - 06/30/2014 
+8,000 
+$ 
+90.00 
+$ 
+114.00 
+$ 
+44 
+Oil 
+01/01/2014 - 06/30/2014 
+12,000 
+90.00 
+115.50 
+67 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+85.00 
+97.50 
+(309 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+30,000 
+85.00 
+98.00 
+(560 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+12,000 
+85.00 
+100.00 
+(90 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+12,200 
+85.00 
+100.40 
+(70 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+10,000 
+85.00 
+100.55 
+(52 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+87.00 
+97.00 
+(294 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+20,000 
+88.00 
+95.60 
+(536 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+20,000 
+90.00 
+97.00 
+(253 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+12,000 
+90.00 
+97.90 
+(80 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+90.00 
+97.90 
+(98 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+90.00 
+98.00 
+(101 
+) 
+Oil 
+01/01/2014 - 12/31/2014 
+15,000 
+90.00 
+101.15 
+132 
+Total open oil costless collar contracts 
+(2,200 
+) 
+Notional Quantity (MMBtu/month) 
+Price Floor ($/MMBtu) 
+Price Ceiling ($/MMBtu) 
+Fair Value of Asset (Liability) (thousands) 
+Commodity 
+Calculation Period 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.00 
+5.15 
+(60 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.21 
+(34 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.22 
+(34 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.37 
+(22 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.25 
+5.42 
+(18 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.50 
+4.90 
+(37 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2014 
+100,000 
+3.75 
+4.77 
+3 
+Natural Gas 
+01/01/2014 - 12/31/2015 
+100,000 
+3.75 
+4.36 
+(237 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2015 
+100,000 
+3.75 
+4.45 
+(158 
+) 
+Natural Gas 
+01/01/2014 - 12/31/2015 
+100,000 
+3.75 
+4.60 
+(24 
+) 
+Natural Gas 
+04/01/2014 - 12/31/2014 
+100,000 
+3.75 
+4.75 
+6 
+Natural Gas 
+01/01/2015 - 03/31/2015 
+200,000 
+4.00 
+4.84 
+(3 
+) 
+Natural Gas 
+01/01/2015 - 12/31/2015 
+100,000 
+3.75 
+4.65 
+(9 
+) 
+Natural Gas 
+01/01/2015 - 12/31/2015 
+200,000 
+3.75 
+5.04 
+182 
+Total open natural gas costless collar contracts 
+(445 
+) 
+F- 29 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+Notional Quantity (Gal/month) 
+Fixed Price ($/Gal) 
+Fair Value of Asset (Liability) (thousands) 
+Commodity 
+Calculation Period 
+Propane 
+01/01/2014 - 12/31/2014 
+116,000 
+0.950 
+(247 
+) 
+Propane 
+01/01/2014 - 12/31/2014 
+84,000 
+1.143 
+32 
+Propane 
+01/01/2014 - 12/31/2014 
+68,000 
+1.150 
+32 
+Propane 
+01/01/2014 - 12/31/2014 
+116,000 
+1.003 
+(150 
+) 
+Propane 
+01/01/2014 - 12/31/2014 
+60,000 
+1.015 
+(69 
+) 
+Propane 
+01/01/2015 - 12/31/2015 
+150,000 
+1.000 
+(58 
+) 
+Propane 
+01/01/2015 - 12/31/2015 
+68,000 
+1.073 
+33 
+Normal Butane 
+01/01/2014 - 12/31/2014 
+17,500 
+1.540 
+47 
+Normal Butane 
+01/01/2014 - 12/31/2014 
+45,500 
+1.550 
+122 
+Isobutane 
+01/01/2014 - 12/31/2014 
+22,000 
+1.640 
+78 
+Isobutane 
+01/01/2014 - 12/31/2014 
+37,000 
+1.640 
+140 
+Natural Gasoline 
+01/01/2014 - 12/31/2014 
+30,000 
+1.970 
+(35 
+) 
+Natural Gasoline 
+01/01/2014 - 12/31/2014 
+41,000 
+2.000 
+(33 
+) 
+Total open NGL swap contracts 
+(108 
+) 
+Total open derivative financial instruments 
+$ 
+(2,753 
+) 
+These derivative financial instruments are subject to master netting arrangements within specific commodity types, i.e., oil, natural gas and NGL, by counterparty. Derivative financial instruments with Counterparty A are not subject to master netting across commodity types, while derivative financial instruments with Counterparties B, C and D allow for cross-commodity master netting provided the settlement dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheet. 
+F- 30 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2013 (in thousands). 
+Derivative Instruments 
+Gross 
+amounts of 
+recognized 
+assets 
+Gross amounts 
+netted in the 
+consolidated 
+balance sheet 
+Net amounts of 
+assets 
+presented in the 
+consolidated 
+balance sheet 
+Amounts subject to master netting arrangements presented on a gross basis 
+Counterparty A 
+Current assets 
+$ 
+1,746 
+$ 
+(1,746 
+) 
+$ 
+— 
+$ 
+— 
+Other assets 
+— 
+— 
+— 
+— 
+Counterparty B 
+Current assets 
+1,371 
+(1,371 
+) 
+— 
+— 
+Other assets 
+841 
+(668 
+) 
+173 
+— 
+Counterparty C 
+Current assets 
+2,886 
+(2,873 
+) 
+13 
+— 
+Other assets 
+1,046 
+(1,046 
+) 
+— 
+— 
+Counterparty D 
+Current assets 
+6 
+— 
+6 
+— 
+Other assets 
+— 
+— 
+— 
+— 
+Total 
+$ 
+7,896 
+$ 
+(7,704 
+) 
+$ 
+192 
+$ 
+— 
+The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2013 (in thousands). 
+Derivative Instruments 
+Gross 
+amounts of 
+recognized 
+liabilities 
+Gross amounts 
+netted in the 
+consolidated 
+balance sheet 
+Net amounts of 
+liabilities 
+presented in the 
+consolidated 
+balance sheet 
+Amounts subject to master netting arrangements presented on a gross basis 
+Counterparty A 
+Current liabilities 
+$ 
+2,550 
+$ 
+(1,746 
+) 
+$ 
+804 
+$ 
+— 
+Long-term liabilities 
+— 
+— 
+— 
+— 
+Counterparty B 
+Current liabilities 
+2,136 
+(1,371 
+) 
+765 
+— 
+Long-term liabilities 
+668 
+(668 
+) 
+— 
+— 
+Counterparty C 
+Current liabilities 
+3,996 
+(2,873 
+) 
+1,123 
+— 
+Long-term liabilities 
+1,299 
+(1,046 
+) 
+253 
+— 
+Counterparty D 
+Current liabilities 
+— 
+— 
+— 
+— 
+Long-term liabilities 
+— 
+— 
+— 
+— 
+Total 
+$ 
+10,649 
+$ 
+(7,704 
+) 
+$ 
+2,945 
+$ 
+— 
+F- 31 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following table presents the gross asset balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2012 (in thousands). 
+Derivative Instruments 
+Gross 
+amounts of 
+recognized 
+assets 
+Gross amounts 
+netted in the 
+consolidated 
+balance sheet 
+Net amounts of 
+assets 
+presented in the 
+consolidated 
+balance sheet 
+Amounts subject to master netting arrangements presented on a gross basis 
+Counterparty A 
+Current assets 
+$ 
+6,445 
+$ 
+(2,373 
+) 
+$ 
+4,072 
+$ 
+— 
+Other assets 
+1,096 
+(370 
+) 
+726 
+— 
+Counterparty B 
+Current assets 
+530 
+(224 
+) 
+306 
+82 
+Other assets 
+384 
+(339 
+) 
+45 
+— 
+Total 
+$ 
+8,455 
+$ 
+(3,306 
+) 
+$ 
+5,149 
+$ 
+82 
+The following table presents the gross liability balances of the Company’s derivative financial instruments, the amounts subject to master netting arrangements, the amounts that the Company has presented on a net basis, the amounts subject to master netting across different commodity types that were presented on a gross basis and the location of these balances in its consolidated balance sheet as of December 31, 2012 (in thousands). 
+Derivative Instruments 
+Gross 
+amounts of 
+recognized 
+liabilities 
+Gross amounts 
+netted in the 
+consolidated 
+balance sheet 
+Net amounts of 
+liabilities 
+presented in the 
+consolidated 
+balance sheet 
+Amounts subject to master netting arrangements presented on a gross basis 
+Counterparty A 
+Current liabilities 
+$ 
+2,373 
+$ 
+(2,373 
+) 
+$ 
+— 
+$ 
+— 
+Long-term liabilities 
+370 
+(370 
+) 
+— 
+— 
+Counterparty B 
+Current liabilities 
+894 
+(224 
+) 
+670 
+82 
+Long-term liabilities 
+339 
+(339 
+) 
+— 
+— 
+Total 
+$ 
+3,976 
+$ 
+(3,306 
+) 
+$ 
+670 
+$ 
+82 
+F- 32 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS — Continued 
+The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. 
+Location in 
+Year Ended December 31, 
+Type of Instrument 
+Statement of Operations 
+2013 
+2012 
+2011 
+Derivative Instrument 
+Oil 
+Revenues: Realized (loss) gain on derivatives 
+$ 
+(2,408 
+) 
+$ 
+2,047 
+$ 
+— 
+Natural Gas 
+Revenues: Realized gain on derivatives 
+831 
+11,892 
+7,106 
+NGL 
+Revenues: Realized gain on derivatives 
+668 
+21 
+— 
+Realized (loss) gain on derivatives 
+(909 
+) 
+13,960 
+7,106 
+Oil 
+Revenues: Unrealized (loss) gain on derivatives 
+(5,319 
+) 
+3,673 
+(554 
+) 
+Natural Gas 
+Revenues: Unrealized (loss) gain on derivatives 
+(1,580 
+) 
+(8,700 
+) 
+5,692 
+NGL 
+Revenues: Unrealized (loss) gain on derivatives 
+(333 
+) 
+225 
+— 
+Unrealized (loss) gain on derivatives 
+(7,232 
+) 
+(4,802 
+) 
+5,138 
+Total 
+$ 
+(8,141 
+) 
+$ 
+9,158 
+$ 
+12,244 
+F- 33 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 12 — FAIR VALUE MEASUREMENTS 
+The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories. 
+Level 1 
+Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. 
+Level 2 
+Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. 
+Level 3 
+Unobservable inputs that are not corroborated by market data. This category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based on internally developed models or methodologies using significant inputs that are generally less readily observable from objective sources. 
+Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. 
+At December 31, 2013 and 2012 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, advances from joint interest owners, income taxes payable and other current liabilities approximate their fair values due to their short-term maturities and are classified at Level 1. 
+At December 31, 2013 and 2012 , the carrying value of borrowings under the Credit Agreement approximates fair value as it is subject to short-term floating interest rates that reflect market rates available to the Company at the time and is classified at Level 2. 
+The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2013 and 2012 (in thousands). 
+Fair Value Measurements at 
+December 31, 2013 using 
+Description 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Oil, natural gas and NGL derivatives 
+$ 
+— 
+$ 
+192 
+$ 
+— 
+$ 
+192 
+Oil, natural gas and NGL derivatives 
+— 
+(2,945 
+) 
+— 
+(2,945 
+) 
+Total 
+$ 
+— 
+$ 
+(2,753 
+) 
+$ 
+— 
+$ 
+(2,753 
+) 
+Fair Value Measurements at 
+December 31, 2012 using 
+Description 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Certificates of deposit 
+$ 
+— 
+$ 
+230 
+$ 
+— 
+$ 
+230 
+Oil, natural gas and NGL derivatives 
+— 
+5,149 
+— 
+5,149 
+Oil, natural gas and NGL derivatives 
+— 
+(670 
+) 
+— 
+(670 
+) 
+Total 
+$ 
+— 
+$ 
+4,709 
+$ 
+— 
+$ 
+4,709 
+F- 34 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 12 — FAIR VALUE MEASUREMENTS — Continued 
+The Company’s accounting policies for certificates of deposit and derivative financial instruments are discussed in Note 2; additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that certificates of deposit and derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified at Level 2. 
+The Company accounts for additions to asset retirement obligations and lease and well equipment inventory when adjusted for impairment at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis as of December 31, 2013 and 2012 (in thousands). 
+Fair Value Measurements at 
+December 31, 2013 using 
+Description 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Asset retirement obligations 
+$ 
+— 
+$ 
+— 
+$ 
+(1,470 
+) 
+$ 
+(1,470 
+) 
+Total 
+$ 
+— 
+$ 
+— 
+$ 
+(1,470 
+) 
+$ 
+(1,470 
+) 
+Fair Value Measurements at 
+December 31, 2012 using 
+Description 
+Level 1 
+Level 2 
+Level 3 
+Total 
+Assets (Liabilities) 
+Asset retirement obligations 
+$ 
+— 
+$ 
+— 
+$ 
+(1,243 
+) 
+$ 
+(1,243 
+) 
+Lease and well equipment inventory 
+— 
+— 
+34 
+34 
+Total 
+$ 
+— 
+$ 
+— 
+$ 
+(1,209 
+) 
+$ 
+(1,209 
+) 
+The Company’s accounting policies for asset retirement obligations are discussed in Note 2; reconciliations of the Company’s asset retirement obligations are provided in Note 4 for the periods presented. For purposes of fair value measurement, the Company determined that the additions to asset retirement obligations should be classified at Level 3. The Company recorded additions to asset retirement obligations of approximately $1.5 million and $1.2 million in 2013 and 2012 , respectively. 
+The Company’s accounting policies for lease and well equipment inventory are discussed in Note 2. For purposes of fair value measurement, the Company determined that lease and well equipment inventory should be classified at Level 3. The Company recorded an impairment of $192,000 to its equipment, consisting primarily of pipe, held in inventory in 2013 . The Company recorded an impairment to some of its equipment held in inventory, consisting primarily of drilling rig parts and pipe, of $425,000 and $60,464 , respectively, in 2012. The Company periodically obtains estimates of the market value of its equipment held in inventory from an independent third-party contractor or seller of similar equipment and uses these estimates as a basis for its measurement of the fair value of this equipment. 
+F- 35 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES 
+Office Lease 
+The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. In April 2013 , the Company entered into the fifth amendment to its office lease agreement. This amendment increased the square footage of its corporate headquarters to 40,071 square feet effective July 1, 2013 . The lease expires on June 30, 2022 . 
+The effective base rent over the term of the new lease extension is $20.28 per square foot per year. The base rate escalates several times during the course of the lease, specifically in July 2015, July 2017, July 2019 and July 2020; however, the Company recognizes rent expense under the lease ratably over the term of the lease. 
+The following is a schedule of future minimum lease payments required under the office lease agreement as of December 31, 2013 (in thousands). 
+Year Ending December 31, 
+Amount 
+2014 
+$ 
+812 
+2015 
+831 
+2016 
+852 
+2017 
+872 
+2018 
+893 
+Thereafter 
+3,329 
+Total 
+$ 
+7,589 
+Rent expense, including fees for operating expenses and consumption of electricity, was $0.8 million , $0.6 million and $0.5 million for 2013 , 2012 and 2011 , respectively. 
+Natural Gas and NGL Processing and Transportation Commitments 
+Effective September 1, 2012 , the Company entered into a firm five -year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period. 
+Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain periods, the Company had an immaterial natural gas deficiency, and the counterparty to this agreement has agreed to waive the deficiency fee. The Company paid approximately $5.3 million and $0.3 million in processing and transportation fees under this agreement during the years ended December 31, 2013 and 2012 , respectively. 
+F- 36 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+The aggregate undiscounted minimum commitments under this agreement at December 31, 2013 are as follows (in thousands). 
+Year Ending December 31, 
+Amount 
+2014 
+$ 
+4,731 
+2015 
+2,992 
+2016 
+1,800 
+2017 
+1,195 
+Total 
+$ 
+10,718 
+Other Commitments 
+From time to time, the Company enters into contracts with third parties for drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided, which are typically for one year or less. Should the Company elect to terminate a contract and if the drilling contractor were unable to secure work for the contracted drilling rigs or if the drilling contractor were unable to secure work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under its drilling rig contracts were approximately $9.9 million at December 31, 2013 . 
+At December 31, 2013 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $5.7 million at December 31, 2013 . The Company expects these costs to be incurred within the next few months. 
+Legal Proceedings 
+Cynthia Fry Peironnet, et al. v. Matador Resources Company. The Company was involved in a dispute over a mineral rights lease (the “Lease”) involving certain acreage in Louisiana. The dispute regarded an extension of the term of the Lease in Caddo Parish, Louisiana where the Company has drilled or participated in the drilling of both Cotton Valley and Haynesville shale wells. At issue were the deep rights below the Cotton Valley formation on approximately 1,805 gross acres where the Company has the right to participate for up to a 25% working interest, and also retains a small overriding royalty interest, in Haynesville shale wells drilled in units that include portions of the acreage. The Company’s total net revenue and overriding royalty interests in several non-operated Haynesville shale wells previously drilled on this acreage range from approximately 2% to 23% , and only portions of these interests are attributable to this acreage. The sum of the Company’s overriding royalty and net revenue interests attributable to this acreage from Haynesville wells previously drilled on this acreage comprises less than one net well. 
+The plaintiffs brought this claim against the Company on May 15, 2008 in the First Judicial District Court, Caddo Parish, Louisiana (the “Trial Court”). The plaintiffs sought (i) reformation or rescission of the lease extension, (ii) an accounting for additional royalty, (iii) monetary damages and (iv) attorney’s fees. During the pendency of the case in the Trial Court, the Company settled with one lessor who owned a 1/6 th undivided interest in the minerals. The Trial Court rendered multiple rulings in the favor of the Company, including a unanimous jury verdict in favor of the Company in the fall of 2010. Final judgment of the Trial Court was rendered in favor of the Company on June 6, 2011. On August 1, 2012, the Louisiana Second Circuit of Appeal (the “Court of Appeal”) affirmed in part and reversed in part the judgment of the Trial Court and remanded the case to the Trial Court for determination of damages. The Court of Appeal affirmed the Trial Court with respect to the 1/6 th royalty owner that settled and also affirmed that the Company’s lease extension was unambiguous. Nonetheless, the Court of Appeal reformed the lease extension to cover only approximately 169 gross acres, holding that the deep rights covering the remaining 1,636 gross acres had expired. The Court of Appeal denied the Company’s motion for rehearing, and the Company and certain other defendants filed an appeal with the Louisiana Supreme Court. The Louisiana Supreme Court granted the requests to hear an appeal of the Court of Appeal’s decision, and in June 2013, the Louisiana Supreme Court reversed the decision of the Court 
+F- 37 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+of Appeal and reinstated the Trial Court judgment in its entirety. The plaintiffs filed an application for rehearing with the Louisiana Supreme Court, which was denied on August 30, 2013. 
+MRC Energy Company f/k/a Matador Resources Company, v. Orca ICI Development, J.V. The Company and Orca, a non-operator working interest owner, had various disputes regarding certain of the Company’s Eagle Ford shale wells and properties. Among other things, issues arose with respect to the rights and obligations of the Company and Orca under various agreements between the parties and Orca sought the Company’s consent to Orca’s proposed assignment of its 50% working interest in the Cowey #3H and #4H wells to a non-industry person, despite the presence of a uniform maintenance of interest provision. On April 2, 2013, Orca brought suit against the Company in the 57th Judicial District Court of Bexar County, Texas and sought injunctive relief. The court denied Orca’s demand for injunctive relief and on April 5, 2013, the Company moved to enforce arbitration provisions in the agreements between the parties. On April 22, 2013, the Company initiated an arbitration against Orca, seeking, among other things, a declaration that the Company could withhold its consent to Orca’s putative assignment of these interests. On May 6, 2013, Orca and the Company agreed to resolve all outstanding issues between the parties regarding the respective rights and obligations of the parties under the agreements between them. In addition, Matador agreed to allow Orca time to try to resolve the outstanding issue with respect to Orca’s purported assignment of its interest in the Cowey #3H and #4H wells and to stay the pending arbitration. Ultimately, pursuant to an amendment to the Purchase and Sale Agreement between the parties, the Company agreed to bear 100% of the costs to drill, complete and equip the Cowey #3H and #4H wells. Until such time as the Company has recovered 100% of the costs to drill, complete and equip these wells, all revenues generated by production from these two wells will be attributable to the Company. Following the Company’s recovery of these amounts, Orca would participate in the wells for a 25% working interest. The Company has returned $8.7 million submitted by Orca’s putative assignee. The agreement also included a mutual release of claims between the Company and Orca and provided for dismissal of the Bexar County litigation. Orca filed a notice of non-suit of the Bexar County litigation on August 7, 2013. 
+The Company is also a defendant in several lawsuits encountered in the ordinary course of its business. In the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial position, results of operations or cash flows. 
+General Federal and State Regulations 
+Oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in material compliance with currently applicable state and federal regulations. Because these rules and regulations are frequently amended or reinterpreted, however, the Company is unable to predict the future cost or impact of complying with these regulations. 
+Environmental Regulations 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. The Company’s activities are subject to a variety of environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA, the Safe Drinking Water Act, or SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. The Company is also subject to regulations governing the handling, transportation, storage and disposal of waste generated by its activities and of naturally occurring radioactive materials, or NORM, that may result from its oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species, and require investigation and cleanup of pollution. The Company has no outstanding material environmental remediation liabilities and believes that it is in material compliance with currently applicable environmental laws and regulations and that these laws and 
+F- 38 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 13 — COMMITMENTS AND CONTINGENCIES — Continued 
+regulations will not have a material adverse impact on the financial position, results of operations or cash flows of the Company. 
+Changes in environmental laws and regulations occur frequently, however, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations and cash flows, as well as those of the oil and natural gas industry in general. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require the Company to incur increased operating costs adversely affecting its financial position, results of operations and cash flows. 
+The Company’s activities involve the use of hydraulic fracturing. Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) at the federal level. At the federal level and in some states, there have been efforts to place additional regulatory burdens on hydraulic fracturing activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens on hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will result in additional expense and delay the Company’s operations adversely affecting its financial position, results of operations and cash flows. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of the Company’s properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, may require remediation. In addition, the Company occasionally must agree to indemnify sellers of producing properties the Company acquires against some or all of the liability for environmental claims associated with these properties. While the Company does not believe that the costs it incurs for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, the Company cannot provide assurances that these costs will not result in material expenditures that adversely affect its financial position, results of operations and cash flows. 
+The Company maintains insurance against some, but not all, potential risks and losses associated with the oil and natural gas industry and operations. The Company does not carry business interruption insurance. For some risks, the Company may not obtain insurance if it believes the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations and cash flows. 
+F- 39 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 14 — SUPPLEMENTAL DISCLOSURES 
+Accrued Liabilities 
+The following table summarizes the Company’s current accrued liabilities at December 31, 2013 and 2012 (in thousands). 
+December 31, 
+2013 
+2012 
+Accrued evaluated and unproved and unevaluated property costs 
+$ 
+52,605 
+$ 
+45,592 
+Accrued support equipment and facilities costs 
+— 
+1,382 
+Accrued stock-based compensation 
+56 
+65 
+Accrued lease operating expenses 
+6,251 
+5,218 
+Accrued interest on borrowings under Credit Agreement 
+141 
+255 
+Accrued asset retirement obligations 
+175 
+660 
+Accrued partners’ share of joint interest charges 
+1,173 
+3,597 
+Other 
+3,586 
+2,410 
+Total accrued liabilities 
+$ 
+63,987 
+$ 
+59,179 
+Supplemental Cash Flow Information 
+The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2013, 2012 and 2011 (in thousands). 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Cash paid for interest expense, net of amounts capitalized 
+$ 
+5,801 
+$ 
+780 
+$ 
+634 
+Asset retirement obligations related to mineral properties 
+1,363 
+1,195 
+488 
+Asset retirement obligations related to support equipment and facilities 
+3 
+49 
+12 
+Increase in liabilities for oil and natural gas properties capital expenditures 
+7,548 
+24,847 
+1,864 
+Increase in liabilities for support equipment and facilities 
+660 
+1,112 
+175 
+Issuance of restricted stock units for Board and advisor services 
+274 
+73 
+— 
+Issuance of common stock for Board and advisor services 
+57 
+71 
+230 
+(Decrease) increase in liabilities for accrued cost to issue equity 
+— 
+(332 
+) 
+(27 
+) 
+Stock-based compensation expense recognized as liability 
+1,012 
+(1,092 
+) 
+2,102 
+Transfer of inventory to oil and natural gas properties 
+343 
+69 
+96 
+NOTE 15 — SUBSIDIARY GUARANTORS 
+Matador filed a registration statement on Form S-3 with the SEC, which became effective May 9, 2013, and registered, among other securities, debt securities. The subsidiaries of Matador (the “Subsidiaries”) are co-registrants with Matador, and the registration statement registers guarantees of debt securities by the Subsidiaries. As of December 31, 2013, the Subsidiaries are 100% owned by Matador, and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). Matador has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to Matador. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by Matador, such guarantees will constitute joint and several obligations. 
+NOTE 16 — SUBSEQUENT EVENTS 
+On March 12, 2014 , the borrowing base under the Company’s Credit Agreement was increased to $385.0 million based on the lenders’ review of its proved oil and natural gas reserves at December 31, 2013 . At that time, the Credit Agreement was also amended to include Wells Fargo Bank, N.A., which replaced Capital One, N.A., in the Company’s lending group, which 
+F- 40 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED 
+December 31, 2013, 2012 and 2011 
+NOTE 16 — SUBSEQUENT EVENTS — Continued 
+also includes RBC as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia, SunTrust Bank, BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank. The amendment also provided that the borrowing base will automatically be reduced to the conforming borrowing base on the earlier of (i) June 30, 2015 or (ii) concurrent with the issuance by the Company of senior unsecured notes in an amount greater than or equal to $10.0 million . At March 13, 2014 , the Company had $250.0 million in borrowings and $0.3 million in letters of credit outstanding under its Credit Agreement. The Company incurred $0.8 million of additional deferred loan costs in connection with the borrowing base redetermination and amendment of the Credit Agreement. These costs will be included with the remaining unamortized portion of the deferred loan costs of $2.1 million at December 31, 2013 to be amortized over the term of the agreement. 
+In February 2014 , the Company granted awards of options to purchase 49,721 shares of the Company’s common stock at an exercise price of $19.71 per share to certain of its employees. The fair value of these awards was approximately $0.4 million . The Company also granted awards of 19,787 shares of restricted stock to certain of its employees in February 2014 . The fair value of these restricted stock awards was approximately $0.4 million . All of these awards vest over a term of four years. In March 2014, the Company granted awards of options to purchase 224,962 of the Company’s common stock at an exercise price of $23.40 per share to certain of its employees. The fair value of these awards was approximately $2.2 million . The Company also granted awards of 67,690 shares of restricted stock to certain of its employees. The fair value of these awards was approximately $1.5 million . All of these awards vest over a term of four years. 
+Subsequent to December 31, 2013 , the Company entered into new contracts with respect to its contracted drilling rigs. The Company’s maximum outstanding termination obligations under its drilling rig contracts were approximately $13.7 million at March 13, 2014 . 
+Subsequent to December 31, 2013 , the Company agreed to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed, the Company will have minimum outstanding aggregate commitments for its participation in these wells of approximately $20.1 million at March 13, 2014 , which it expects to incur within the next six months. 
+F- 41 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+UNAUDITED SUPPLEMENTARY INFORMATION 
+December 31, 2013, 2012 and 2011 
+SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES 
+Costs Incurred 
+The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration and development of oil and natural gas properties for the years ended December 31, 2013, 2012 and 2011 (in thousands). 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Property acquisition costs 
+Proved 
+$ 
+176 
+$ 
+— 
+$ 
+— 
+Unproved and unevaluated 
+64,305 
+28,672 
+41,497 
+Exploration costs 
+99,104 
+115,084 
+108,662 
+Development costs 
+209,956 
+190,891 
+12,511 
+Total costs incurred 
+$ 
+373,451 
+$ 
+334,647 
+$ 
+162,670 
+Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2013, 2012 and 2011 , respectively, essentially all of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions. 
+Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties. 
+Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and installing production facilities. 
+Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $1.5 million , $1.2 million and $0.5 million for the years ended December 31, 2013, 2012 and 2011 , respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $3.7 million , $2.6 million and $2.0 million of these internal costs in 2013 , 2012 and 2011 , respectively. Capitalized interest expense for qualifying projects is also included in the table above. The Company capitalized $1.9 million , $1.6 million and $1.3 million of its interest expense for the years ended December 31, 2013 , 2012 and 2011 , respectively. 
+F- 42 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED 
+December 31, 2013, 2012 and 2011 
+SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued 
+Oil and Natural Gas Reserves 
+Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. 
+The Company reports its production and proved reserves in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where the Company produces liquids-rich natural gas, such as in the Eagle Ford shale in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on these properties where the natural gas liquids are extracted and sold. The Company’s oil and natural gas reserves estimates for the years ended December 31, 2013, 2012 and 2011 were prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. 
+Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12 -month period. For the period from January through December 2013 , these average oil and natural gas prices were $93.42 per barrel and $3.670 per MMBtu, respectively. For the period from January through December 2012, these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period from January through December 2011, these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. 
+The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil to six Mcf of natural gas. 
+F- 43 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED 
+December 31, 2013, 2012 and 2011 
+SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued 
+Net Proved Reserves 
+Oil 
+Gas 
+Oil 
+Equivalent 
+(MBbl) 
+(MMcf) 
+(MBOE) 
+Total at December 31, 2010 
+152 
+127,412 
+21,387 
+Revisions of prior estimates 
+51 
+(646 
+) 
+(57 
+) 
+Extensions and discoveries 
+3,745 
+58,164 
+13,439 
+Production 
+(154 
+) 
+(14,512 
+) 
+(2,573 
+) 
+Total at December 31, 2011 
+3,794 
+170,418 
+32,196 
+Revisions of prior estimates 
+(782 
+) 
+(103,375 
+) 
+(18,010 
+) 
+Extensions and discoveries 
+8,687 
+25,443 
+12,927 
+Production 
+(1,214 
+) 
+(12,479 
+) 
+(3,294 
+) 
+Total at December 31, 2012 
+10,485 
+80,007 
+23,819 
+Revisions of prior estimates 
+(199 
+) 
+78,812 
+12,936 
+Purchases of minerals in-place 
+— 
+170 
+28 
+Extensions and discoveries 
+8,209 
+66,121 
+19,231 
+Production 
+(2,133 
+) 
+(12,915 
+) 
+(4,285 
+) 
+Total at December 31, 2013 
+16,362 
+212,195 
+51,729 
+Proved Developed Reserves 
+December 31, 2010 
+152 
+43,143 
+7,342 
+December 31, 2011 
+1,419 
+56,547 
+10,843 
+December 31, 2012 
+4,764 
+54,040 
+13,771 
+December 31, 2013 
+8,258 
+53,458 
+17,168 
+Proved Undeveloped Reserves 
+December 31, 2010 
+— 
+84,269 
+14,045 
+December 31, 2011 
+2,375 
+113,871 
+21,353 
+December 31, 2012 
+5,721 
+25,967 
+10,048 
+December 31, 2013 
+8,104 
+158,737 
+34,561 
+The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2013, 2012 and 2011 . 
+The Company’s proved oil and natural gas reserves increased to 51,729 MBOE at December 31, 2013 from 23,819 MBOE at December 31, 2012 . The Company’s proved oil and natural gas reserves increased by 32,195 MBOE and the Company produced 4,285 MBOE during the year ended December 31, 2013 , resulting in a net increase of 27,910 MBOE. An increase of 19,231 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas and additional proved undeveloped natural gas reserves identified on the Company’s properties in the Haynesville shale. The Company’s proved oil and natural gas reserves increased by 12,936 MBOE during the year as a result of revisions to previous estimates, primarily upward revisions in the Company’s proved undeveloped natural gas reserves resulting from higher natural gas prices in 2013 . The Company also purchased minerals in-place with proved reserves of 28 MBOE in 2013. The Company’s proved developed oil and natural gas reserves increased to 17,168 MBOE at December 31, 2013 from 13,771 MBOE at December 31, 2012 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2013 , the Company’s proved reserves were made up of approximately 32% oil and 68% natural gas. 
+The Company’s proved oil and natural gas reserves decreased to 23,819 MBOE at December 31, 2012 from 32,196 MBOE at December 31, 2011 . The Company’s proved oil and natural gas reserves decreased by 5,083 MBOE and the Company produced 3,294 MBOE during the year ended December 31, 2012 , resulting in a net decrease of 8,377 MBOE. An increase of 12,927 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas. The Company’s oil and 
+F- 44 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED 
+December 31, 2013, 2012 and 2011 
+SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued 
+natural gas reserves decreased by 18,010 MBOE during the year as a result of revisions to previous estimates, primarily resulting from lower natural gas prices in 2012 . The Company’s proved developed oil and natural gas reserves increased to 13,771 MBOE at December 31, 2012 from 10,843 MBOE at December 31, 2011 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2012 , the Company’s proved reserves were made up of approximately 44% oil and 56% natural gas. 
+The Company’s proved oil and natural gas reserves increased to 32,196 MBOE at December 31, 2011 from 21,387 MBOE at December 31, 2010 . The Company increased its proved oil and natural gas reserves by 13,382 MBOE and produced 2,573 MBOE during the year ended December 31, 2011 , resulting in a net gain of 10,809 MBOE. A total of 13,439 MBOE of the increase in proved oil and natural gas reserves was a result of extensions and discoveries during the year, all of which was attributable to drilling operations in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. The Company’s oil and natural gas reserves decreased by 57 MBOE during the year as a result of revisions to previous estimates, representing the net impact of small changes in prior estimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to 10,843 MBOE at December 31, 2011 from 7,342 MBOE at December 31, 2010 , primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford and Haynesville shale plays. At December 31, 2011 , the Company’s proved reserves were made up of approximately 12% oil and 88% natural gas. 
+Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves 
+The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates. 
+As noted previously, for the period from January through December 2013 , the unweighted, arithmetic average of first-day-of-the-month oil and natural gas prices were $93.42 per barrel and $3.670 per MMBtu, respectively. For the period from January through December 2012 , the comparable average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period from January through December 2011 , the comparable average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. 
+Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation and marketing costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations. 
+Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows. 
+F- 45 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+UNAUDITED SUPPLEMENTARY INFORMATION — CONTINUED 
+December 31, 2013, 2012 and 2011 
+SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES — Continued 
+The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011 (in thousands). 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Future cash inflows 
+$ 
+2,316,626 
+$ 
+1,273,882 
+$ 
+924,796 
+Future production costs 
+(666,450 
+) 
+(325,413 
+) 
+(194,538 
+) 
+Future development costs 
+(507,923 
+) 
+(244,283 
+) 
+(235,469 
+) 
+Future income tax expense 
+(181,041 
+) 
+(77,821 
+) 
+(83,840 
+) 
+Future net cash flows 
+961,212 
+626,365 
+410,949 
+10% annual discount for estimated timing of cash flows 
+(382,544 
+) 
+(231,729 
+) 
+(195,476 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+578,668 
+$ 
+394,636 
+$ 
+215,473 
+The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011 (in thousands). 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Balance, beginning of period 
+$ 
+394,636 
+$ 
+215,473 
+$ 
+111,077 
+Net change in sales and transfer prices and in production (lifting) costs related to future production 
+(97,511 
+) 
+(60,892 
+) 
+53,903 
+Changes in estimated future development costs 
+(233,232 
+) 
+16,937 
+(64,958 
+) 
+Sales and transfers of oil and natural gas produced during the period 
+(209,338 
+) 
+(116,142 
+) 
+(53,478 
+) 
+Purchases of reserves 
+176 
+— 
+— 
+Net change due to extensions and discoveries 
+386,696 
+358,159 
+182,282 
+Net change due to revisions in estimates of reserves quantities 
+260,148 
+(56,850 
+) 
+(653 
+) 
+Previously estimated development costs incurred during the period 
+106,348 
+9,750 
+1,023 
+Accretion of discount 
+36,184 
+24,873 
+11,987 
+Other 
+(371 
+) 
+(290 
+) 
+(1,335 
+) 
+Net change in income taxes 
+(65,068 
+) 
+3,618 
+(24,375 
+) 
+Standardized measure of discounted future net cash flows 
+$ 
+578,668 
+$ 
+394,636 
+$ 
+215,473 
+F- 46 
+Table of Contents 
+Matador Resources Company and Subsidiaries 
+UNAUDITED SUPPLEMENTARY INFORMATION 
+December 31, 2013, 2012 and 2011 
+SELECTED QUARTERLY FINANCIAL INFORMATION 
+The following table presents selected unaudited quarterly financial information for 2013 (in thousands, except per share data). 
+December 31 
+September 30 
+June 30 
+March 31 
+2013 
+Oil and natural gas revenues 
+$ 
+69,664 
+$ 
+81,868 
+$ 
+58,179 
+$ 
+59,319 
+Realized (loss) gain on derivatives 
+(390 
+) 
+(1,165 
+) 
+254 
+392 
+Unrealized (loss) gain on derivatives 
+(606 
+) 
+(9,327 
+) 
+7,526 
+(4,825 
+) 
+Expenses 
+45,513 
+46,736 
+39,054 
+69,141 
+Other expense 
+724 
+1,972 
+1,754 
+1,204 
+Income (loss) before income taxes 
+22,431 
+22,668 
+25,151 
+(15,459 
+) 
+Income tax provision (benefit) 
+7,056 
+2,563 
+32 
+46 
+Net income (loss) 
+$ 
+15,375 
+$ 
+20,105 
+$ 
+25,119 
+$ 
+(15,505 
+) 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+0.23 
+$ 
+0.35 
+$ 
+0.45 
+$ 
+(0.28 
+) 
+Class B 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+Diluted 
+Class A 
+$ 
+0.23 
+$ 
+0.35 
+$ 
+0.45 
+$ 
+(0.28 
+) 
+Class B 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+The following table presents selected unaudited quarterly financial information for 2012 (in thousands, except per share data). 
+December 31 
+September 30 
+June 30 
+March 31 
+2012 
+Oil and natural gas revenues 
+$ 
+52,748 
+$ 
+38,008 
+$ 
+36,078 
+$ 
+29,164 
+Realized gain on derivatives 
+2,813 
+3,371 
+4,713 
+3,063 
+Unrealized (loss) gain on derivatives 
+(3,653 
+) 
+(12,993 
+) 
+15,114 
+(3,270 
+) 
+Expenses 
+72,377 
+38,087 
+66,263 
+21,857 
+Other expense 
+907 
+89 
+31 
+235 
+(Loss) income before income taxes 
+(21,376 
+) 
+(9,790 
+) 
+(10,389 
+) 
+6,865 
+Income tax (benefit) provision 
+(188 
+) 
+(593 
+) 
+(3,713 
+) 
+3,064 
+Net (loss) income 
+$ 
+(21,188 
+) 
+$ 
+(9,197 
+) 
+$ 
+(6,676 
+) 
+$ 
+3,801 
+Earnings (loss) per common share 
+Basic 
+Class A 
+$ 
+(0.38 
+) 
+$ 
+(0.17 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.08 
+Class B 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+0.15 
+Diluted 
+Class A 
+$ 
+(0.38 
+) 
+$ 
+(0.17 
+) 
+$ 
+(0.12 
+) 
+$ 
+0.08 
+Class B 
+$ 
+— 
+$ 
+— 
+$ 
+— 
+$ 
+0.15 
+F- 47
\ No newline at end of file
diff --git a/raw/filings/0001520006/2013/0001520006-14-000017/filing_metadata.csv b/raw/filings/0001520006/2013/0001520006-14-000017/filing_metadata.csv
new file mode 100644
index 0000000000000000000000000000000000000000..4af0dccb8b59a0539c29c080481cc3fca8d9caa4
--- /dev/null
+++ b/raw/filings/0001520006/2013/0001520006-14-000017/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
+0001520006,MTDR,Matador Resources Co,10-K,2014-03-17,2013-12-31,2014-03-17T15:30:21.000Z,0001520006-14-000017,mtdr10-k12312013.htm,10-K,18855168,1,0,https://www.sec.gov/Archives/edgar/data/1520006/000152000614000017/mtdr10-k12312013.htm,https://www.sec.gov/Archives/edgar/data/1520006/000152000614000017/,2013,2013,1
diff --git a/raw/filings/0001520006/2013/0001520006-14-000017/item1.txt b/raw/filings/0001520006/2013/0001520006-14-000017/item1.txt
new file mode 100644
index 0000000000000000000000000000000000000000..8c96f88b9d6461875026b85a3eeaf7ed9f3cd1ed
--- /dev/null
+++ b/raw/filings/0001520006/2013/0001520006-14-000017/item1.txt
@@ -0,0 +1,1023 @@
+Item 1. Business. 
+In this Annual Report on Form 10-K, references to “we,” “our” or “the Company” refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly-owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company. 
+Unless the context otherwise requires, the term “common stock” refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering on February 7, 2012, as the Class A common stock then became the only class of common stock authorized, and the term “Class A common stock” refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our initial public offering. 
+For certain oil and natural gas terms used in this Annual Report on Form 10-K, see the “Glossary of Oil and Natural Gas Terms” included in this Annual Report on Form 10-K. 
+General 
+We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Our current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. We also operate in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. In addition, we have a large exploratory leasehold position in Southwest Wyoming and adjacent areas of Utah and Idaho where we are testing the Meade Peak shale. 
+We are a Texas corporation founded in July 2003 by Joseph Wm. Foran, Chairman and CEO. Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc., in an all cash transaction for an enterprise value of approximately $388.5 million. 
+On February 2, 2012, our common stock began trading on the New York Stock Exchange (the “NYSE”) under the symbol “MTDR.” Prior to trading on the NYSE, there was no established public trading market for our common stock. 
+Our goal is to increase shareholder value by building oil and natural gas reserves, production and cash flows at an attractive rate of return on invested capital. We plan to achieve our goal by, among other items, executing the following business strategies: 
+• focus exploration and development activity on our Eagle Ford acreage in South Texas; 
+• explore and develop our Wolfcamp and Bone Spring acreage in the Permian Basin; 
+• identify, evaluate and develop oil and natural gas plays to maintain a balanced portfolio; 
+• continue to improve operational and cost efficiencies; 
+• maintain our financial discipline; and 
+• pursue opportunistic acquisitions. 
+The successful execution of our business strategies in 2013 led to significant increases in our oil and natural gas revenues and Adjusted EBITDA, oil production and proved oil and natural gas reserves, and the associated increase in the PV-10 of our proved reserves. We also significantly increased our leasehold position in the Permian Basin and added to our acreage positions in the Eagle Ford shale and the Haynesville shale. Adjusted EBITDA and PV-10 are non-GAAP financial measures. For a definition of such terms and a reconciliation to the most directly comparable GAAP financial measures, see “Selected Financial Data — Non-GAAP Financial Measures” and “—Estimated Proved Reserves.” 
+3 
+Table of Contents 
+2013 Highlights 
+Increased Oil and Natural Gas Revenues and Adjusted EBITDA 
+Our oil and natural gas revenues for the year ended December 31, 2013 were the highest achieved in any fiscal year in the Company’s history. Our oil and natural gas revenues increased $113.0 million to $269.0 million in 2013 , which represents an increase of 72% from 2012. This revenue increase was primarily driven by a significant increase in our oil production in 2013 and a higher weighted average natural gas price realized in 2013 . Our Adjusted EBITDA of $191.8 million for 2013 was an increase of 65% , as compared to our Adjusted EBITDA of $115.9 million for 2012. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see “Selected Financial Data — Non-GAAP Financial Measures.” 
+Increased Oil and Oil Equivalent Production 
+Our total oil production and our average daily oil equivalent production for the year ended December 31, 2013 were the best in our history. In 2013 , we produced 2.1 million barrels of oil, an increase of 76% , as compared to 1.2 million barrels of oil produced in 2012. Our average daily oil equivalent production was 11,740 BOE per day, including 5,843 Bbl of oil per day and 35.4 MMcf of natural gas per day, an increase of 30% , as compared to 9,000 BOE per day, including 3,317 Bbl of oil per day and 34.1 MMcf of natural gas per day, for the year ended December 31, 2012 . This increase in oil production was a direct result of our drilling operations in the Eagle Ford shale. We achieved this increased oil production despite having as much as 15% to 20% of our production capacity shut in at various times during 2013 , as we continued our operational practices of pad and batch drilling in the Eagle Ford shale and shutting in producing wells while conducting drilling and completion operations on offsetting wells. Oil production comprised 50% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the year ended December 31, 2013 , as compared to 37% for the year ended December 31, 2012 and 6% for the year ended December 31, 2011. 
+Increased Oil and Natural Gas Reserves 
+At December 31, 2013 , our estimated total proved oil and natural gas reserves were 51.7 million BOE, including 16.4 million Bbl of oil and 212.2 Bcf of natural gas, which is an increase of 117% from December 31, 2012 . The associated PV-10 of our estimated total proved oil and natural gas reserves increased 55% to $655.2 million at December 31, 2013 from $423.2 million at December 31, 2012 . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “—Estimated Proved Reserves.” 
+Our proved oil reserves grew 56% to 16.4 million Bbl at December 31, 2013 , as compared to 10.5 million Bbl at December 31, 2012 . This growth in oil reserves was primarily attributable to our drilling program in the Eagle Ford shale during 2013. Our proved natural gas reserves increased 165% to 212.2 Bcf at December 31, 2013 from 80.0 Bcf at December 31, 2012 . This large increase in proved natural gas reserves was attributable to our drilling and completion activities and improvements in natural gas prices in 2013. As a result of the continued improvement in natural gas prices during 2013, we re-classified Haynesville shale natural gas volumes previously removed from our proved reserves in 2012 as proved undeveloped reserves in 2013 and also included additional Haynesville shale proved undeveloped natural gas reserves in our total proved reserves at December 31, 2013 . 
+At December 31, 2013 , proved developed reserves included 8.3 million Bbl of oil and 53.5 Bcf of natural gas, and proved undeveloped reserves included 8.1 million Bbl of oil and 158.7 Bcf of natural gas. Proved developed reserves comprised 33% and proved oil reserves comprised 32% of our total proved oil and natural gas reserves, respectively, at December 31, 2013 . Based on our 2013 year-end total proved reserves and our 2013 oil equivalent production of 4.3 million BOE, we improved our reserves/production (“R/P”) ratio to 12.1 years at December 31, 2013 , as compared to 7.2 years at December 31, 2012 . 
+Operational Efficiencies 
+We focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the cost incurred and to minimize our operating costs per BOE produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. This allows us to manage more effectively operating costs, the pace of development activities, technical applications, the gathering and marketing of our production and capital allocation. Additionally, we concentrate on our core areas, which allows us to achieve economies of scale and reduce operating costs. Largely as a result of these factors, we believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past two years. 
+D uring this time, we have progressed from drilling wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In August 2013, we began drilling certain wells on our western Eagle Ford acreage from batch drilled pads using a drilling rig equipped with a “walking” package and, as a result, we have improved both drilling times and costs. We have realized cost savings of approximately $325,000 per well on initial wells drilled using this rig, and we expect the use of batch drilling and the “walking” rig will lead to total cost savings of approximately $400,000 per well or more going 
+4 
+Table of Contents 
+forward. Recent wells drilled on our western Eagle Ford acreage in La Salle County, Texas have drilling times from spud to total depth of eight to 10 days per well and costs at or just below $6 million per well. In April 2014, we expect to replace the drilling rig currently operating in the central portion of our acreage in Karnes and Wilson Counties, Texas with a new “walking” rig. At that time, we will have two “walking” rigs operating in the Eagle Ford and will conduct batch drilling operations on our properties using these rigs for the balance of 2014. Recent wells in our central Eagle Ford acreage have been drilled for between $7.0 and $7.5 million, but we expect to see further cost improvements with the initiation of batch drilling operations in this area as well. We anticipate that we will drill almost 250,000 lateral feet with two rigs in the Eagle Ford in 2014, as compared to 150,000 feet using two rigs in 2012 and effectively 1.5 rigs in 2013, an increased drilling efficiency of almost 70%. 
+During 2013, we continued to refine the design of our hydraulic fracture treatments to enhance well productivity and ultimate hydrocarbon recovery, increasing fluid volumes to 40 Bbl per foot and proppant volumes to more than 2,000 pounds per foot, while decreasing the spacing between perforation clusters where the fractures are initiated. These Generation 5, and now Generation 6, fracture treatments are resulting in significant improvements in initial well productivity as compared to earlier generation treatment designs. We also believe that initiating the use of gas lift relatively early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. 
+Acreage Acquisitions 
+During 2013, we acquired approximately 55,400 gross (38,900 net) acres in the Permian Basin in Southeast New Mexico and West Texas. These acreage acquisitions brought our total Permian Basin acreage position to approximately 70,800 gross (44,800 net) acres as of December 31, 2013 . Between January 1 and December 31, 2013 , we also acquired approximately 1,720 gross (1,660 net) acres in the Eagle Ford shale play in South Texas and approximately 1,190 gross (1,190 net) acres in the Haynesville shale play in Northwest Louisiana. 
+Issuance of Common Stock 
+In April 2013, we filed with the SEC a universal shelf registration statement on Form S-3 (the “Shelf Registration Statement”), which provided us with the ability to offer and sell up to $300 million of debt and equity securities, subject to market conditions and our capital needs. The SEC declared the Shelf Registration Statement effective on May 9, 2013. As of December 31, 2013, we had approximately $151 million of securities available for issuance under the Shelf Registration Statement. 
+On September 10, 2013, we completed an underwritten public offering of 9,775,000 shares of our common stock and received net proceeds of approximately $141.7 million. The net proceeds from this offering were used to fund a portion of our capital expenditures, including the addition of a third rig to our drilling program and the acquisition of additional acreage in the Eagle Ford shale, the Permian Basin and the Haynesville shale. Pending such uses, we used a portion of the net proceeds to repay $130.0 million in outstanding borrowings under our third amended and restated credit agreement (the “Credit Agreement”) in September 2013, which amounts may be reborrowed in accordance with the terms of that facility for, among other items, the uses contemplated above. 
+Recent Developments 
+On March 12, 2014 , the borrowing base under our Credit Agreement was increased to $385.0 million , and the conforming borrowing base was increased to $310.0 million based on the lenders’ review of our proved oil and natural gas reserves at December 31, 2013 . At that time, we also amended our Credit Agreement to include Wells Fargo Bank, N.A., which replaced Capital One, N.A., in our lending group, which also includes Royal Bank of Canada, as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia, SunTrust Bank, BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank. At March 13, 2014 , we had $250.0 million in borrowings and $0.3 million in letters of credit outstanding under our Credit Agreement. 
+Between January 1 and March 13, 2014 , we acquired an additional 7,000 gross (5,300 net) acres in Southeast New Mexico and West Texas, bringing our total Permian Basin acreage position to 77,800 gross (50,100 net) acres as of March 13, 2014 . 
+Principal Areas of Interest 
+Our focus since inception has been the exploration for oil and natural gas in unconventional plays with an emphasis in recent years on the Eagle Ford shale play in South Texas, the Haynesville shale play in Northwest Louisiana and most recently, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. During 2013 , we devoted most of our efforts and most of our capital investment to our drilling operations in the Eagle Ford shale in South Texas as we sought to continue to increase our oil production and reserves. Since our inception, our exploration efforts have 
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+concentrated primarily on known hydrocarbon-producing basins with well-established production histories offering the potential for multiple-zone completions. We have also sought to balance the risk profile of our prospects by exploring for more conventional targets as well, although at December 31, 2013, essentially all of our efforts are focused on unconventional plays. 
+At December 31, 2013 , our principal areas of interest consisted of the Eagle Ford shale play in South Texas, the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas, the Haynesville shale play, as well as the traditional Cotton Valley and Hosston (Travis Peak) formations, in Northwest Louisiana and East Texas, and the Meade Peak shale play in Southwest Wyoming and the adjacent areas of Utah and Idaho. 
+The following table presents certain summary data for each of our operating areas as of and for the year ended December 31, 2013 : 
+Producing 
+Total Identified 
+Estimated Net Proved 
+Wells 
+Drilling Locations (1) 
+Reserves (2) 
+Avg. Daily 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+% 
+Production 
+Acreage 
+MBOE (3) 
+Developed 
+(BOE/d) (3) 
+South Texas: 
+Eagle Ford (4) 
+27,147 
+73 
+63.3 
+273 
+229.3 
+20,221 
+54.9 
+8,225 
+NW Louisiana/E Texas: 
+Haynesville 
+14,969 
+140 
+13.0 
+527 
+114.5 
+28,797 
+14.9 
+2,831 
+Cotton Valley (5) 
+21,821 
+100 
+63.7 
+71 
+49.3 
+1,339 
+100.0 
+600 
+Area Total (6) 
+25,761 
+240 
+76.7 
+598 
+163.8 
+30,136 
+18.7 
+3,431 
+Permian Basin: 
+SE New Mexico, West Texas (7) 
+44,834 
+13 
+5.0 
+241 
+177.7 
+1,372 
+31.1 
+84 
+Other: 
+Wyoming, Utah, Idaho 
+36,004 
+— 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+133,746 
+326 
+145.0 
+1,112 
+570.8 
+51,729 
+33.2 
+11,740 
+__________________ 
+(1) 
+Identified and engineered drilling locations. These locations have been identified for potential future drilling and were not producing at December 31, 2013 . The total net engineered drilling locations is calculated by multiplying the gross engineered drilling locations in an operating area by our working interest participation in such locations. At December 31, 2013 , these engineered drilling locations included 52 gross (39.8 net) locations to which we have assigned proved undeveloped reserves in the Eagle Ford, four gross (3.4 net) locations to which we have assigned proved undeveloped reserves in the Wolfcamp or Bone Spring plays in the Permian Basin and 125 gross (20.6 net) locations to which we have assigned proved undeveloped reserves in the Haynesville. We had no proved undeveloped reserves assigned to engineered drilling locations in any other formation at December 31, 2013 . 
+(2) 
+These estimates were prepared by our engineering staff and audited by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. 
+(3) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(4) 
+Includes two wells producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(5) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+(6) 
+Some of the same leases cover the net acres shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the net acreage for both formations is not equal to the total net acreage for Northwest Louisiana and East Texas. This total includes acreage that we are producing from or that we believe to be prospective for these formations. 
+(7) 
+Includes potential future engineered drilling locations in the Wolfcamp, Bone Spring or Avalon shale plays on our acreage in the Permian Basin at December 31, 2013 . 
+We are active both as an operator and as a co-working interest owner with larger industry participants, including affiliates of EOG Resources, Inc., Royal Dutch Shell plc, Chesapeake Energy Corporation, EP Energy Company, Concho Resources Inc., Devon Energy Corporation and others. At December 31, 2013 , we were the operator for approximately 90% of our Eagle Ford acreage and 70% of our Haynesville acreage, including approximately 36% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in the core area of the Haynesville shale is operated by a subsidiary of Chesapeake Energy Corporation. We also operate the majority of our acreage in the Permian Basin in Southeast New Mexico and West Texas, as well as all of our acreage in Southwest Wyoming and the adjacent areas of Utah and Idaho. In those wells where we are not the operator, our working interests are often relatively small, particularly in the Haynesville shale. 
+From time to time, we enter into joint operating agreements with our co-working interest partners governing operations on certain of our jointly owned wells and properties. Particularly when our working interest is small, however, we do not 
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+always enter into formal operating agreements with the operators, and in such cases, we rely on applicable legal and statutory authority to govern our business arrangement in accordance with industry standard practices. Where we do have joint operating agreements with affiliates of other companies, these agreements call for significant penalties should we elect not to participate in the drilling and completion of a well proposed by the operator, or a non-consent well. These non-consent penalties typically allow the operator to recover up to 400% of its costs to drill, complete and equip the non-consent well from the well’s future net revenue prior to us being allowed to participate in the non-consent well for our original working interest. Ultimately, the amount of these penalties may result in us having no participation at all in the non-consent well. We also have the right to propose wells under these joint operating agreements, and the same non-consent penalties apply to the operator should it elect not to consent to a well that we propose. 
+While we do not always have direct access to our operating partners’ drilling plans with respect to future well locations on non-operated properties, we do attempt to maintain ongoing communications with the technical staff of these operators in an effort to understand their drilling plans for purposes of our capital expenditure budget and our booking of any related proved undeveloped well locations and reserves. We review these locations with Netherland, Sewell & Associates, Inc. , independent reservoir engineers, on a periodic basis to ensure their concurrence with our estimates of these drilling plans and our approach to booking these reserves. 
+South Texas — Eagle Ford Shale and Other Formations 
+The Eagle Ford shale extends across portions of South Texas from the Mexican border into East Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford is an organically rich calcareous shale and lies between the deeper Buda limestone and the shallower Austin Chalk formation. Along the entire length of the Eagle Ford trend, the structural dip of the formation is consistently down to the south with relatively few, modestly sized structural perturbations. As a result, depth of burial increases consistently southwards along with the thermal maturity of the formation. Where the Eagle Ford is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford is more natural gas prone. The transition between being more oil prone and more natural gas prone includes an interval that typically produces liquids-rich natural gas with condensate. 
+At December 31, 2013 , our properties included approximately 39,000 gross ( 27,100 net) acres in the Eagle Ford shale play in Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties in South Texas. We believe that approximately 87% of our Eagle Ford acreage is prospective predominantly for oil or liquids-rich natural gas with condensate. In addition, we believe that portions of this acreage may also be prospective for other targets, such as the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. Approximately 82% of our Eagle Ford acreage was held by production at December 31, 2013 , and approximately 97% of our Eagle Ford acreage was either held by production at December 31, 2013 or not burdened by lease expirations before 2015 . During the year ended December 31, 2013 , we acquired approximately 1,720 gross (1,660 net) acres in the Eagle Ford shale play that we consider to be prospective primarily for oil production. This acreage essentially replaced the acreage upon which we drilled and established oil and natural gas production and reserves during 2013 . 
+At December 31, 2013 , we had 73 gross ( 63.3 net) wells producing from the Eagle Ford shale in South Texas. We had drilled and completed a total of 61 gross (59.5 net) Eagle Ford wells on our operated properties, and we had also participated in 12 gross (3.8 net) Eagle Ford wells with co-working interest owners on certain of our non-operated Eagle Ford properties. 
+During 2013 , approximately 70% of our total capital expenditures of $373.5 million were directed to our operations in South Texas, and almost entirely in the Eagle Ford shale, as we continued executing our strategy to significantly increase our oil production and oil reserves. During the first quarter of 2013, we had two contracted drilling rigs operating full-time in South Texas and all of our operated drilling and completion activities were focused on the Eagle Ford shale. In late April 2013, we moved one of these contracted drilling rigs to Southeast New Mexico, while the second contracted drilling rig continued to operate in the Eagle Ford shale. In mid-August 2013, we added a third contracted drilling rig to our drilling program and returned to operating two contracted drilling rigs in the Eagle Ford shale play. We expect to operate two contracted drilling rigs in South Texas throughout 2014 . At March 13, 2014 , one of our two Eagle Ford rigs was operating in southern Wilson County, Texas, while the other was operating in La Salle County, Texas. The development of our Eagle Ford shale properties in South Texas will continue to be the primary driver of our growth in 2014 , and we intend to direct approximately $318.4 million , or 72%, of our estimated 2014 capital expenditure budget of $440.0 million to our operations in South Texas. 
+During the year ended December 31, 2013 , we completed and began producing oil and natural gas from 32 gross (27.6 net) Eagle Ford shale wells drilled on our acreage position in South Texas, including 25 gross (25.0 net) operated and seven gross (2.6 net) non-operated wells. As we completed and began producing oil and natural gas from these wells during 2013 , our Eagle Ford production increased significantly. For the year ended December 31, 2013 , 70% of our daily oil equivalent production, or 8,225 BOE per day, including 5,748 Bbl of oil per day and 14.9 MMcf of natural gas per day, was produced 
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+from the Eagle Ford shale. Almost all of our oil production in 2013 and 2012 was attributable to the Eagle Ford shale. The Eagle Ford shale contributed approximately 98% of our daily oil production and approximately 42% of our daily natural gas production during 2013 , as compared to approximately 98% of our daily oil production and approximately 12% of our daily natural gas production during 2012 . During the year ended December 31, 2012 , approximately 44% of our daily production, or 3,928 BOE per day, including 3,261 Bbl of oil per day and 4.0 MMcf of natural gas per day, was attributable to the Eagle Ford shale. During the year ended December 31, 2011, only about 8% of our daily production, or 548 BOE per day, including 331 Bbl of oil per day and 1.3 MMcf of natural gas per day, was attributable to the Eagle Ford shale. This growth in oil and natural gas production from the Eagle Ford shale over the past several years reflects our ongoing drilling and completion operations in South Texas. Natural gas produced from most of our Eagle Ford shale wells is a liquids-rich natural gas and our purchasers process this natural gas for us at their processing facilities to remove the natural gas liquids, such as ethane, propane and other heavier natural gas liquids components. Our Eagle Ford wells typically yield five to seven gallons of natural gas liquids per Mcf of natural gas produced at the wellhead depending on the specific property. 
+At December 31, 2013 , approximately 39% of our estimated total proved oil and natural gas reserves, or 20.2 million BOE, was attributable to the Eagle Ford shale, including approximately 15.2 million Bbl of oil and 30.1 Bcf of natural gas. Our proved reserves attributable to the Eagle Ford shale increased approximately 41% to 20.2 million BOE for the year ended December 31, 2013 , as compared to 14.4 million BOE for the year ended December 31, 2012 . Our Eagle Ford proved reserves at December 31, 2013 comprised approximately 93% of our proved oil reserves and 14% of our proved natural gas reserves, as compared to approximately 99% of our proved oil reserves and 30% of our proved natural gas reserves at December 31, 2012 . The PV-10 of our proved reserves in the Eagle Ford shale at December 31, 2013 was $540.4 million , or approximately 82% of the PV-10 of our total proved reserves of $655.2 million . PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure, see “— Estimated Proved Reserves.” 
+At December 31, 2013 , we have identified and engineered 273 gross ( 229.3 net) locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Eagle Ford wells and other nearby wells based on available public data, drilling densities anticipated on our properties and observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Of the 273 gross ( 229.3 net) engineered locations identified for potential future drilling in the Eagle Ford shale at December 31, 2013 , we consider 150 gross (125.9 net) locations to be Tier 1 locations. We define Tier 1 Eagle Ford locations as those locations that we anticipate to have estimated ultimate recoveries of 225,000 Bbl of oil or greater. Of these Tier 1 locations, 114 gross (111.5 net) locations would be operated by us. These identified locations presume that we will be able to develop our Eagle Ford properties on 40-acre to 80-acre spacing, depending on the specific property and the wells we have already drilled. As a result of the initial performance of test wells drilled on 40-acre and 50-acre spacing during 2013 , we anticipate that Eagle Ford shale wells on our acreage in central and northern La Salle County, northern Karnes County and southern Wilson County can be developed on 40-acre spacing, while our other properties may be more likely developed on 80-acre spacing. We are currently drilling on 40-acre spacing on most of our properties in central and northern La Salle County, northern Karnes County and southern Wilson County. On our properties in the eastern portion of our Eagle Ford acreage in DeWitt County, we continue to drill on 80-acre spacing with no plans to test less than 80-acre spacing at December 31, 2013 , because we believe that higher permeability, better transmissibility and higher pressure in these areas make these properties less conducive to reduced spacing. 
+We define Tier 2 Eagle Ford locations, including 123 gross (103.4 net) locations, as those locations that we anticipate to have estimated ultimate recoveries of between 150,000 Bbl and 225,000 Bbl of oil, locations that are primarily prospective for natural gas or locations with lesser estimates of ultimate oil recovery, but on properties already held by existing production. At December 31, 2013 , Tier 2 locations were identified primarily on our acreage in Zavala County, southern La Salle County and eastern Gonzales County. We have identified no potential future Eagle Ford drilling locations on our Atascosa County acreage. All of these Tier 2 locations would be operated by us, and almost all of these locations are on properties already held by production from the Eagle Ford or other producing horizons. Although we have no plans to drill any of these Tier 2 locations in 2014 , as long as these properties remain held by production, or remain in the primary terms of the leases, these locations remain available for us to drill at a later time should commodity prices improve, drilling and completion costs decline further or new technologies be developed that increase expected recoveries. Certain of these properties, such as our properties in Zavala and Atascosa Counties, also offer the opportunity to explore horizons other than the Eagle Ford, including the Austin Chalk, Buda, Edwards or Pearsall, and we may develop new prospects on these properties in the future. We have included one test of the Buda formation on our Zavala County acreage as part of our 2014 capital expenditure budget. As we explore and develop all of our Eagle Ford acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2013 , these 273 gross ( 229.3 net) potential future drilling locations included 52 gross (39.8 net) locations to which we have assigned proved undeveloped reserves. 
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+We believe that we have increased our technical knowledge of drilling, completing and producing Eagle Ford shale wells, particularly over the past two years. During this time, we have progressed from drilling wells on single-well pads to multi-well pad drilling, and most recently, to multi-well batch drilling. In August 2013, we began drilling certain wells on our western Eagle Ford acreage from batch drilled pads using a drilling rig equipped with a “walking” package and, as a result, we have improved both drilling times and costs. We realized cost savings of approximately $325,000 per well on initial wells drilled using this rig, and we expect the use of batch drilling and the “walking” rig will lead to total cost savings of approximately $400,000 per well or more going forward. Recent wells drilled on our western Eagle Ford acreage in La Salle County have drilling times from spud to total depth of eight to 10 days per well and costs at or just below $6 million per well. In April 2014, we expect to replace the drilling rig currently operating in the central portion of our acreage in Karnes and Wilson Counties with a new “walking” rig. At that time, we will have two “walking” rigs operating in the Eagle Ford and will conduct batch drilling operations on our properties using these rigs for the balance of 2014. Recent wells in our central Eagle Ford acreage have been drilled for between $7.0 and $7.5 million, but we expect to see further cost improvements with the initiation of batch drilling operations in this area as well. We anticipate that we will drill almost 250,000 lateral feet with two rigs in the Eagle Ford in 2014, as compared to 150,000 feet using two rigs in 2012 and effectively 1.5 rigs in 2013, an increased drilling efficiency of almost 70%. 
+During 2013, we continued to refine the design of our hydraulic fracture treatments to enhance well productivity and ultimate hydrocarbon recovery, increasing fluid volumes to 40 Bbl per foot and proppant volumes to more than 2,000 pounds per foot, while decreasing the spacing between perforation clusters where the fractures are initiated. These Generation 5, and now Generation 6, fracture treatments are resulting in significant improvements in initial well productivity as compared to earlier generation treatment designs. We also believe that initiating the use of gas lift relatively early in the life of our newly drilled Eagle Ford wells has accelerated oil production, reduced lease operating expenses, lowered maintenance costs and helped our wells recover faster after being shut in for offset well operations. 
+As we continue to explore and develop our leasehold positions in the Eagle Ford shale, we may face challenges with establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and in particular hydraulic fracturing, services for our newly drilled wells during 2013 or 2012, although we experienced these problems at various times during 2011 in South Texas and may have such difficulties again in the future. We believe that maintaining reliable and timely drilling and completion services and optimizing drilling and completion costs will be essential to the successful development and profitability of the Eagle Ford shale play. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+In the past, we have experienced pipeline and natural gas processing interruptions and capacity and infrastructure constraints associated with natural gas production, which have, among other things, required us to flare natural gas occasionally. To alleviate a portion of the interruptions and processing capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. No assurance can be made that this agreement will alleviate these issues completely, and if we were required to shut in or flare our production for long periods of time due to pipeline interruptions or lack of processing facilities or capacity of these facilities, it would have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+We believe portions of our Eagle Ford acreage may also be prospective for the Austin Chalk, Buda, Edwards and Pearsall formations, from which we would expect to produce predominantly oil and liquids. In particular, the Austin Chalk formation, which is a naturally fractured carbonate typically ranging in thickness from 200 to 400 feet, and the Buda formation, which is a naturally fractured carbonate typically ranging in thickness from 90 to 160 feet, have produced from several fields on or nearby portions of our acreage. We believe that approximately 21,000 gross (16,800 net) acres of our properties in South Texas are prospective for the Austin Chalk and 17,200 gross (13,300 net) acres are prospective for the Buda formation, which have historically been targeted by operators in South Texas. 
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+In particular, we own approximately 8,900 gross (8,900 net) contiguous acres on our Glasscock Ranch property in southeast Zavala County, Texas which are held by production and which we believe are prospective for the Buda formation. We believe our acreage is located within the extension of a trend where encouraging drilling by other operators has occurred in the Buda just southwest of our leasehold position. We have acquired a 3-D seismic survey over our acreage, and at March 13, 2014 , we were evaluating a series of seismic attributes which are similar to fracture patterns observed in cores from other wells in the area and from our drilling of previous wells on the acreage in 2012 and which are consistent with regional mapping. At December 31, 2013 , we had not included any Buda locations in our future drilling locations, although we do plan to drill one gross (1.0 net) exploratory well to test the Buda formation on our Glasscock Ranch property in 2014. We participated in one non-operated test of the Buda formation in South Texas (approximately 21% working interest) on one of our leases in Atascosa County during the first quarter of 2013. This well tested a strong initial oil flow from a very short horizontal lateral, but the well was plugged and abandoned after oil production from this interval declined to uneconomic levels soon thereafter. We do not expect to participate in any additional Buda tests on our Atascosa County acreage during 2014 . 
+Southeast New Mexico and West Texas — Permian Basin 
+The Permian Basin in Southeast New Mexico and West Texas is a mature exploration and production province with extensive developments in a wide variety of petroleum systems resulting in stacked target horizons in many areas. Historically, the majority of development in this basin has focused on relatively conventional reservoir targets, but the combination of advanced formation evaluation, 3-D seismic technology, horizontal drilling and hydraulic fracturing technology is enhancing the development potential of this basin, particularly in the organic rich shales, or source rocks, of the Wolfcamp and low permeability sand and carbonate reservoirs of the Bone Spring, Avalon and Delaware formations. We believe these formations, which have been typically considered to be low quality rocks because of their low permeability, are strong candidates for horizontal drilling and intense hydraulic fracturing techniques. 
+One example of such an opportunity appears to be the so-called “Wolf-Bone” play in the western Permian Basin. Together, the Lower Permian age Bone Spring (also called Leonardian) and Wolfcamp shale formations span several thousand feet of stacked shales, sandstones, limestones and dolomites, representing complex and dynamic submarine depositional systems that include several organic rich source rocks. Throughout these intervals, oil and natural gas have been produced primarily from conventional sandstone and carbonate reservoirs even though hydrocarbons are trapped in the tight sands, limestones and dolomites interbedded within organic rich shale. Recently, these hydrocarbon-bearing zones have been recognized and tested by a number of operators as targets for horizontal drilling and multi-stage hydraulic fracturing techniques. As a result, many industry players are expanding positions and conducting drilling programs throughout the western Permian Basin in Lea and Eddy Counties in Southeast New Mexico and Loving, Pecos, Reeves, Ward and Winkler Counties in West Texas. In addition, other industry players have been successful in developing similar formations on the eastern side of the Permian Basin, east of the Central Basin Platform in West Texas. Multiple horizontal drilling and completion targets are being identified and tested by companies throughout the vertical section including the Delaware, Avalon, Bone Spring (First, Second and Third sands) and multiple intervals within the Wolfcamp shale, often identified as the Wolfcamp “A” through “D” intervals. 
+During 2013, we added significantly to our acreage position and initiated an exploration program to begin testing our Permian Basin leasehold. We acquired an additional 55,400 gross (38,900 net) acres in Southeast New Mexico and West Texas. At December 31, 2013 , our leasehold position included approximately 70,800 gross (44,800 net) acres in the Permian Basin, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas in the western Permian Basin. At December 31, 2013 , approximately 7,000 gross (4,900 net) of these acres were held by production. We consider the vast majority of this acreage to be prospective for oil and liquids-rich targets in the Bone Spring and Wolfcamp formations. Other potential targets on certain portions of our acreage include the Avalon shale and Delaware formations, as well as the Abo, Strawn, Devonian, Cisco/Canyon and Glorieta/San Andres formations. We have also acquired approximately 2,000 gross (1,450 net) acres in Howard and Dawson Counties, Texas in the eastern Permian Basin, although we do not expect to drill any wells in the eastern Permian Basin in 2014. In addition, a portion of our leasehold interests in the Permian Basin, including approximately 7,300 gross (450 net) acres in Winkler County, Texas, is no longer considered to be prospective by us, and we plan to allow this acreage to expire without drilling. 
+At December 31, 2013 and March 13, 2014, we were running one contracted drilling rig in the Permian Basin to further evaluate and delineate our acreage position both geographically and geologically. During 2013, we drilled three wells in the Permian Basin - two in Lea County, New Mexico and one in Loving County, Texas. Our first well, the Ranger 12 State #1 well in Lea County, was a vertical data collection well where we took extensive well log and whole and sidewall core data in an effort to better understand the multiple potential completion targets throughout the vertical section. We were continuing to test multiple potential completion intervals in this well at December 31, 2013 . Our second well, the Ranger 33 State Com #1H in Lea County, was a 4,300-ft horizontal lateral drilled and completed in the Second Bone Spring sand with 18 fracturing stages, including 165,000 Bbl of fluid and 7.5 million pounds of sand. This well was placed on production at the end of October 2013 
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+and has continued to exhibit strong performance. In its first three months on production, including the initial cleanup phase, the well produced over 48,000 BOE, including approximately 44,000 Bbl of oil (92% oil), and continued to flow with gas lift assist. Our third well, the Dorothy White #1H in Loving County, Texas, was a 5,000-ft horizontal lateral drilled in the upper portion of the Wolfcamp formation, the Wolfcamp “A”, at approximately 10,700-ft vertical depth. We completed this well in January 2014 with 20 fracturing stages, including 200,000 Bbl of fluid and 9.8 million pounds of sand. The Dorothy White #1H was placed on production in January 2014 and flowed 1,355 BOE per day, including 902 Bbl of oil per day and 2.7 MMcf of natural gas per day (67% oil) at 3,711 pounds per square inch pressure (“psi”) on a 22/64 th inch choke during a 24-hour initial potential test. 
+Because of these encouraging initial results, we plan to run one rig continuously in the western Permian Basin throughout 2014. We have allocated approximately $108.6 million , or about 25% of our 2014 capital expenditure budget of $440.0 million , to our drilling and completion activities in the Permian Basin, as well as for the acquisition of additional leasehold interests in the area. The objective of our 2014 Permian Basin drilling program is to further evaluate and delineate our acreage position in an effort to define an expanded, multi-rig drilling program for 2015 and beyond. 
+At December 31, 2013 , we had identified and engineered 241 gross ( 177.7 net) locations for potential future drilling on our Permian Basin acreage, primarily in the Wolfcamp or Bone Spring plays, but also including some Avalon shale locations. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our Permian Basin wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among other criteria. Because we have just begun the exploration of our properties in the Permian Basin in 2013, our engineered well locations at December 31, 2013 do not yet include all portions of our acreage position. Our identified well locations presume that these properties may be developed on 160-acre well spacing, although we believe that denser well spacing may be possible and that multiple intervals may be prospective at any one surface location. In addition, although our potential future drilling locations presume the drilling of horizontal wells, we also believe that certain portions of our acreage could lend themselves to development with vertical wells. As a result, as we explore and develop our Permian Basin acreage further, we anticipate that we may identify additional locations for future drilling. In addition, although we believe that prospective well locations exist on our acreage for the Delaware formation or other potential completion intervals, we had not included any locations for these intervals in our engineered well locations at December 31, 2013 . At December 31, 2013 , these potential future drilling locations included only four gross (3.4 net) locations in the Permian Basin to which we have assigned proved undeveloped reserves. 
+As we continue to explore and develop our leasehold positions in the Permian Basin, we may face challenges with establishing operations in new areas and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to process, transport and market the oil and natural gas we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure on our leases throughout the area. We believe that we have successfully secured the necessary drilling and completion services for our current Permian Basin operations, but industry activity in Southeast New Mexico and West Texas is increasing rapidly, and we may encounter difficulties in securing these services as we move forward with our exploration and development operations in this area in future periods. We believe that maintaining reliable and timely drilling and completion services, reducing drilling and completion costs and securing the necessary pipeline and natural gas processing capabilities will be essential to the successful development and profitability of the Wolfcamp, Bone Spring and other plays in the Permian Basin. See “Risk Factors — The Unavailability or High Cost of Drilling Rigs, Completion Equipment and Services, Supplies and Personnel, Including Hydraulic Fracturing Equipment and Personnel, Could Adversely Affect Our Ability to Establish and Execute Exploration and Development Plans within Budget and on a Timely Basis, Which Could Have a Material Adverse Effect on Our Financial Condition, Results of Operations and Cash Flows.” 
+Northwest Louisiana and East Texas 
+We did not conduct any operated drilling and completion activities on our leasehold properties in Northwest Louisiana and East Texas during 2013 , although we did participate in the drilling and completion of 11 gross (0.4 net) non-operated Haynesville shale wells. We do not plan to drill any operated Haynesville shale wells in 2014 , but we have budgeted capital expenditures of approximately $12.0 million for our participation in 26 gross (1.5 net) wells that we anticipate may be drilled by other operators on certain of our non-operated properties in 2014 , as well as for additional leasehold acquisition opportunities in the Haynesville shale play. Certain of these wells were already in progress at December 31, 2013 . During the year ended December 31, 2013 , we acquired approximately 1,190 gross (1,190 net) acres in Northwest Louisiana that we consider to be prospective primarily for natural gas production from the core area of the Haynesville shale. This acreage acquisition provides us additional operational flexibility if we resume operated activities in the Haynesville shale play in the future. At December 31, 2013 , we held approximately 28,600 gross (25,800 net) acres in Northwest Louisiana and East Texas, 
+11 
+Table of Contents 
+including 22,700 gross ( 15,000 net) acres in the Haynesville shale play. We operate all of our Cotton Valley and shallower production on our leasehold interests in Northwest Louisiana and East Texas, as well as all of our Haynesville production on the acreage outside of what we believe to be the core area of the Haynesville shale play. We operate approximately 36% of the 13,800 gross (6,900 net) acres that we consider to be in the core area of the Haynesville play. 
+For the year ended December 31, 2013 , approximately 29% of our average daily oil equivalent production, or 3,431 BOE per day, including 17 Bbl of oil per day and 20.5 MMcf of natural gas per day, was attributable to our leasehold interests in Northwest Louisiana and East Texas. Natural gas production from these properties comprised approximately 58% of our daily natural gas production, but oil production from these properties comprised only about 0.3% of our daily oil production during 2013 , as compared to approximately 88% of our daily natural gas production and approximately 1% of our daily oil production during 2012 . During the year ended December 31, 2012 , approximately 56% of our average daily oil equivalent production, or 5,042 BOE per day, including 31 Bbl of oil per day and 30.1 MMcf of natural gas per day, was attributable to our properties in Northwest Louisiana and East Texas. The decline in oil and particularly natural gas production from these properties over the past year reflects (i) the natural decline in production from these properties, (ii) our decision not to drill any operated Haynesville shale or Cotton Valley wells during 2013 and (iii) the lack of drilling on these properties by our co-working interest owners in 2013 . 
+For the year ended December 31, 2013 , approximately 48% of our daily natural gas production, or 17.0 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 10% , or 3.5 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. For the year ended December 31, 2012 , approximately 76% of our daily natural gas production, or 26.0 MMcf of natural gas per day, was produced from the Haynesville shale, with approximately 12% , or 4.1 MMcf of natural gas per day, produced from the Cotton Valley and other shallower formations on these properties. 
+At December 31, 2013 , approximately 56% of our estimated total proved reserves, or 28.8 million BOE, was attributable to the Haynesville shale with another 3% of our proved reserves, or 1.3 million BOE, attributable to the Cotton Valley and shallower formations underlying this acreage. The unweighted arithmetic average of the first-day-of-the-month natural gas price used to estimate proved natural gas reserves for 2013 increased to $3.670 per MMBtu, as compared to $2.757 per MMBtu for 2012 . Primarily as a result of the continued improvement in natural gas prices over the past year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013 . We had removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our estimated total proved reserves at June 30, 2012 because the natural gas price used to estimate natural gas reserves at June 30, 2012 had declined to $3.146 per MMBtu, a price at which the natural gas volumes associated with almost all of our identified Haynesville shale well locations could no longer be classified as proved undeveloped reserves. 
+At December 31, 2013 , we had identified and engineered 527 gross ( 114.5 net) locations for potential future drilling in the Haynesville shale play and 71 gross ( 49.3 net) locations for potential future drilling in the Cotton Valley formation. These engineered locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated rates of return, estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed on properties of other operators, including on some of our non-operated properties, estimated horizontal lateral lengths, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among other criteria. Of the 527 gross ( 114.5 net) locations identified for future drilling on our Haynesville acreage, 452 gross (63.6 net) locations have been identified within the 13,800 gross (6,900 net) acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Northwest Louisiana and East Texas acreage further, we believe it is possible that we may identify additional locations for future drilling. At December 31, 2013 , these potential future drilling locations included 125 gross (20.6 net) locations in the Haynesville shale (and no locations in the Cotton Valley) to which we have assigned proved undeveloped reserves. 
+About one-third of our acreage in the core area of the Haynesville shale play in Northwest Louisiana is operated by a subsidiary of Chesapeake Energy Corporation. During the fourth quarter of 2013, we notified Chesapeake that we would be electing to take in kind the anticipated natural gas production from most of the wells operated by Chesapeake effective January 1, 2014. In addition, in December 2013, we entered into a five-year natural gas gathering agreement effective January 1, 2014 for this natural gas production. This agreement has no firm transportation commitments and no natural gas volume commitments. We believe that taking this natural gas production in kind and transporting through this gathering agreement will improve price realizations and reduce marketing and transportation fees and other costs associated with this natural gas production by an average of approximately $0.70 or more per MMBtu beginning January 1, 2014. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities 
+12 
+Table of Contents 
+Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+The NYMEX Henry Hub natural gas futures contract price for the earliest delivery date was $4.38 per MMBtu at March 13, 2014 . Although we do not have plans to drill any Haynesville or Cotton Valley wells on our operated properties at December 31, 2013 , as a result of the recent improvement in natural gas prices, we anticipate that certain of our co-working interest owners may elect to drill additional Haynesville wells in 2014 on properties where they are the operator. As noted above, our 2014 capital expenditure budget includes our participation in 26 gross (1.5 net) non-operated Haynesville wells in 2014, several of which were already in progress at December 31, 2013 . Should natural gas prices remain above $4.00 per MMBtu during a significant portion of 2014, however, we believe that we may receive proposals to participate in additional non-operated wells during 2014. Should we elect to participate in these non-operated Haynesville wells, our 2014 capital expenditure budget would most likely be increased accordingly. See “Risk Factors — Our Identified Drilling Locations Are Scheduled over Several Years, Making Them Susceptible to Uncertainties That Could Materially Alter the Occurrence or Timing of Their Drilling” and “Risk Factors — We Have Limited Control over Activities on Properties We Do Not Operate.” 
+Haynesville and Middle Bossier Shales 
+The Haynesville shale is an organically rich, overpressured marine shale found below the Cotton Valley and Bossier formations and above the Smackover formation at depths ranging from 10,500 to 13,500 feet across a broad region throughout Northwest Louisiana and East Texas, including principally Bossier, Caddo, DeSoto and Red River Parishes in Louisiana and Harrison, Rusk, Panola and Shelby Counties in Texas. The Haynesville shale produces primarily dry natural gas with almost no associated liquids. The Bossier shale is overpressured and is often divided into lower, middle and upper units. The Middle Bossier shale appears to be productive for natural gas under large portions of DeSoto, Red River and Sabine Parishes in Louisiana and Shelby and Nacogdoches Counties in Texas, where it shares many similar productive characteristics with the deeper Haynesville shale. Although there is some overlap between the Haynesville and Bossier shale plays, the two plays appear quite distinct and a separate horizontal wellbore is typically needed for each formation. 
+At December 31, 2013 , we had approximately 22,700 gross ( 15,000 net) acres in the Haynesville shale play, primarily in Northwest Louisiana. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data, information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, approximately 13,800 gross (6,900 net) acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Almost all of our Haynesville acreage is held by production or consists of fee mineral interests that we own and portions of it are also producing from and, we believe, prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe that approximately 1,700 net acres are prospective for the Middle Bossier shale play. We have not yet drilled a Middle Bossier shale well, and, although we believe that prospective well locations may exist on this acreage, we have not included any Middle Bossier locations in our engineered drilling locations at December 31, 2013 . 
+Within the acreage that we believe to be in the core area of the Haynesville shale play, we are the operator of approximately 2,500 net acres. We have identified 32 gross (24.4 net) potential additional Haynesville locations that we may drill and operate in the future on this acreage. The remainder of our acreage in the core area of the Haynesville shale play is operated by other companies, including approximately one-third of our non-operated Haynesville acreage in this area of the play that is operated by a subsidiary of Chesapeake following a sale of a portion of our interest in July 2008. The working interests in our non-operated Haynesville wells are typically small, ranging from less than 1% to more than 30%. 
+Cotton Valley, Hosston (Travis Peak) and Other Shallower Formations 
+Prior to initiating natural gas production from the Haynesville shale in 2009, almost all of our production and reserves in Northwest Louisiana and East Texas was attributable to wells producing from the Cotton Valley formation. We own almost all of the shallow rights from the base of the Cotton Valley formation to the surface under our acreage in Northwest Louisiana and East Texas. 
+All of the shallow rights underlying our acreage in our Elm Grove/Caspiana properties in Northwest Louisiana, approximately 10,000 gross (9,800 net acres) at December 31, 2013 , are held by existing production from the Cotton Valley formation or the Haynesville shale. The Cotton Valley formation was the primary producing zone in the Elm Grove field prior to discovery of the Haynesville shale. The Cotton Valley formation is a low permeability natural gas sand that ranges in thickness from 200 to 300 feet and has porosity ranging from 6% to 10%. 
+13 
+Table of Contents 
+We have identified 71 gross ( 49.3 net) additional drilling locations for future Cotton Valley horizontal wells on our Elm Grove/Caspiana properties. We did not drill any of these locations in 2013 and do not plan to drill any of these locations in 2014 . As long as this leasehold acreage is held by existing production from the vertical Cotton Valley wells or the deeper Haynesville shale wells, however, these Cotton Valley natural gas volumes remain available to be developed by us should natural gas prices improve further, drilling and completion costs decline or new technologies be developed that increase expected recoveries. 
+We also continue to hold the shallow rights primarily by existing production on our Central and Southwest Pine Island, Longwood, Woodlawn and other prospect areas in Northwest Louisiana and East Texas. At December 31, 2013 , we held an estimated 13,800 gross (11,400 net) leasehold and mineral acres by existing production in these areas. 
+Southwest Wyoming, Northeast Utah and Southeast Idaho — Meade Peak Shale 
+At December 31, 2013 , we held leasehold interests in approximately 76,500 gross ( 36,000 net) acres in Southwest Wyoming and adjacent areas in Utah and Idaho as part of a natural gas shale exploration prospect targeting the Meade Peak shale. These leasehold interests are a combination of federal, state and fee mineral interests. We have entered into a participation and joint operating agreement with other parties covering the initial exploration effort, and if successful, the future development of this acreage. We are the operator of this prospect. We had no production, no proved reserves and no engineered drilling locations attributable to this acreage at December 31, 2013 . 
+We began drilling the initial test well on this prospect, the Crawford Federal #1 well in Lincoln County, Wyoming, in February 2011. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations in September 2011 and completed drilling, well logging and coring operations in November 2011. During 2012, we conducted detailed evaluations of the well logs and conducted special core analysis to better understand the petrophysical characteristics of the Meade Peak shale. 
+In September 2012, we entered into an agreement with the principal non-operated working interest owner related to the ongoing exploration of the Meade Peak shale, pursuant to which the working interest owner (i) paid us a prospect fee of $1.0 million, (ii) agreed to provide up to a total cost of $3.0 million (carrying our 50% share) for extensions of expiring leases and new leasing in the prospect in which we will have a 50% working interest at no cost to us and (iii) agreed to carry our 50% share of the drilling and completion costs associated with the horizontal lateral up to a total cost for these operations of $5.0 million, with each party paying 50% of all drilling and completion costs in excess of $5.0 million. In return for this consideration, in December 2012, we assigned 50% of our gross and net leasehold interests in the prospect to this working interest owner. 
+In November 2012, we re-entered the Crawford Federal #1 vertical well and drilled a horizontal lateral from that wellbore into the Meade Peak shale approximately 2,500 feet in length. We completed the lateral with a five-stage fracture treatment in September 2013 and initiated flow back to recover the hydraulic fracture load fluid. Due to weather constraints, we have temporarily suspended our testing program for this well and plan to resume operations in 2014. We plan to evaluate this well with the other working interest owners before making further decisions concerning the future exploration of the Meade Peak shale in this prospect. 
+14 
+Table of Contents 
+Operating Summary 
+The following table sets forth certain unaudited production data for the years ended December 31, 2013, 2012 and 2011 : 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Unaudited Production Data: 
+Net Production Volumes: 
+Oil (MBbl) 
+2,133 
+1,214 
+154 
+Natural gas (Bcf) 
+12.9 
+12.5 
+14.5 
+Total oil equivalent (MBOE) (1) 
+4,285 
+3,294 
+2,573 
+Average daily production (BOE/d) (1) 
+11,740 
+9,000 
+7,049 
+Average Sales Prices: 
+Oil, with realized derivatives (per Bbl) 
+$ 
+98.67 
+$ 
+103.55 
+$ 
+93.80 
+Oil, without realized derivatives (per Bbl) 
+$ 
+99.79 
+$ 
+101.86 
+$ 
+93.80 
+Natural gas, with realized derivatives (per Mcf) 
+$ 
+4.47 
+$ 
+3.55 
+$ 
+4.11 
+Natural gas, without realized derivatives (per Mcf) 
+$ 
+4.35 
+$ 
+2.59 
+$ 
+3.62 
+Operating Expenses (per BOE): 
+Production taxes and marketing 
+$ 
+4.89 
+$ 
+3.54 
+$ 
+2.44 
+Lease operating 
+$ 
+9.04 
+$ 
+8.56 
+$ 
+2.82 
+Depletion, depreciation and amortization 
+$ 
+22.96 
+$ 
+24.43 
+$ 
+12.34 
+General and administrative 
+$ 
+4.85 
+$ 
+4.42 
+$ 
+5.21 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2013 from our primary operating areas: 
+Average Net Daily Production 
+Oil (Bbl/d) 
+Natural Gas (Mcf/d) 
+Oil Equivalent (BOE/d) (1) 
+Total Net Production (MBOE) (1) 
+Percentage of Total Net Production 
+South Texas: 
+Eagle Ford (2) 
+5,748 
+14,865 
+8,225 
+3,002 
+70.1 
+% 
+NW Louisiana/E Texas: 
+Haynesville 
+— 
+16,984 
+2,831 
+1,033 
+24.1 
+% 
+Cotton Valley (3) 
+17 
+3,498 
+600 
+219 
+5.1 
+% 
+Area Total 
+17 
+20,482 
+3,431 
+1,252 
+29.2 
+% 
+Permian Basin: 
+SE New Mexico, West Texas 
+78 
+36 
+84 
+31 
+0.7 
+% 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+Total 
+5,843 
+35,383 
+11,740 
+4,285 
+100.0 
+% 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+15 
+Table of Contents 
+The following table sets forth information regarding our average net daily production and total production for the year ended December 31, 2012 from our primary operating areas: 
+Average Net Daily Production 
+Oil (Bbl/d) 
+Natural Gas (Mcf/d) 
+Oil Equivalent (BOE/d) (1) 
+Total Net Production (MBOE) (1) 
+Percentage of Total Net Production 
+South Texas: 
+Eagle Ford (2) 
+3,261 
+4,007 
+3,928 
+1,438 
+43.7 
+% 
+NW Louisiana/E Texas: 
+Haynesville 
+1 
+26,007 
+4,336 
+1,587 
+48.2 
+% 
+Cotton Valley (3) 
+30 
+4,051 
+706 
+258 
+7.8 
+% 
+Area Total 
+31 
+30,058 
+5,042 
+1,845 
+56.0 
+% 
+Permian Basin: 
+SE New Mexico, West Texas 
+25 
+30 
+30 
+11 
+0.3 
+% 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+Total 
+3,317 
+34,095 
+9,000 
+3,294 
+100.0 
+% 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(2) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(3) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+Our total production of approximately 4.3 million BOE for the year ended December 31, 2013 was an increase of 30% from our total production of approximately 3.3 million BOE for the year ended December 31, 2012 . This increased production was primarily due to our drilling operations in the Eagle Ford shale. Our average daily production for the year ended December 31, 2013 was 11,740 BOE per day, as compared to 9,000 BOE per day for the year ended December 31, 2012 . Our average daily oil production for the year ended December 31, 2013 was 5,843 Bbl of oil per day, an increase of 76% from 3,317 Bbl of oil per day for the year ended December 31, 2012 . 
+Producing Wells 
+The following table sets forth information relating to producing wells at December 31, 2013 . Wells are classified as oil wells or natural gas wells according to their predominant production stream. We do not have any currently active dual completions. In the table below, gross wells are the total number of producing wells in which we own a working interest and net wells represent the total of our fractional working interests owned in the gross wells. 
+Oil Wells 
+Natural Gas Wells 
+Total Wells 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford (1) 
+69 
+59.3 
+4 
+4.0 
+73 
+63.3 
+NW Louisiana/E Texas: 
+Haynesville 
+— 
+— 
+140 
+13.0 
+140 
+13.0 
+Cotton Valley (2) 
+2 
+2.0 
+98 
+61.7 
+100 
+63.7 
+Area Total 
+2 
+2.0 
+238 
+74.7 
+240 
+76.7 
+Permian Basin: 
+SE New Mexico, West Texas 
+12 
+4.4 
+1 
+0.6 
+13 
+5.0 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+— 
+Total 
+83 
+65.7 
+243 
+79.3 
+326 
+145.0 
+__________________ 
+(1) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(2) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+Estimated Proved Reserves 
+16 
+Table of Contents 
+The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2013, 2012 and 2011 . Our production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where we produce liquids-rich natural gas, such as in the Eagle Ford shale, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. The reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC’s rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 
+At December 31, (1) 
+2013 
+2012 
+2011 
+Estimated Proved Reserves Data: (2) 
+Estimated proved reserves: 
+Oil (MBbl) 
+16,362 
+10,485 
+3,794 
+Natural Gas (Bcf) (3) 
+212.2 
+80.0 
+170.4 
+Total (MBOE) (4) 
+51,729 
+23,819 
+32,196 
+Estimated proved developed reserves: 
+Oil (MBbl) 
+8,258 
+4,764 
+1,419 
+Natural Gas (Bcf) (3) 
+53.5 
+54.0 
+56.5 
+Total (MBOE) (4) 
+17,168 
+13,771 
+10,843 
+Percent developed 
+33.2 
+% 
+57.8 
+% 
+33.7 
+% 
+Estimated proved undeveloped reserves: 
+Oil (MBbl) 
+8,104 
+5,721 
+2,375 
+Natural gas (Bcf) (3) 
+158.7 
+26.0 
+113.9 
+Total (MBOE) (4) 
+34,561 
+10,048 
+21,353 
+PV-10 (5) (in millions) 
+$ 
+655.2 
+$ 
+423.2 
+$ 
+248.7 
+Standardized Measure (6) (in millions) 
+$ 
+578.7 
+$ 
+394.6 
+$ 
+215.5 
+__________________ 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the 12 months ended December 31, 2013 were $93.42 per Bbl for oil and $3.670 per MMBtu for natural gas, for the 12 months ended December 31, 2012 were $91.21 per Bbl for oil and $2.757 per MMBtu for natural gas, and for the 12 months ended December 31, 2011 were $92.71 per Bbl for oil and $4.118 per MMBtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead. We report our proved reserves in two streams, oil and natural gas, and the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. 
+(3) 
+As a result of substantially lower natural gas prices in 2012, at June 30, 2012, we removed 97.8 Bcf (16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves, most of which were attributable to non-operated properties. Primarily as a result of the continued improvement in natural gas prices during 2013, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013. 
+(4) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(5) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 2013, 2012 and 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2013, 2012 and 2011 were, in millions, $76.5 , $28.6 and $33.2 , respectively. 
+(6) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+17 
+Table of Contents 
+Our estimated total proved oil and natural gas reserves increased 117% from 23.8 million BOE at December 31, 2012 to 51.7 million BOE at December 31, 2013 . Our proved oil reserves grew 56% from approximately 10.5 million Bbl at December 31, 2012 to approximately 16.4 million Bbl at December 31, 2013 . This increase is primarily attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale in South Texas. Our proved natural gas reserves increased 165% from 80.0 Bcf at December 31, 2012 to 212.2 Bcf at December 31, 2013 . This increase in our proved natural gas reserves was attributable to our drilling and completion activities in 2013 and to the increase in our proved undeveloped natural gas reserves in 2013 from 26.0 Bcf at December 31, 2012 to 158.7 Bcf at December 31, 2013 due primarily to higher natural gas prices. As a result of substantially lower natural gas prices in 2012, we removed 97.8 Bcf ( 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale from our total proved reserves at June 30, 2012, most of which were attributable to non-operated properties. These proved undeveloped natural gas reserves were likewise not included in our estimated total proved reserves at December 31, 2012 . During 2013, primarily as a result of continued improvement in natural gas prices during the year, we added approximately 134.2 Bcf ( 22.4 million BOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which are reflected in our estimated total proved reserves at December 31, 2013 . The PV-10 of our total proved oil and natural gas reserves increased by 55% from $423.2 million at December 31, 2012 to $655.2 million at December 31, 2013 . Our total proved reserves at December 31, 2013 were made up of approximately 32% oil and 68% natural gas, as compared to 44% oil and 56% natural gas at December 31, 2012 . 
+Our proved developed oil and natural gas reserves increased from 13.8 million BOE at December 31, 2012 to 17.2 million BOE at December 31, 2013 due primarily to additions resulting from our drilling operations in the Eagle Ford shale. Our proved developed oil reserves increased from 4.8 million Bbl at December 31, 2012 to 8.3 million Bbl at December 31, 2013 as a result of our drilling operations in the Eagle Ford shale. Our proved developed natural gas reserves decreased slightly from 54.0 Bcf at December 31, 2012 to 53.5 Bcf at December 31, 2013 due primarily to declining natural gas production in the Haynesville shale and Cotton Valley coupled with the fact that we did not drill any operated Haynesville shale or Cotton Valley wells on our operated properties during 2013 and likewise, our co-working interest owners drilled very few Haynesville shale wells on the properties they operate. 
+The following table summarizes changes in our estimated proved developed reserves at December 31, 2013 . 
+Proved Developed Reserves 
+(MBOE) (1) 
+As of December 31, 2012 
+13,771 
+Extensions and discoveries 
+3,971 
+Purchases of minerals-in-place 
+28 
+Revisions of prior estimates 
+(651 
+) 
+Production 
+(4,285 
+) 
+Conversion of proved undeveloped to proved developed 
+4,334 
+As of December 31, 2013 
+17,168 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+Our proved undeveloped oil and natural gas reserves increased from 10.0 million BOE at December 31, 2012 to 34.6 million BOE at December 31, 2013 . Our proved undeveloped oil reserves increased from 5.7 million Bbl at December 31, 2012 to 8.1 million Bbl at December 31, 2013 , primarily as a result of our drilling operations in the Eagle Ford shale. Our proved undeveloped natural gas reserves increased from 26.0 Bcf at December 31, 2012 to 158.7 Bcf at December 31, 2013 due primarily to the previously discussed addition of approximately 134.2 Bcf ( 22.4 MBOE) of proved undeveloped natural gas reserves in the Haynesville shale to our estimated total proved reserves in the second, third and fourth quarters of 2013, which is reflected in our estimated total proved reserves at December 31, 2013 . 
+At December 31, 2013 , we had no proved reserves in our estimates that remained undeveloped for five years or more following their booking. 
+18 
+Table of Contents 
+The following table summarizes changes in our estimated proved undeveloped reserves at December 31, 2013 . 
+Proved Undeveloped Reserves 
+(MBOE) (1) 
+As of December 31, 2012 
+10,048 
+Extensions and discoveries 
+15,260 
+Purchases of minerals-in-place 
+— 
+Revisions of prior estimates 
+13,587 
+Conversion of proved undeveloped to proved developed 
+(4,334 
+) 
+As of December 31, 2013 
+34,561 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth, since 2011, proved undeveloped reserves converted to proved developed reserves during each year and the investments associated with these conversions (dollars in thousands). 
+Investment in Conversion of Proved Undeveloped Reserves to Proved Developed Reserves 
+Proved Undeveloped Reserves Converted to Proved Developed Reserves 
+Oil 
+Natural Gas 
+Total 
+(MBbl) 
+(Bcf) 
+(MBOE) (1) 
+2011 
+— 
+3.4 
+573 
+$ 
+1,409 
+2012 
+283 
+0.8 
+415 
+8,096 
+2013 
+2,944 
+8.3 
+4,334 
+115,699 
+Total 
+3,227 
+12.5 
+5,322 
+$ 
+125,204 
+__________________ 
+(1) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+The following table sets forth additional summary information by operating area with respect to our estimated net proved reserves at December 31, 2013 : 
+Net Proved Reserves (1) 
+Oil 
+Natural Gas 
+Oil Equivalent 
+PV-10 (2) 
+Standardized Measure (3) 
+(MBbl) 
+(Bcf) 
+(MBOE) (4) 
+(in millions) 
+(in millions) 
+South Texas: 
+Eagle Ford (5) 
+15,198 
+30.1 
+20,221 
+$ 
+540.4 
+$ 
+477.3 
+NW Louisiana/E Texas: 
+Haynesville 
+— 
+172.8 
+28,797 
+74.7 
+66.0 
+Cotton Valley (6) 
+36 
+7.8 
+1,339 
+8.2 
+7.2 
+Area Total 
+36 
+180.6 
+30,136 
+82.9 
+73.2 
+Permian Basin: 
+SE New Mexico, West Texas 
+1,128 
+1.5 
+1,372 
+31.9 
+28.2 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+— 
+Total 
+16,362 
+212.2 
+51,729 
+$ 
+655.2 
+$ 
+578.7 
+__________________ 
+(1) 
+Numbers in table may not total due to rounding. 
+(2) 
+PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. Our PV-10 at December 31, 
+19 
+Table of Contents 
+2013 may be reconciled to our Standardized Measure of discounted future net cash flows at such date by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2013 were approximately $ 76.5 million . 
+(3) 
+Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties. 
+(4) 
+Estimated using a conversion ratio of one Bbl of oil per six Mcf of natural gas. 
+(5) 
+Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. 
+(6) 
+Includes the Cotton Valley formation and shallower zones and also includes one well producing from the Frio formation in Orange County, Texas. 
+Technology Used to Establish Reserves 
+Under current SEC rules, proved reserves are those quantities of oil and natural gas, 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 economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven 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 have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. 
+In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available pressure and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserves estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. 
+Internal Control Over Reserves Estimation Process 
+We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our Vice President – Reservoir Engineering is primarily responsible for overseeing the preparation of our reserves estimates. He received his Bachelor and Master of Science degrees in Petroleum Engineering from Texas A&M University, is a Licensed Professional Engineer in the State of Texas and has over 36 years of industry experience. Following the preparation of our reserves estimates, these estimates are audited for their reasonableness by Netherland, Sewell & Associates, Inc. , independent reservoir engineers. The Engineering Committee of our Board of Directors reviews the reserves report and our reserves estimation process, and the results of the reserves report and the independent audit of our reserves are reviewed by other members of our Board of Directors, including members of our Audit Committee. 
+20 
+Table of Contents 
+Acreage Summary 
+The following table sets forth the approximate acreage in which we held a leasehold, mineral or other interest at December 31, 2013 . 
+Developed Acres 
+Undeveloped Acres 
+Total Acres 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+22,604 
+18,206 
+16,381 
+8,941 
+38,985 
+27,147 
+NW Louisiana/E Texas: 
+Haynesville 
+18,960 
+11,238 
+3,734 
+3,731 
+22,694 
+14,969 
+Cotton Valley 
+20,510 
+18,418 
+3,916 
+3,403 
+24,426 
+21,821 
+Area Total (1) 
+24,215 
+21,885 
+4,392 
+3,876 
+28,607 
+25,761 
+Permian Basin: 
+SE New Mexico, West Texas 
+1,120 
+897 
+69,699 
+43,937 
+70,819 
+44,834 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+76,496 
+36,004 
+76,496 
+36,004 
+Total 
+47,939 
+40,988 
+166,968 
+92,758 
+214,907 
+133,746 
+__________________ 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Undeveloped Acreage Expiration 
+The following table sets forth the approximate number of gross and net undeveloped acres at December 31, 2013 that will expire prior to December 31, 2015 by operating area unless production is established within the spacing units covering the acreage prior to the expiration dates, the existing leases are renewed prior to expiration or continued operations maintain the leases beyond the expiration of each respective primary term. 
+Acres 
+Acres 
+Expiring 2014 
+Expiring 2015 
+Gross 
+Net 
+Gross 
+Net 
+South Texas: 
+Eagle Ford 
+2,879 
+846 
+2,343 
+1,777 
+NW Louisiana/E Texas: 
+Haynesville 
+11 
+11 
+— 
+— 
+Cotton Valley 
+11 
+11 
+— 
+— 
+Area Total (1) 
+11 
+11 
+— 
+— 
+Permian Basin: 
+SE New Mexico, West Texas 
+7,775 
+706 
+5,496 
+2,439 
+Other: 
+Wyoming, Utah, Idaho 
+— 
+— 
+— 
+— 
+Total 
+10,665 
+1,563 
+7,839 
+4,216 
+__________________ 
+(1) 
+Some of the same leases cover the gross and net acreage shown for both the Haynesville formation and the shallower Cotton Valley formation. Therefore, the sum of the gross and net acreage for both formations is not equal to the total gross and net acreage for Northwest Louisiana and East Texas. 
+Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless operations are conducted which will serve to maintain the respective leases in effect beyond the expiration of the primary term or production from the acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities in most cases. We also have options to extend some of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. In addition, we may attempt to secure a new lease upon the expiration of certain of our acreage; however, there may be third party leases that become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date or operations are not conducted to maintain the leases in effect beyond the primary term. Our leases are mainly fee leases with primary terms of three to five years. We believe that our lease terms are similar to our competitors’ fee lease terms as they relate to both primary term and royalty interests. 
+21 
+Table of Contents 
+Drilling Results 
+The following table summarizes our drilling activity for the years ended December 31, 2013, 2012 and 2011 : 
+Year Ended December 31, 
+2013 
+2012 
+2011 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Development Wells 
+Productive 
+32 
+20.7 
+36 
+17.1 
+30 
+0.6 
+Dry 
+— 
+— 
+— 
+— 
+— 
+— 
+Exploration Wells 
+Productive 
+14 
+8.7 
+22 
+10.4 
+30 
+10.2 
+Dry (1) 
+1 
+0.4 
+— 
+— 
+— 
+— 
+Total Wells 
+Productive 
+46 
+29.4 
+58 
+27.5 
+60 
+10.8 
+Dry (1) 
+1 
+0.4 
+— 
+— 
+— 
+— 
+__________________ 
+(1) 
+We participated on a non-operated basis in an unsuccessful vertical well test of the Edwards formation on our Atascosa County, Texas acreage in 2013. 
+Marketing 
+Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil and a portion of our heavier liquids move up and down in direct correlation with the oil market as it reacts to supply and demand factors. The prices of the remaining lighter liquids move up and down independently of any relationship between the crude oil and natural gas markets. Transportation costs related to moving crude oil and liquids are also deducted from the price received for crude oil and liquids. 
+Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated midstream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees. When there is an opportunity to do so, the midstream companies may, at our request, process our natural gas at a processing facility and extract liquid hydrocarbons from the natural gas. We are then paid for the extracted liquids based on either a negotiated percentage of the proceeds that are generated from the midstream companies’ sale of the liquids, or other negotiated pricing arrangements using then-current market pricing less fixed rate processing, transportation and fractionation fees. 
+The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuations include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices do adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production do occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations, if they occur, curtail our production capabilities and ability to maintain a steady source of revenue. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors — Our Success Is Dependent on the Prices of Oil and Natural Gas. Low Oil or Natural Gas Prices and the Substantial Volatility in These Prices May Adversely Affect Our Financial Condition and Our Ability to Meet Our Capital Expenditure Requirements and Financial Obligations.” 
+For the year ended December 31, 2013 , we had five significant purchasers that accounted for approximately 87% of our total oil, natural gas and natural gas liquids revenues. For the years ended December 31, 2012 and 2011 , we had three significant purchasers that accounted for approximately 74% and 60% , respectively, of our total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, we do not believe that the loss of any one of these purchasers would have a material adverse impact on our financial condition, results of operations or cash flows for any significant period of time. 
+22 
+Table of Contents 
+About one-third of our acreage in the core area of the Haynesville shale play in Northwest Louisiana is operated by a subsidiary of Chesapeake Energy Corporation. During the fourth quarter of 2013, we notified Chesapeake that we would be electing to take in kind the anticipated natural gas production from most of the wells operated by Chesapeake effective January 1, 2014. In addition, we entered into a five-year natural gas gathering agreement effective January 1, 2014 for this anticipated natural gas production. This agreement has no firm transportation commitments and no natural gas volume commitments. We believe that taking our natural gas production in kind and transporting through this gathering agreement will improve price realizations and reduce marketing and transportation fees and other costs associated with this natural gas production by an average of approximately $0.70 or more per MMBtu. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Effective September 1, 2012, we entered into a firm five-year natural gas processing and transportation agreement whereby we committed to transport the anticipated natural gas production from a significant portion of our Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue we receive varies with the quality of natural gas transported to the processing facilities and the contract period. 
+Under this natural gas processing and transportation agreement, if we do not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, we will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. During certain periods, we had an immaterial natural gas deficiency and the counterparty to this agreement has agreed to waive the deficiency fee. See “Risk Factors — The Marketability of Our Production Is Dependent upon Oil and Natural Gas Gathering, Processing and Transportation Facilities Owned and Operated by Third Parties, and the Unavailability of Satisfactory Oil and Natural Gas Gathering, Processing and Transportation Arrangements Would Have a Material Adverse Effect on Our Revenue.” 
+Title to Properties 
+We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by conducting operations, making lease rental payments or producing oil and natural gas from wells in paying quantities, where required, prior to expiration of various time periods to avoid lease termination. Certain of the leases that we have obtained to date have been purchased by and in the name of professional lease brokers as our nominee. See “Risk Factors — We May Incur Losses or Costs as a Result of Title Deficiencies in the Properties in Which We Invest.” 
+Seasonality 
+Generally, but not always, the demand and price levels for natural gas increase during winter months and decrease during summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer. However, increased summertime demand for electricity can place increased demand on storage volumes. Demand for oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are impacted more significantly by global supply and demand. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Certain of our drilling, completion and other operations are also subject to seasonal limitations. 
+Competition 
+The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which 
+23 
+Table of Contents 
+would adversely affect our competitive position. These competitors may be willing and able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to identify, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs and hydraulic fracturing equipment. 
+Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We have been conducting field operations since 2004 while many of our competitors may have a longer history of operations. Additionally, most of our competitors have demonstrated the ability to operate through industry cycles. 
+The oil and natural gas industry also competes with other energy-related industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. See “Risk Factors — Competition in the Oil and Natural Gas Industry Is Intense, Making It More Difficult for Us to Acquire Properties, Market Oil and Natural Gas and Secure Trained Personnel.” 
+Regulation 
+Oil and Natural Gas Regulation 
+Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these laws, rules and regulations are frequently amended or reinterpreted and new laws, rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations. 
+Texas, New Mexico, Louisiana, Wyoming, Idaho and Utah and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas and other matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the prohibition or restriction on venting or flaring natural gas, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. 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. 
+Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases. 
+Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, as well as under Section 311 of the Natural Gas Policy Act of 1978, or the NGPA. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue. 
+In 2005, Congress enacted the Domenici-Barton Energy Policy Act of 2005, or the Energy Policy Act. The Energy Policy Act, among other things, amended the NGA to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for the sale or transportation of physical natural gas in interstate commerce and to significantly increase the penalties for violations of the NGA, the NGPA or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims. 
+24 
+Table of Contents 
+Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated. 
+Natural gas gathering facilities are exempt from the jurisdiction of FERC under section 1(b) of the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. 
+The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations. 
+In 2007, the Energy Independence & Security Act of 2007, or the EISA, went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future laws or regulations or their impact. 
+U.S. Federal and State Taxation 
+The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes to federal laws on the income taxation of small oil and natural gas exploration and production companies like ours. Among other issues, President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could adversely affect our business and our financial results. See “Risk Factors — We Are Subject to Federal, State and Local Taxes, and May Become Subject to New Taxes or Have Eliminated or Reduced Certain Federal Income Tax Deductions Currently Available with Respect to Oil and Natural Gas Exploration and Production Activities as a Result of Future Legislation, Which Could Adversely Affect Our Business, Financial Condition, Results of Operations and Cash Flows.” 
+Hydraulic Fracturing Policies and Procedures 
+We use hydraulic fracturing as a means to maximize the recovery of oil and natural gas in almost every well that we drill and complete. Our engineers responsible for these operations attend specialized hydraulic fracturing training programs taught by industry professionals. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately two-thirds of the total well costs for our horizontal wells are attributable to overall completion activities, which are primarily focused on hydraulic fracture treatment operations. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget. A change to any federal and state laws and regulations governing hydraulic fracturing could impact these costs and adversely affect our business and financial results. See “Risk Factors — Federal and State Legislation and Regulatory Initiatives Relating to Hydraulic Fracturing Could Result in Increased Costs and Additional Operating Restrictions or Delays.” 
+The protection of groundwater quality is important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the Bureau of Land Management (“BLM”) with respect to federal acreage). 
+Although rare, if and when the cement and steel casing used in well construction requires remediation, we deal with these problems by evaluating the issue and running diagnostic tools, including cement bond logs, temperature logs and pressure testing, followed by pumping remedial cement jobs and other appropriate remedial measures. 
+25 
+Table of Contents 
+The vast majority of hydraulic fracturing treatments are made up of water and sand or other kinds of man-made propping agents. We use major hydraulic fracturing service companies who track and report chemical additives that are used in the fracturing operation as required by the appropriate governmental agencies. These service companies fracture stimulate thousands of wells each year for the industry and invest millions of dollars to protect the environment through rigorous safety procedures, and also work to develop more environmentally friendly fracturing fluids. We also follow safety procedures and monitor all aspects of the fracturing operation in an attempt to ensure environmental protection. We do not pump any diesel in the fluid systems of any of our fracture stimulation procedures. 
+While current fracture stimulation procedures utilize a significant amount of water, we typically recover less than 10% of this fracture stimulation water before produced salt water becomes a significant portion of the fluids produced. All produced water, including fracture stimulation water, is disposed of in permitted and regulated disposal facilities in a way that is designed to avoid any impact to surface waters. 
+Environmental Regulation 
+The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, drilling, completing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to: the Oil Pollution Act of 1990, or the OPA 90, the Clean Water Act, or the CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or the CAA, the Safe Drinking Water Act, or the SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials, or NORM, that may result from our oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We expect to remain in compliance in all material respects with currently applicable environmental laws and regulations and expect that these laws and regulations will not have a material adverse impact on us. 
+The OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and related to liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” under the OPA 90 may include the owner or operator of an onshore facility. The OPA 90 subjects responsible parties to strict, joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with the OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects, navigable waters subject to the OPA 90. We believe that compliance with applicable requirements under the OPA 90 will not have a material adverse effect on us. 
+The CWA and comparable state laws impose restrictions and strict controls regarding the discharge of produced waters, fill materials and other materials into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into certain state and federal waters and to conduct construction activities in those waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the U.S. Environmental Protection Agency, or the EPA, has 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. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards. 
+CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on various 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 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 responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third 
+26 
+Table of Contents 
+parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Although CERCLA generally exempts petroleum from the definition of hazardous substances, our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Many states have adopted similar statutes. Certain state statutes may impose liability for a broader range of contaminants and may not contain a similar exemption for petroleum. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous substances or other materials requiring remediation. 
+RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. Not all of the wastes we generate fall within these exemptions. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes. 
+The CAA, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound (“VOC”) emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also established specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules have required changes to our operations, including the installation of new equipment to control emissions. We continue to evaluate the effect these rules have on our business and operations, which effects we do not expect to be material. 
+Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+The EPA has adopted rules under the CAA for the permitting of greenhouse gas emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The EPA has adopted a multi-tiered approach to this permitting, with the largest sources first subject to permitting. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the United States beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production was first required on an annual basis in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce, depressing the prices we receive for oil and natural gas. 
+27 
+Table of Contents 
+Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or state or regional greenhouse gas cap-and-trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition, results of operations and cash flows. 
+Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently own and operate five underground injection wells and expect to own other similar wells. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties. 
+Our activities involve the use of hydraulic fracturing. For more information on our hydraulic fracturing operations, see “— Hydraulic Fracturing Policies and Procedures.” Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the hydraulic fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition, results of operations and cash flows. 
+In addition, in some states and localities, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities and, in some areas, to severely restrict or prohibit those activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting or permitting requirements, will result in additional expense and delay in our operations. 
+The EPA has recently asserted federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. The EPA recently issued SDWA permitting guidance for hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids in those states where the EPA is the permitting authority. Although we do not currently pump diesel in the fluid systems of any of our fracture stimulation procedures, any such change in our practices may cause us to be subject to this guidance. In addition, the EPA is currently conducting a study on the effects of hydraulic fracturing on drinking water resources. A progress report was released in December 2012, with draft final results expected in 2014. Further, the BLM has proposed rules to regulate hydraulic fracturing on federal lands. The EPA has also announced an initiative under the Toxic Substance Control Act to develop regulations governing the disclosure of hydraulic fracturing chemicals. 
+Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire the properties against some of the liability for environmental claims associated with the properties. While we do not believe that costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, we cannot provide any assurances that these costs will not result in material expenditures that adversely affect our profitability. 
+Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub- 
+28 
+Table of Contents 
+surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, 
+have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned partly by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us. 
+We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards. 
+The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in material restrictions on land use and may materially impact oil and natural gas development. If a portion of our leases were designated as critical or suitable habitat, our ability to maximize production from our leases may be adversely impacted. 
+We have not in the past been, and do not anticipate in the near future to be, required to expend amounts that are material in relation to our total capital expenditures as a result of environmental laws and regulations, but since these laws and regulations are periodically amended, we are unable to predict the ultimate cost of compliance. We have no assurance that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. See “Risk Factors — We Are Subject to Government Regulation and Liability, Including Complex Environmental Laws, Which Could Require Significant Expenditures.” 
+The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The EPA has announced that one of its enforcement initiatives for 2014 to 2016 is to focus on compliance by the energy extraction sector. Any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we have no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. 
+We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition, results of operations and cash flows. 
+Office Lease 
+Our corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. In April 2013 , we entered into the fifth amendment to our office lease agreement. This amendment increased the square footage of our corporate headquarters to 40,071 square feet effective July 1, 2013 . The lease expires on June 30, 2022 . 
+Employees 
+At December 31, 2013 , we had 66 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, production operations, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill all of our wells and usually perform field and on-site production operation services for us, including facilities construction, pumping, maintenance, dispatching, inspection and testing. If significant opportunities for company growth arise and require additional management and professional expertise, we will seek to employ qualified individuals to fill positions where that expertise is necessary to develop those opportunities. 
+29 
+Table of Contents 
+Available Information 
+Our Internet website address is www.matadorresources.com . We make available, free of charge, through our website, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, the charters of our Audit Committee, Corporate Governance Committee, Executive Committee and Nominating, Compensation and Planning Committee, and our Code of Ethics and Business Conduct for Officers, Directors and Employees, are available through our website and in print to any shareholder who provides a written request to the Corporate Secretary at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The contents of our website are not intended to be incorporated by reference into this Annual Report on Form 10-K or any other report or document we file and any reference to our website is intended to be an inactive textual reference only.
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+Item 13. Certain Relationships and Related Transactions, and Director Independence. 
+The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
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+Item 9A. Controls and Procedures. 
+Evaluation of Disclosure Controls and Procedures 
+As of the end of the period covered by this Annual Report on Form 10-K, we evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2013 to ensure that (i) information required to be disclosed in the reports it files and submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that (ii) information required to be disclosed under the Exchange Act is accumulated and communicated to the Company’s management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. 
+Changes in Internal Control over Financial Reporting 
+During the quarter ended December 31, 2013 , there were no changes in our internal controls that have materially affected or are reasonably likely to have a material effect on our internal control over financial reporting. 
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+Table of Contents 
+Management’s Report on Internal Control over Financial Reporting 
+Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this Annual Report on Form 10-K based on the framework in 1992 “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. 
+Grant Thornton LLP, our independent registered public accounting firm, has issued an attestation report on our controls over financial reporting as of December 31, 2013 as included herein. 
+Important Considerations 
+The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management. 
+76 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Shareholders 
+Matador Resources Company 
+We have audited the internal control over financial reporting of Matador Resources Company (a Texas corporation) and subsidiaries (collectively 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 March 17, 2014 expressed an unqualified opinion on those financial statements. 
+/s/ GRANT THORNTON LLP 
+Dallas, Texas 
+March 17, 2014 
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+TRANSACTIONS WITH RELATED PERSONS 
+Since January 1, 2013, there has not been, nor is there currently proposed, any transaction or series of similar transactions to
+which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our 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, other than compensation arrangements with directors and executive officers, which are described in “Executive Compensation—Compensation Discussion and
+Analysis” above. 
+Procedures for Approval of Related Party Transactions 
+Our Board has adopted a written related party transaction policy. Pursuant to this policy, a “Related Party Transaction” is
+defined as a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or series of related transactions, or any material amendment to any such transaction, involving a
+Related Party (as defined below) and in which we are a participant, other than: 
+• 
+a transaction involving compensation of directors; 
+• 
+a transaction involving compensation of an executive officer or involving an employment agreement, severance agreement, change in control provision or
+agreement or a special supplemental benefit for an executive officer; 
+• 
+a transaction available to all employees generally or to all salaried employees generally; 
+• 
+a transaction with a Related Party involving less than $120,000; 
+• 
+a transaction in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that
+class receive the same benefit on a pro rata basis; or 
+• 
+a transaction in which the rates or charges involved therein are determined by competitive bids, or a transaction that involves the rendering of
+services as a common or contract carrier, or public utility, at rates or charges fixed in conformity with law or governmental authority. 
+“Related Party” means: 
+• 
+any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors or nominees for directors;
+• 
+any person who is known by us to be the beneficial owner of more than 5% of our Common Stock; 
+• 
+any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law,
+father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, nominee for director, executive officer or a beneficial owner of more than 5% of our Common Stock; and 
+• 
+any firm, corporation or other entity that is owned or controlled by any of the foregoing persons or in which any of the foregoing persons is a general
+partner or executive officer or in which such person, together with all other of the foregoing persons, owns 10% or more of the equity interests thereof. 
+Pursuant to our related party transaction policy, the Audit Committee must review all material facts of each Related Party Transaction and recommend either approval or disapproval of the Related Party
+Transaction to the full Board, subject to certain limited exceptions. In determining whether to recommend approval or disapproval of the Related Party Transaction, the Audit Committee must, after reviewing all material facts of the Related Party
+Transaction and the Related Party’s relationship and interest, determine whether the Related Party Transaction is fair to the Company. Further, the policy requires that all Related Party Transactions be disclosed in our filings with the SEC
+and/or our website in accordance with applicable laws, rules and regulations. 
+56 
+Table of Contents
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