2009 Annual Report Letter to Stockholders Proxy Statement Form 10-K L e t t e r t o S t o c k h o d e r s l LETTER TO OUR STOCKHOLDERS The more things change, the more they are the same. Never has this been a more profound statement. After enduring a year of extreme stress in the financial markets, we find ourselves at the end of 2009 once again owning producing properties that we had originally contributed to our master limited partnership. After we determined that an initial public offering of the partnership was not going to be possible due to the condition of the financial markets, we found the only feasible solution was to merge the partnership into the parent, Abraxas Petroleum Corporation. After getting over the disappointment of not being able to take the partnership public, which in my mind is still a very viable financial vehicle for certain producing properties, we now find ourselves with a larger, stronger company, and one capable of pursuing our exciting upside potential. Last year in my letter I mentioned two significant wells that had been placed on production at the end of 2008. As an update, in Spring 2009, the Nordheim #2H was successfully fracture stimulated with six stages and continues to produce approximately 3 million cubic feet of gas per day after having produced 1.2 billion cubic feet of gas during its first year of production. We look forward to a number of low risk offsets to this well when gas markets justify further development of this area. In the Brooks Draw area of Wyoming, we followed up our success of the Lakeside #1H with the Peregrine #5H, a horizontal well in the Turner sand that we successfully fracture stimulated with seven stages. Since most of our acreage in this area is held by production and thus not subject to lease expiration, we have no plans for offsets this year. Nonetheless, we may drill one offset this year to test the Niobrara formation, which is an emerging new play in the area being developed with horizontal staged frac technology. By virtue of a large acquisition by the partnership which closed in January, 2008, we acquired a large number of producing properties in the Williston Basin of North Dakota and Montana. Included in these properties were producing wells that hold (by production) in excess of 20,000 net acres in what has emerged as the most prolific oil play being developed in North America, the Bakken and Three Forks. To date, we have participated in three successful Bakken/Three Forks wells, albeit with relatively small interests. At the time of this letter, we are in the process of permitting our first two operated wells in the play and are making plans for more throughout the year, in addition to participating in a non-operated position when the opportunity arises. With advances in technology and a relatively stable oil price, this play has become very economic and repeatable. We will be very active in this play for the foreseeable future, including acquiring additional acreage in our areas of interest. Another emerging resource play is developing right in our backyard, the Eagle Ford Shale in South Texas. Our presence in this play started with our legacy acreage position held by our wells that produce from the underlying Edwards formation, all of which have Eagle Ford Shale behind pipe. During the past year, we acquired additional acreage, and will continue to do so in very specific geologically and geophysically controlled areas. We are planning our first Eagle Ford well this year. The Eagle Ford has been given perhaps even more early credibility than the Bakken as most of the major oil companies have a significant presence in the play. Our geological staff has identified another oil-prone resource play that appears to be amenable to horizontal staged frac technology. We are out in front of the industry in this play and have been able to establish an initial acreage position relatively inexpensively with little competition. This advantage will likely not last for long as a number of wells have been drilled by other operators which has de-risked the play somewhat. For obvious competitive reasons, we cannot divulge the location of this play at this time, but rest assured we are excited about its potential and we will announce it as soon as we are comfortable with our acreage position. Another benefit of the acquisition by the partnership in early 2008 was a position in the Granite Wash play in the Texas Panhandle. We recently participated for a relatively small interest in a well, which at the time of this letter has been on production for six weeks and is currently producing approximately 17 million cubic feet of liquids-rich gas and 400 barrels of condensate per day. This well is the most productive well we have ever participated in and we have additional acreage in the play, which we are in the process of quantifying. We have commenced an initiative to rationalize our producing assets by selling our non-core, principally non-operated properties and using the proceeds to pay down debt and to accelerate our development in the Bakken and Eagle Ford. This initiative has already resulted in the divestiture of a number of properties on very economic terms. The term loan portion of our long-term debt resulting from the merger of the Partnership has now been repaid and plans to expand capital spending are underway. We expect this initiative to be complete by the end of 2010 and the result will be a more focused Abraxas with three core areas, South Texas, West Texas and the northern Rockies, and a balance sheet that will allow aggressive development of these core areas. Our position in the many resource plays that I have discussed in this letter together with our traditional bread and butter conventional plays in South and West Texas, makes me feel very good about 2010 and beyond for Abraxas. The confusion about financial statements and reserve reports due to partnership accounting is behind us and 2010 should turn out to be the watershed year for which we have all been waiting. I, our staff and directors, thank you for your patience. Sincerely, Robert L.G. Watson ABRAXAS PETROLEUM CORPORATION 18803 Meisner Drive San Antonio, Texas 78258 (210) 490-4788 April 15, 2010 Dear Stockholders: You are cordially invited to attend the 2010 Annual Meeting of Stockholders of Abraxas Petroleum Corporation to be held on Wednesday, May 19, 2010, at 10:30 a.m., local time, at the Petroleum Club of San Antonio located at 8620 N. New Braunfels, Suite 700, San Antonio, Texas 78217. We hope that you will be able to attend the meeting. Matters on which action will be taken at the meeting are explained in detail in the Notice and Proxy Statement following this letter. Whether or not you expect to attend the Annual Meeting, it is important that you vote your shares. We are offering multiple options for voting your shares. All holders may vote their shares by mail or written ballot at the Annual Meeting. If you are a beneficial holder, you may also vote your shares by telephone or the Internet using the instructions on each proxy card. In order to vote your shares by mail, please mark, sign, and date the enclosed proxy and return it promptly in the enclosed envelope. Thank you for your continued support of Abraxas Petroleum Corporation. Robert L.G. Watson Chairman of the Board, President, and Chief Executive Officer P r o x y S t a t e m e n t P r o x y S t a t e m e n t ABRAXAS PETROLEUM CORPORATION 18803 Meisner Drive San Antonio, Texas 78258 (210) 490-4788 NOTICE OF ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 19, 2010 To the Stockholders of Abraxas Petroleum Corporation: NOTICE IS HEREBY GIVEN that the Annual Meeting of Stockholders of Abraxas Petroleum Corporation (“Abraxas”) will be held at the Petroleum Club of San Antonio located at 8620 N. New Braunfels, Suite 700, San Antonio, Texas 78217, on Wednesday, May 19, 2010, at 10:30 a.m., local time, for the following purposes: (1) To elect as directors to the Abraxas Board of Directors the four nominees named below for a term of three years: • Harold D. Carter • Brian L. Melton • Edward P. Russell • Robert L.G. Watson (2) To approve an amendment to the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan; (3) To ratify the appointment of BDO Seidman, LLP as Abraxas’ independent registered public accounting firm for the year ending December 31, 2010; and (4) To transact any other business that has been properly brought before the meeting in accordance with the provisions of the Company’s Amended and Restated Bylaws. Our Board recommends that you vote FOR Proposals 1, 2 and 3. We cordially invite you to attend the Annual Meeting in person. Whether or not you expect to attend the Annual Meeting, we urge you to mark, sign, date, and return the enclosed proxy card as soon as possible in the enclosed envelope. If you are a beneficial holder, you may also vote your shares by telephone or the Internet using the instructions on each proxy card. You may revoke your proxy at any time prior to the Annual Meeting, and, if you attend the Annual Meeting, you may vote your shares of Abraxas stock in person. The Board of Directors has fixed the close of business on April 12, 2010 as the record date for the determination of the stockholders entitled to notice of and to vote at the Annual Meeting and any adjournment thereof. By Order of the Board of Directors Stephen T. Wendel SECRETARY San Antonio, Texas April 15, 2010 Important Notice Regarding the Availability of Proxy Materials for the Annual Meeting of Stockholders to be held May 19, 2010 This proxy statement and our 2009 Annual Report on Form 10-K are available at www.abraxaspetroleum.com/proxy, which does not have “cookies” that identify visitors to the site. ABRAXAS PETROLEUM CORPORATION 18803 Meisner Drive San Antonio, Texas 78258 (210) 490-4788 PROXY STATEMENT P r o x y S t a t e m e n t The Board of Directors of Abraxas Petroleum Corporation is soliciting proxies to vote shares of common stock at the 2010 Annual Meeting of Stockholders to be held at 10:30 a.m., local time, on Wednesday, May 19, 2010, at the Petroleum Club of San Antonio located at 8620 N. New Braunfels, Suite 700, San Antonio, Texas 78217, and at any adjournment thereof. This Proxy Statement and the accompanying Proxy are first being mailed to stockholders on or about April 12, 2010. For ten days prior to the annual meeting, a complete list of stockholders entitled to vote at the annual meeting will be available for examination by any stockholder for any purpose relevant to the annual meeting during ordinary business hours at Abraxas’ executive offices, located at the address set forth above. Record Date; Shares Entitled To Vote; Quorum The Board of Directors has fixed the close of business on April 12, 2010 as the record date for Abraxas stockholders entitled to notice of and to vote at the annual meeting. Holders of common stock as of the record date are entitled to vote at the annual meeting. As of the record date, there were 76,246,967 shares of Abraxas common stock outstanding, which were held by approximately 1,217 holders of record. Stockholders are entitled to one vote for each share of Abraxas common stock held as of the record date. The holders of a majority of the outstanding shares of Abraxas common stock issued and entitled to vote at the annual meeting must be present in person or by proxy to establish a quorum for business to be conducted at the annual meeting. Abstentions and “broker non-votes” are treated as shares that are present and entitled to vote for purposes of determining the presence of a quorum. If you own shares through a bank or broker in street name, you may instruct your bank or broker how to vote your shares. A “broker non-vote” occurs when you fail to provide your bank or broker with voting instructions and the bank or broker does not have the discretionary authority to vote your shares on a particular proposal because the proposal is not a routine matter under the New York Stock Exchange rules. Proposal 1 (election of directors) and Proposal 2 (to approve the amendment to the Abraxas Petroleum Corporation 2005 Non-Employees Long-Term Equity Incentive Plan) are not considered routine matters under the current New York Stock Exchange rules, so your bank or broker will not have discretionary authority to vote your shares held in street name on those items. A broker non-vote may also occur if your broker fails to vote your shares for any reason. Proposal 3 (ratification of the appointment of our independent registered public accounting firm) is considered a routine matter under the New York Stock Exchange rules, so your bank or broker will have discretionary authority to vote your shares held in street name on that item. Important Change: Under the new rules of the New York Stock Exchange, if you own shares in “street name” through a broker and do not vote, your broker may not vote your shares on proposals determined to be “non-routine.” In such cases, the absence of voting instructions results in a “broker non-vote.” Broker non-voted shares count toward achieving a quorum requirement for the annual meeting, but they do not affect the determination of whether the non-routine matter is approved or rejected. The proposal to ratify the appointment of BDO Seidman, LLP as our independent registered public accounting firm is the only matter in this proxy statement considered to be a routine matter for which brokers will be permitted to vote on behalf of their clients if no voting instructions are furnished. Since Proposals 1 and 2 are non-routine matters, broker non-voted shares will not count as votes cast to affect the determination of whether they are approved or rejected. Therefore, it is important that you provide voting instructions to your broker. Votes Required The votes required for each proposal is as follows: Election of Directors. The nominees for director who receive the most votes will be elected. Therefore, if you do not vote for a particular nominee or you indicate “withhold authority to vote” for a particular nominee on your proxy card, your abstention will have no effect on the election of directors. To be elected, each director must receive a majority of the votes 1 cast (the number of shares voted “for” a director nominee must exceed the number of votes cast “against” that nominee) at the meeting. Non-votes are not considered votes cast “for” or “against” this proposal at the annual meeting and will have no effect on the approval to elect directors. 2005 Directors Plan. The proposal to amend the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long- Term Equity Incentive Plan must receive a majority of the total votes cast on the proposal. Therefore, abstentions will have the same legal effect as a vote against the proposal. Non-votes are not considered votes cast at the meeting for this proposal and will have no effect on the approval to amend the 2005 Directors Plan. Appointment of Independent Registered Public Accounting Firm. The proposal to ratify the appointment of Abraxas’ independent registered public accounting firm must receive the affirmative vote of the holders of a majority of the total votes cast on the proposal. Therefore, abstentions will have the same legal effect as a vote against the proposal. Since this proposal is considered a “routine” matter, brokers will be permitted to vote on behalf of their clients, if no voting instructions are furnished. Voting of Proxies Votes cast in person or by proxy at the annual meeting will be tabulated at the annual meeting. All valid, unrevoked proxies will be voted as directed. In the absence of instructions to the contrary, properly executed proxies will be voted in favor of each of the proposals listed in the notice of annual meeting and for the election of the nominees for director set forth herein. If any matters other than those addressed on the proxy card are properly presented for action at the annual meeting, the persons named in the proxy will have the discretion to vote on those matters in their best judgment, unless authorization is withheld. Many of our stockholders hold their shares through a stockbroker, bank or other nominee rather than directly in their own names. As summarized below, there are some distinctions between shares held of record and those owned beneficially. Stockholder of Record. If your shares are registered directly in your name or with our transfer agent, American Stock Transfer & Trust Company, you are considered the stockholder of record with respect to those shares and these proxy materials are being sent directly to you by us. As a stockholder of record, you have the right to grant your voting proxy directly to us or to vote in person at the annual meeting. We have enclosed a proxy card for your use. Beneficial Holder. If your shares are held in a brokerage account or by a bank or other nominee, you are considered the beneficial owner of the shares held in street name, and these proxy materials are being forwarded to you by your broker or nominee who is considered the stockholder of record with respect to those shares. As the beneficial owner, you have the right to direct your broker on how to vote and are also invited to attend the meeting. However, since you are not the stockholder of record, you may not vote these shares in person at the meeting. Your broker or nominee has enclosed a proxy card for your use. How To Vote By Proxy; Revocability of Proxies To vote by proxy, you must mark, sign, date, and return the proxy card in the enclosed envelope. If you are a beneficial holder, you may also vote your shares by telephone or the Internet using the instructions on each proxy card. Any Abraxas stockholder who delivers a properly executed proxy may revoke the proxy at any time before it is voted. Proxies may be revoked by: • • • delivering a written revocation of the proxy to the Abraxas Secretary before the annual meeting; submitting a later-dated proxy by mail, telephone or the Internet; or appearing at the annual meeting and voting in person. Attendance at the annual meeting will not, in and of itself, constitute revocation of a proxy. An Abraxas stockholder whose shares are held in the name of its broker, bank or other nominee must bring a legal proxy from its broker, bank or other nominee to the meeting in order to vote in person. 2 P r o x y S t a t e m e n t Deadline for Voting by Proxy In order to be counted, votes cast by proxy must be received prior to the annual meeting. Solicitation of Proxies Proxies will be solicited by mail. Proxies may also be solicited personally, or by telephone, fax, or other means by the directors, officers, and employees of Abraxas. Directors, officers, and employees soliciting proxies will receive no extra compensation, but may be reimbursed for related out-of-pocket expenses. In addition to solicitation by mail, Abraxas will make arrangements with brokerage houses and other custodians, nominees, and fiduciaries to send the proxy materials to beneficial owners. Abraxas will, upon request, reimburse these brokerage houses, custodians, and other persons for their reasonable out-of-pocket expenses in doing so. Abraxas will pay the cost of solicitation of proxies. Important Information Regarding Delivery of Proxy Material The Securities and Exchange Commission has adopted amendments to the proxy rules that change how companies must provide proxy materials to its stockholders. These new rules are often referred to as “notice and access,” under which a company may select either of the following options for making proxy materials available to its stockholders: • • the full set delivery option; or the notice only option. A company may use a single method for all of its stockholders, or use full set delivery for some while adopting the notice only option for others. Full Set Delivery Option Under the full set delivery option, a company delivers all proxy material to its stockholders by mail as it would have done prior to the change in the rules. In addition to delivery of proxy materials to stockholders, the company must post all proxy materials on a publicly-accessible website and provide information to stockholders about how to access the website. In connection with its 2010 Annual Meeting of Stockholders, Abraxas elected to use the full set delivery option. Accordingly, you should have received Abraxas’ proxy materials by mail. These proxy materials include the Notice of Annual Meeting of Stockholders, proxy statement, proxy card and Annual Report on Form 10-K. Additionally, Abraxas has posted these materials at www.abraxaspetroleum.com/proxy. Notice Only Option Under the notice only option, a company must post all proxy materials on a publicly-accessible website. Instead of delivering proxy materials to its stockholders, the company instead delivers a “Notice of Internet Availability of Proxy Material.” The notice includes, among other matters: • • • information regarding the date and time of the annual meeting of stockholders as well as the items to be considered at the meeting; information regarding the website where the proxy materials are posted; and various means by which a stockholder can request paper or e-mail copies of the proxy materials. If a stockholder requests paper copies of the proxy materials, these materials must be sent to the stockholder within three business days and by first class mail. Abraxas May Use the Notice Only Option in the Future Although Abraxas elected to use the full set delivery option in connection with the 2010 Annual Meeting of Stockholders, it may choose to use the notice only option in the future. By reducing the amount of materials that a company needs to print and mail, the notice only option provides an opportunity for costs savings as well as conservation of paper products. Many companies that have used the notice only option have also experienced a lower participation rate resulting in fewer stockholders voting at the annual meeting. Abraxas plans to evaluate the future possible cost savings as well as the possible impact on stockholder participation as it considers future use of the notice only option. 3 Householding The Securities and Exchange Commission has adopted rules that permit companies and intermediaries (e.g. brokers) to satisfy the delivery requirements for proxy materials with respect to two or more stockholders sharing the same address by delivering a single set of proxy materials. This process, which is commonly referred to as “householding,” potentially results in extra convenience for stockholders and cost savings for companies. If, at any time, you no longer wish to participate in “householding” and would prefer to receive a separate set of proxy materials, you may: • • Send a written request to Investor Relations, Abraxas Petroleum Corporation, 18803 Meisner Drive, San Antonio, Texas 78258, if you are a stockholder of record, or Notify your broker, if you hold your common shares in street name. 4 P r o x y S t a t e m e n t PROPOSAL ONE Election of Directors Abraxas’ Articles of Incorporation divide the Board of Directors into three classes of directors serving staggered three- year terms, with one class to be elected at each annual meeting of stockholders. At this year’s meeting, four Class III directors are to be elected for a term of three years to hold office until the expiration of their term in 2013, or until a successor has been elected and duly qualified. The nominees for Class III directors are Harold D. Carter, Brian L. Melton, Edward P. Russell and Robert L.G. Watson. Assuming the presence of a quorum, the nominees for director who receive the most votes will be elected. The enclosed proxy card provides a means for stockholders to vote for or to withhold authority to vote for the nominees for director. If a stockholder executes and returns a proxy, but does not specify how the shares represented by such stockholder’s proxy are to be voted, such shares will be voted FOR the election of the nominees for director. In determining whether this item has received the required number of affirmative votes, abstentions will have no effect. Non-votes are not considered votes cast “for” or “against” this proposal at the annual meeting and will have no effect on the approval to elect directors. The Board of Directors recommends a vote “FOR” the election of the nominees to the Board of Directors. Board of Directors and Executive Officers The following table sets forth the names, ages, and positions of the executive officers and directors of Abraxas. The term of the Class I directors expires in 2012, the term of the Class II directors expires in 2011 and the term of the Class III directors expires in 2010. Name and Municipality of Residence Age Office Robert L.G. Watson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Chairman of the Board, President and Chief San Antonio, Texas Executive Officer C. Scott Bartlett, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Director Richmond Hill, Georgia Franklin A. Burke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Director Doyleston, Pennsylvania Harold D. Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Director Dallas, Texas Ralph F. Cox . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Director Fort Worth, Texas Dennis E. Logue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Director Enfield, New Hampshire Brian L. Melton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Director Kansas City, Missouri Paul A. Powell, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Director Roanoke, Virginia Edward P. Russell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Director Stilwell, Kansas Chris E. Williford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Executive Vice President, Chief Financial Officer San Antonio, Texas and Treasurer Lee T. Billingsley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Vice President – Exploration San Antonio, Texas William H. Wallace . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Vice President – Operations Blanco, Texas Stephen T. Wendel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Vice President – Land & Marketing and Corporate San Antonio, Texas Secretary Barbara M. Stuckey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Vice President – Corporate Finance and Assistant San Antonio, Texas Secretary 5 Class III II I III II II III I III — — — — — Executive Officers Robert L.G. Watson has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. From January 2003 to July 2009, Mr. Watson served as Chairman of the Board, Chief Executive Officer and director of Grey Wolf Exploration Inc., which we refer to as Grey Wolf, an oil and gas exploration and production company and which was, until February 2005, a wholly-owned subsidiary of Abraxas. From May 1996 to January 2003, Mr. Watson served as President, Chairman of the Board and a director of Grey Wolf Exploration, Inc., a former wholly-owned subsidiary of Abraxas, which we refer to as Old Grey Wolf, the capital stock of which was sold by Abraxas in January 2003. From November 1996 to January 2003, Mr. Watson was Chairman of the Board, President and a director of Canadian Abraxas Petroleum Limited, which we refer to as Canadian Abraxas, a former wholly-owned Canadian subsidiary of Abraxas, the capital stock of which was sold by Abraxas in January 2003. Prior to forming Abraxas, Mr. Watson held petroleum engineering positions with Tesoro Petroleum Corporation and DeGolyer and MacNaughton. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974. Chris E. Williford was elected Vice President, Treasurer and Chief Financial Officer of Abraxas in January 1993 and as Executive Vice President and a director of Abraxas in May 1993. Mr. Williford resigned as a director of Abraxas in December 1999. From November 1996 to January 2003, Mr. Williford was Vice President and Assistant Secretary of Canadian Abraxas and Vice President of Old Grey Wolf. Prior to joining Abraxas, Mr. Williford was Chief Financial Officer of American Natural Energy Corporation and President of Clark Resources Corp. Mr. Williford also serves as Chairman of Williford Information Corp., a privately-held desktop publishing company. Mr. Williford received a Bachelor of Science degree in Business Administration from Pittsburg State University in 1973. Lee T. Billingsley has served as Vice President – Exploration since joining Abraxas in 1998. Dr. Billingsley founded Sandia Oil & Gas Corp. in 1983 and served as its President until Sandia merged into Abraxas in 1998. Prior to forming Sandia, Dr. Billingsley worked for Tenneco Oil Company and American Quasar Petroleum. Dr. Billingsley served as President of the American Association of Petroleum Geologists (AAPG) for the 2006-2007 term. Dr. Billingsley holds three degrees in Geology, Bachelor of Science and Doctorate from Texas A&M University and Master of Science from Colorado School of Mines. William H. Wallace has served as Vice President – Operations since 2000. Mr. Wallace served as Abraxas’ Superintendent/Senior Operations Engineer, from 1995 to 2000. Prior to joining Abraxas, Mr. Wallace was associated with Dorchester Gas Producing Company and Parker and Parsley. Mr. Wallace received a Bachelor of Science degree in Petroleum Engineering from Texas Tech University in 1981. Stephen T. Wendel has served as Vice President – Land and Marketing since 1990 and as Corporate Secretary since 1988. Mr. Wendel served as Abraxas’ Manager of Joint Interests and Natural Gas Contracts, from 1982 to 1990. Prior to joining Abraxas, Mr. Wendel held accounting, auditing and marketing positions with Tenneco Oil Company and Tesoro Petroleum Corporation. Mr. Wendel also serves as a director of the Corporation Board and the Development Board of Texas Lutheran University. Mr. Wendel received a Bachelor of Business Administration degree in Accounting from Texas Lutheran University in 1971. Barbara M. Stuckey has served as Vice President – Corporate Finance and Assistant Secretary since 2007. Ms. Stuckey joined Abraxas in 1997 and has held positions in investor relations, corporate finance, land and marketing. Ms. Stuckey received a Bachelor of Arts degree from the University of Texas at San Antonio 1991 and a Master of Business Administration degree from the Bordeaux Business School in 2004. Director Nominees Harold D. Carter has served as a director of Abraxas since October 2003. Mr. Carter has more than 40 years experience in the oil and gas industry and has been an independent consultant since 1990. Prior to consulting, Mr. Carter served as Executive Vice President of Pacific Enterprises Oil Company (USA). Before that, Mr. Carter was associated for 20 years with Sabine Corporation, ultimately serving as President and Chief Operating Officer from 1986 to 1989. Mr. Carter has served as a director of Brigham Exploration Company, a publicly traded oil and gas company, since 1998 and Longview Energy Company, a privately-owned oil and gas exploration and production company, since 1999. Mr. Carter also serves as Vice Chairman of the Board of Trustees for the Texas Scottish Rite Hospital for Children. Mr. Carter previously served as a director of Abraxas from 1996 to 1999, as an advisory director from 1999 to October 2003 and as a director of Energy Partners. Ltd, a publicly-traded oil and gas exploration and production company, from 2000 to 2009. Mr. Carter received a Bachelor of Business Administration degree in Petroleum Land Management from the University of Texas and completed the Program for Management Development at the Harvard University Business School. 6 P r o x y S t a t e m e n t Brian L. Melton, a director of Abraxas since October 2009, has served as Vice President of Corporate Strategy of Inergy, L.P. (Nasdaq: NRGY), a publicly traded limited partnership that specializes in retail propane distribution and midstream processing and storage facilities, since September 2008. Prior to joining Inergy, Mr. Melton was a Director in the Energy Corporate Investment Banking groups of Wachovia Securities and A.G. Edwards, prior to its merger with Wachovia in October of 2007. Mr. Melton joined A.G. Edwards in July 2000 and was a senior member of the energy corporate finance team. From November 1995 until July 2000, Mr. Melton served as Director of Finance & Corporate Planning with TransMontaigne Inc., a downstream refined products supply, transportation and logistics company. Mr. Melton previously served as director of Abraxas General Partner, LLC, the general partner of Abraxas Energy Partners, L.P., which we refer to as the Partnership. Mr. Melton received a Bachelor of Science degree in Management and a Master of Business Administration degree from Arkansas State University. Edward P. Russell, a director of Abraxas since October 2009, has served as President of Tortoise Capital Resources Corp. since April 2007. Prior to joining Tortoise Capital Advisors, Mr. Russell was a Managing Director at Stifel, Nicolaus & Company, Inc. where he headed the Energy and Power group. Prior to Stifel, Mr. Russell served more than 15 years as an investment banker at Pauli & Company, Inc. and Arch Capital, LLC and as a commercial banker with Magna Bank and Southside National Bank. Mr. Russell also serves as a director of VantaCore Partners, a private partnership specializing in aggregates, and International Resource Partners, LP, a coal company. Mr. Russell previously served as director of Abraxas General Partner, LLC, the general partner of the Partnership, and Quest Midstream Partners, L.P., a privately-owned partnership. Mr. Russell attended Maryville University in St. Louis, Missouri. Robert L.G. Watson, Abraxas’ Chairman of the Board, President and Chief Executive Officer, is a Class III director with a term expiring in 2010. Directors with Terms Expiring in 2011 and 2012 C. Scott Bartlett, Jr., a director of Abraxas since December 1999, has over 50 years of commercial banking experience, the most recent being with National Westminster Bank USA (prior to being acquired by Bank of America), ultimately serving as Executive Vice President, Senior Lending Officer and Chairman of the Credit Policy Committee. Mr. Bartlett previously served as a director of NVR, Inc., a publicly-traded, nationwide home builder, from 1993 to 2009, and where he served on the audit committee for 15 years. Mr. Bartlett attended Princeton University, and has a certificate in Advanced Management from Pennsylvania State University. Franklin A. Burke, a director of Abraxas since June 1992, has served as President and Chief Executive Officer of Burke, Lawton, Brewer & Burke, a securities brokerage firm, since 1964, as President of Venture Securities Corporation, since 1971, and as President, Director of Research and Portfolio Management of BLB&B Advisors, LLC, since 2006. Mr. Burke also serves as Trustee and Treasurer of The Williamson Free School of Mechanical Trades. Mr. Burke currently serves as a director of Starkey Chemical Process Company and as a director and President of Omega Institute, an allied health post-secondary school. Mr. Burke received a Bachelor of Science degree in Business Administration from Kansas State University in 1955, a Masters degree in Finance from University of Colorado in 1960 and studied at the graduate level at the London School of Economics from 1962 to 1963. Ralph F. Cox, a director of Abraxas since December 1999, has over 50 years of oil and gas industry experience, over 30 of which was with Atlantic Richfield Company (ARCO). Mr. Cox retired from ARCO in 1985 after serving as Vice Chairman. Mr. Cox then joined Union Pacific Resources, retiring in 1989 as President and Chief Operating Officer. Mr. Cox then joined Greenhill Petroleum Corporation as President until leaving in 1994 to pursue a consulting business. Mr. Cox currently serves on the board of CH2M Hill Companies, an engineering and construction firm, and as a trustee for Fidelity Mutual Funds. Mr. Cox also serves as a director of Validus International, a company specializing in oil field drilling tools, as a director of World GTL Inc., a gas-to-liquids production facility, as a director of E-T Energy Ltd., a Canadian oil sands extraction company. Mr. Cox previously served as a director of Abraxas General Partner, LLC, the general partner of the Partnership, and as an advisory director of Impact Petroleum, an oil and gas exploration and production company. Mr. Cox received Bachelor of Science degrees in Petroleum Engineering and Mechanical Engineering from Texas A&M University in 1954 and completed advanced studies at Emory University. Dennis E. Logue, a director of Abraxas since April 2003, has served as Chairman of the Board of Directors of Ledyard Financial Group, the holding company for Ledyard National Bank, since August 2005. Mr. Logue served as Dean and Fred E. Brown Chair at the Michael F. Price College of Business at the University of Oklahoma from 2001 through September 2005. Prior to joining Price College, Mr. Logue was the Steven Roth Professor at the Amos Tuck School at Dartmouth 7 College where he had been since 1974. Mr. Logue has served as a director of Waddell & Reed Financial, Inc., a publicly- traded, national financial services organization, since 2002 and Duckwall-ALCO Stores, Inc., a publicly-traded, general merchandise retailer serving smaller, hometown communities, since 2005. Mr. Logue also serves on the board of Hypertherm, a privately-owned company specializing in plasma cutting tools and technology, and as a Trustee for the Montshire Museum of Science. Mr. Logue previously served on the board of Synergy, a research and development company. Mr. Logue holds degrees from Fordham College, Rutgers, and Cornell University. Paul A. Powell, Jr., a director of Abraxas since August 2005, has served as Vice President and director of Mechanical Development Co., Inc. a maker of precision production machine parts, since 1984. Mr. Powell is a managing partner of Claytor Equity Partners, Cortland Partners, JWM Partners, Emory Partners, Burnett Partners and President of Somerset Investments, Inc. Mr. Powell is also manager of Westpoint (2002) LLC and WMP Properties LLC, and co-manager of Wessex LLC. Mr. Powell currently serves on the board of trustees of Emory & Henry College and as trustee for numerous charitable trusts. Mr. Powell previously served as director of Abraxas from 1987 to 1999 and as an advisory director from 1999 to August 2005, in addition to previously serving on the board of the Blue Ridge Mountain Council and Boy Scouts of America. Mr. Powell attended Emory & Henry College and graduated from National Business College with a degree in Accounting. Composition of the Board of Directors The Company believes that its Board as a whole should encompass a range of talent, skill, diversity, experience and expertise enabling it to provide sound guidance with respect to the Company’s operations and business goals. In addition to considering a candidate’s background and accomplishments, candidates are reviewed in the context of the current composition of the Board and the evolving needs of the Company. The Company’s policy is to have at least a majority of its directors qualify as “independent” as determined in accordance with the listing standards of The NASDAQ Stock Market and Rule 10A-3 of the Exchange Act. The Nominating and Corporate Governance Committee identifies candidates for election to the Board of Directors; reviews their skills, characteristics and experience; and recommends nominees for director to the Board for approval. The Nominating and Corporate Governance Committee seeks directors with strong reputations and experience in areas relevant to the strategy and operations of the Company, particularly in the oil and gas industry and complex business and financial dealings. Each of the nominees for election as a director at the Annual Meeting of Stockholders and each of the Company’s current directors holds or has held senior executive positions in either the oil and gas industry or in the financial / banking community. In these positions, we believe that each nominee and current director has gained experience in core management skills, such as strategic and financial planning, public company financial reporting, corporate governance, risk management, and leadership development. Many of our directors also have experience serving on boards of directors and board committees of other public companies, as well as charitable organizations and private companies. The Nominating and Corporate Governance Committee also believes that each nominee and current director has other key attributes that are important to an effective board: integrity and demonstrated high ethical standards; sound judgment; analytical skills; the ability to engage management and each other in a constructive and collaborative fashion; diversity of background, experience and thought; and the commitment to devote significant time and energy to service on the Board and its Committees. Meeting Attendance During the fiscal year ended December 31, 2009, the Board of Directors held eight meetings, the Audit Committee held seven meetings, the Compensation Committee held two meetings and the Nominating and Corporate Governance Committee did not meet in 2009. During 2009, each director attended at least 75% of all Board and applicable Committee meetings. During 2009, Abraxas’ directors, other than Mr. Watson, received compensation for service to Abraxas as a director. See “Executive Compensation—Compensation of Directors.” The directors also received reimbursement of travel expenses to attend meetings of the Board of Directors. Abraxas encourages, but does not require, directors to attend the annual meeting of stockholders. Such attendance allows for direct interaction between stockholders and members of the Board of Directors. At Abraxas’ 2009 Annual Meeting, all members of the Board were present. Committees of the Board of Directors Abraxas has standing Audit, Compensation and Nominating and Corporate Governance Committees. The Audit Committee is a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The Audit Committee consists of Messrs. Bartlett, Burke, Melton and Powell. The 8 P r o x y S t a t e m e n t Board of Directors has determined that C. Scott Bartlett, Jr., as defined by SEC rules, is an audit committee financial expert. The Audit Committee Report, which begins on page 41, more fully describes the activities and responsibilities of the Audit Committee. At each meeting which is attended by Mr. Williford and BDO Seidman, LLP, the Audit Committee also meets in executive session. The Compensation Committee consists of Messrs. Cox, Carter and Logue. The Compensation Committee’s role is to establish and oversee Abraxas’ compensation and benefit plans and policies, administer its stock option plans, and to annually review and approve all compensation decisions relating to Abraxas’ executive officers. The Compensation Discussion & Analysis, which begins on page 16, more fully describes the activities and responsibilities of the Compensation Committee. The Compensation Committee submits its decisions regarding executive compensation to the independent members of the Board for approval. The agenda for meetings of the Compensation Committee is determined by its Chairman, Mr. Cox, and the meetings are regularly attended by Mr. Watson. At each meeting, the Compensation Committee also meets in executive session. Mr. Cox reports the committee’s recommendations on executive compensation to the Board. The Company’s personnel support the Compensation Committee in its duties and, along with Mr. Watson, may be delegated authority to fulfill certain administrative duties regarding the Company’s compensation programs. The Compensation Committee has authority under its charter to retain, approve fees for and terminate advisors, consultants and agents as it deems necessary to assist in the fulfillment of its responsibilities but has not, in the past, utilized the services of a third party consultant to review the policies and procedures with respect to executive compensation. The Compensation Committee may engage a third party to provide such services in the future, as it deems necessary or appropriate at the time in question. For more information on the Compensation Committee’s processes and procedures, please see “Executive Compensation – Compensation Discussion and Analysis – Our Compensation Committee” and – “Elements of Executive Compensation.” The Nominating and Corporate Governance Committee consists of Messrs. Cox, Logue and Powell. The primary function of the Nominating and Corporate Governance Committee is to develop and maintain the corporate governance policies of Abraxas and to assist the Board in identifying, screening and recruiting qualified individuals to become Board members and determining the composition of the Board and its committees, including recommending nominees for annual stockholders meetings or to fill vacancies on the Board. Each of the Board’s committees has a written charter, and copies of the charters are available for review on the Company’s website at www.abraxaspetroleum.com. Director Independence The Board of Directors has determined that each of the following members of the Board of Directors is independent as determined in accordance with the listing standards of The NASDAQ Stock Market and Rule 10A-3 of the Exchange Act: C. Scott Bartlett, Jr., Franklin A. Burke, Harold D. Carter, Ralph F. Cox, Brian L. Melton, Dennis E. Logue, Paul A. Powell, Jr. and Edward P. Russell. All of the members of the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors are independent as determined in accordance with the listing standards of The NASDAQ Stock Market and Rule 10A-3 of the Exchange Act. The Board of Directors conducts an annual self-evaluation on key Board and Committee-related issues, which has proven to be a beneficial tool in the process of continuous improvement in Board functioning and communication. Board Leadership Structure The Board of Directors believes that the Chief Executive Officer is best situated to serve as Chairman because he is the director most familiar with Abraxas’ business and industry, and most capable of effectively identifying strategic priorities and leading the discussion and execution of strategy. The Board believes this provides an efficient and effective leadership model for Abraxas. The Board believes that combining the Chairman and Chief Executive Officer roles fosters clear accountability, effective decision-making and alignment on corporate strategy. To assure effective independent oversight, the Board has adopted a number of governance practices, including: • • • A strong, independent director role; Regular executive sessions of the independent directors; and Annual performance evaluations of the Chairman and Chief Executive Officer by the independent directors. In addition, in 2006, the Board appointed Mr. Cox as lead independent director to provide the Board with additional independent oversight. The Board believes that the combined role of Chairman and Chief Executive Officer is in the best interest of Abraxas stockholders because it provides the appropriate balance between strategic development and independent oversight of management. 9 Risk Management The Board of Directors has an active role, as a whole and also at the committee level, in overseeing management of the Company’s risks. The Board reviews quarterly information regarding the Company’s credit, liquidity and operations, as well as the risks associated with each. The Company’s Compensation Committee is responsible for overseeing the management of risks relating to the Company’s executive compensation plans and arrangements to ensure that the compensation programs do not encourage excessive risk-taking. The Audit Committee oversees management of financial risks. The Nominating and Corporate Governance Committee manages the risks associated with the independence of the Board of Directors and potential conflicts of interest. While each committee is responsible for evaluating specific risks and overseeing the management of such risks, the entire Board of Directors is regularly informed through committee reports about such risks. The Board of Directors, together with the Compensation Committee, the Audit Committee, and the Nominating and Corporate Governance Committee, coordinate with each other to provide company-wide oversight of our management and handling of risk. These committees report regularly to the entire Board of Directors on risk-related matters and provide the Board of Directors with integrated insight about the Company’s management of strategic, credit, interest rate, financial reporting, liquidity, compliance and operational risks. While the Company has not developed a company-wide risk statement, the Board of Directors believes a well-balanced operational risk profile with heavier weighting towards exploitation projects as opposed to exploratory projects together with a relatively conservative approach to managing liquidity, debt levels, and commodity price and interest rate risk contribute to an effective oversight of the Company’s risks. At meetings of the Board of Directors and its committees, directors receive regular updates from management regarding risk management. Outside of formal meetings, the Board, its committees and individual Board members have regular access to the executive officers of Abraxas. Compensation Committee Interlocks and Insider Participation Messrs. Cox, Carter and Logue served on the Compensation Committee during 2009. No member of the Compensation Committee was at any time during 2009 or at any other time an officer or employee of Abraxas, and no member had any relationship with Abraxas requiring disclosure as a related-party transaction in the section “Certain Relationships and Related Transactions” of this proxy statement. Messrs. Cox, Melton and Russell were also directors of Abraxas General Partner, LLC, the general partner of Abraxas Energy Partners, L.P., which we refer to as the Partnership, prior to its merger with and into a wholly-owned subsidiary of Abraxas in October 2009, which we refer to as the Merger. No executive officer of Abraxas has served on the board of directors or compensation committee of any other entity that has or has had one or more executive officers who served as a member of the Board of Directors or the Compensation Committee during 2009. Code of Ethics In April 2004, the Board of Directors unanimously approved Abraxas’ Code of Ethics. This Code is a statement of Abraxas’ high standards for ethical behavior, legal compliance and financial disclosure, and is applicable to all directors, officers, and employees. A copy of the Code of Ethics can be found in its entirety on Abraxas’ website at www.abraxaspetroleum.com. Additionally, should there be any changes to, or waivers from, Abraxas’ Code of Ethics, those changes or waivers will be posted immediately on our website at the address noted above. Stockholder Communications with the Board The Board of Directors has implemented a process by which stockholders may communicate with the Board of Directors. Any stockholder desiring to communicate with the Board of Directors may do so in writing by sending a letter addressed to The Board of Directors, c/o Corporate Secretary. The Corporate Secretary has been instructed by the Board to promptly forward communications so received to the members of the Board of Directors. Nominations The Nominating and Corporate Governance Committee is responsible for determining the slate of director nominees for election by stockholders, which the committee recommends for consideration by the Board. All director nominees are approved by the Board prior to annual proxy material preparation and are required to stand for election by stockholders at the next annual meeting. For positions on the Board created by a director’s leaving the Board prior to the expiration of his current term, whether due to death, resignation, or other inability to serve, Article III of the Company’s Amended and Restated Bylaws provides that a Director elected by the Board to fill a vacancy shall be elected for the unexpired term of his predecessor in office. 10 The Nominating and Corporate Governance Committee does not currently utilize the services of any third party search firm to assist in the identification or evaluation of Board member candidates. The Nominating and Corporate Governance Committee may engage a third party to provide such services in the future, as it deems necessary or appropriate at the time in question. The Nominating and Corporate Governance Committee determines the required selection criteria and qualifications of director nominees based upon the needs of the Company at the time nominees are considered. A candidate must possess the ability to apply good business judgment and must be in a position to properly exercise his duties of loyalty and care. Candidates should also exhibit proven leadership capabilities, high integrity and experience with a high level of responsibility within their chosen fields, and have the ability to quickly understand complex principles of, but not limited to, business and finance. Candidates with potential conflicts of interest or who do not meet independence criteria will be identified and disqualified. The Nominating and Corporate Governance Committee will consider these criteria for nominees identified by the Committee, by stockholders, or through some other source. When current Board members are considered for nomination for re-election, the Nominating and Corporate Governance Committee also takes into consideration their prior Board contributions, performance and meeting attendance records. The Nominating and Corporate Governance Committee does not have a formal policy with regard to the consideration of diversity in identifying director nominees, but the Committee strives to nominate directors with a variety of complementary skills so that, as a group, the Board will possess the appropriate talent, skills, experience and expertise to oversee the Company’s business. As part of this process, the Committee evaluates how a particular candidate would strengthen and increase the diversity of the Board in terms of how that candidate may contribute to the Board’s overall balance of perspectives, backgrounds, knowledge, experience, skill sets and expertise in substantive matters pertaining to the Company’s business. The Nominating and Corporate Governance Committee will consider qualified candidates for possible nomination that are recommended by stockholders. Stockholders wishing to make such a recommendation may do so by sending the required information to the Nominating and Corporate Governance Committee, c/o Corporate Secretary at the address listed above. Any such nomination must comply with the advance notice provisions and provide all of the information required by Abraxas’ Amended and Restated Bylaws. These provisions and required information are summarized under “Stockholder Proposals for 2011 Abraxas Annual Meeting” beginning on page 43 of this document. P r o x y S t a t e m e n t The Nominating and Corporate Governance Committee conducts a process of making a preliminary assessment of each proposed nominee based upon the resume and biographical information, an indication of the individual’s willingness to serve and other background information. This information is evaluated against the criteria set forth above as well as the specific needs of the Company at that time. Based upon a preliminary assessment of the candidate(s), those who appear best suited to meet the needs of the Company may be invited to participate in a series of interviews, which are used for further evaluation. The Nominating and Corporate Governance Committee uses the same process for evaluating all nominees, regardless of the original source of the information. No candidates for director nominations were submitted to the Nominating and Corporate Governance Committee by any stockholder in connection with the 2010 Annual Meeting. 11 SECURITIES HOLDINGS OF PRINCIPAL STOCKHOLDERS, DIRECTORS, NOMINEES AND OFFICERS Based upon information received from the persons concerned, each person known to Abraxas to be the beneficial owner of more than five percent of the outstanding shares of common stock of Abraxas, each director and nominee for director, each of the executive officers and all directors and officers of Abraxas as a group, owned beneficially as of March 31, 2010, the number and percentage of outstanding shares of common stock of Abraxas indicated in the following table. Abraxas’ Board has adopted stock ownership guidelines. Please read “Executive Compensation – Stock Ownership Guidelines.” None of the shares listed below have been pledged as security. Name of Beneficial Owner Number of Shares(1) Percentage (%) Robert L.G. Watson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chris E. Williford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lee T. Billingsley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . William H. Wallace . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stephen T. Wendel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Barbara M. Stuckey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C. Scott Bartlett, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Franklin A. Burke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Harold D. Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ralph F. Cox . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dennis E. Logue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Brian L. Melton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paul A. Powell, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Edward P. Russell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lehman Brothers MLP Opportunity Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Citigroup Global Markets Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Point LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Valley Energy Investment Fund U.S., L.P. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . All Officers and Directors as a Group (14 persons) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,546,222(2) 394,971(3) 330,244(4) 270,100(5) 339,297(6) 189,205(7) 153,340(8) 4,660,438(9) 200,624(10) 434,449(11) 157,449(12) 20,264 191,828(13) 3,264 5,451,426(14) 4,355,350(15) 4,801,054(16) 3,633,231(17) 8,891,695(2) (3)(4)(5)(6) (7)(8)(9)(10)(11) (12)(13) 2.0% * * * * * * 6.1% * * * * * * 7.2% 5.7% 6.3% 4.8% 11.6% Less than 1% * (1) Unless otherwise indicated, all shares are held directly with sole voting and investment power. (2) (3) (4) (5) (6) (7) (8) (9) Includes 283,713 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 1994 Long Term Incentive Plan (the “1994 LTIP”), 152,062 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan (the “2005 Employee Plan”) and 32,868 shares in a retirement account. Does not include a total of 75,880 shares owned by the Robert L.G. Watson, Jr. Trust and the Carey B. Watson Trust, the trustees of which are Mr. Watson’s brothers and the beneficiaries of which are Mr. Watson’s children. Mr. Watson disclaims beneficial ownership of the shares owned by these trusts. Includes 103,000 shares issuable upon exercise of options granted pursuant to the 1994 LTIP, 120,117 shares issuable upon exercise of options granted pursuant to the 2005 Employee Plan and 18,881 shares in a retirement account. Includes 52,000 shares issuable upon exercise of options granted pursuant to the 1994 LTIP, 70,772 shares issuable upon exercise of options granted pursuant to the 2005 Employee Plan and 26,686 shares in a retirement account. Includes 52,000 shares issuable upon exercise of options granted pursuant to the 1994 LTIP, 71,960 shares issuable upon exercise of options granted pursuant to the 2005 Employee Plan and 41,021 shares in a retirement account. Includes 27,000 shares issuable upon exercise of options granted pursuant to the 1994 LTIP, 70,166 shares issuable upon exercise of options granted pursuant to the 2005 Employee Plan and 93,869 shares in a retirement account. Includes 47,594 shares issuable upon exercise of options granted pursuant to the 2005 Employee Plan and 17,094 shares in a retirement account. Includes 52,500 shares issuable upon exercise of options granted pursuant to the Abraxas Petroleum Corporation 2005 Non-Employee Director Long- Term Equity Incentive Plan (the “2005 Directors Plan”) and 26,000 shares in a retirement account. Includes 45,000 shares issuable upon exercise of certain option agreements, 62,500 shares issuable upon exercise of options granted pursuant to the 2005 Directors Plan, 219,930 shares in a retirement account, 2,370,975 shares owned by Venture Securities Corporation Profit Sharing Trust Plan (voluntary), Venture Securities Corporation Profit Sharing Plan Trust (designated) and Venture Securities Corporation Pension Plan Trust over which Mr. Burke has shared discretion to dispose of, direct the disposition of, vote, and direct the voting of such shares for the benefit of the beneficiary of the trust, 16,500 shares in various trust and guardianship accounts, of which Mr. Burke is a trustee or guardian, 24,222 shares in the Pleasantville Church Foundation, of which Mr. Burke is a director, and 1,591,192 shares managed by BLB&B Advisors, LLC, of which Mr. Burke is the sole owner, on behalf of third parties. Mr. Burke does not have any voting rights with regard to the shares managed by BLB&B Advisors, LLC. (10) Includes 45,000 shares issuable upon exercise of certain option agreements, 62,500 shares issuable upon exercise of options granted pursuant to the 2005 Directors Plan, 7,577 shares in a family partnership and 40,598 shares in a retirement account. (11) Includes 62,500 shares issuable upon exercise of options granted pursuant to the 2005 Directors Plan. (12) Includes 68,000 shares issuable upon exercise of certain option agreements and 62,500 shares issuable upon exercise of options granted pursuant to the 2005 Directors Plan. 12 (13) Includes 45,000 shares issuable upon exercise of certain option agreements, 62,500 shares issuable upon exercise of options granted pursuant to the 2005 Directors Plan and 27,277 shares in various entities managed by Mr. Powell. (14) The Board of Directors of Lehman Brothers Holding Inc., whose members may change from time to time, has voting and investment control over the shares held by Lehman Brothers MLP Opportunity Fund L.P. The members of the Board of Directors of Lehman Brothers Holdings Inc. disclaim beneficial ownership of all of such units. The address of Lehman Brothers MLP Opportunity Fund L.P. is 1271 Avenue of the Americas, New York, NY 10020. Lehman Brothers MLP Opportunity Fund L.P.’s general partner is an indirect wholly-owned subsidiary of Lehman Brothers Holdings Inc., a public reporting company. (15) Sean Shi, in his capacity as its authorized employee, has voting and investment control over the shares held by Citigroup Global Markets Inc. Mr. Shi disclaims beneficial ownership of all of such shares. The address of Citigroup Global Markets Inc. is 390 Greenwich Street, 3rd Floor, New York, NY 10013. Citigroup Global Markets Inc. is a member of FINRA and a broker-dealer registered pursuant to Section 15(b) of the Exchange Act. Citigroup Global Markets Inc. (i) purchased the securities for its own account, not as a nominee or agent, in the ordinary course of business and with no intention of selling or otherwise distributing the securities in any transaction in violation of securities laws and not as compensation for investment banking services, and (ii) at the time of purchase, Citigroup Global Markets Inc. did not have any agreement or understanding, direct or indirect, with any other person to sell or otherwise distribute the shares purchased. (16) Third Point LLC, and Daniel S. Loeb, in his capacity as the CEO of Third Point LLC, have voting and investment control over the shares held by Third Point Partners LP and Third Point Partners Qualified LP. Third Point LLC is the investment advisor for Third Point Partners LP and Third Point Partners Qualified LP. The address of Third Point LLC is 390 Park Avenue, 18th Floor, New York, NY 10022. (17) An investment committee composed of employees of Merrill Lynch & Co., a member of the FINRA, or its affiliates, whose members may change from time to time, has voting and investment control over the shares held by Valley Energy Investment Fund U.S., L.P. The address of Valley Energy Investment Fund U.S., L.P. is c/o Merrill Lynch Commodity Partners, 20 East Greenway Plaza Suite 950, Houston, TX 77046. Equity Compensation Plan Information The following table gives aggregate information regarding grants under all of Abraxas’ equity compensation plans through December 31, 2009. Plan Category Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b) Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c) Equity compensation plans approved by security holders . . . . . . . . . . . . . . . . . . . . . . 3,992,961 Equity compensation plans not approved by security holders . . . . . . . . . . . . . . . . . . . . . . 422,252 $2.25 $1.29 2,006,011 — Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires Abraxas’ directors and executive officers and persons who own more than 10% of a registered class of Abraxas equity securities to file with the Securities and Exchange Commission and The NASDAQ Stock Market initial reports of ownership and reports of changes in ownership of Abraxas common stock. Officers, directors and greater than 10% stockholders are required by SEC regulation to furnish us with copies of all such forms they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, Abraxas believes that during 2009, all of its directors and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act. P r o x y S t a t e m e n t 13 EXECUTIVE COMPENSATION Compensation Discussion & Analysis We compensate our executive officers through a combination of base salary, annual incentive bonuses and long-term equity based awards. The compensation is designed to be competitive with those of a peer group which we have selected for comparative purposes and to align the interests of our executive officers with the interests of our stockholders. This section discusses the principles underlying our executive compensation policies and decisions, and the most important factors relevant to an analysis of these policies and decisions. It provides qualitative information regarding the manner and context in which compensation is awarded to and earned by our executive officers and places in perspective the data presented in the tables and narrative that follow. Our Compensation Committee Our Compensation Committee approves, implements and monitors all compensation and awards to executive officers including the chief executive officer, chief financial officer and the other executive officers named in the Summary Compensation Table below, whom we refer to as the named executive officers. The Committee’s membership is determined by the Board of Directors and is composed of three independent, non-management directors. The Committee, in its sole discretion, has the authority to delegate any of its responsibilities to subcommittees as it deems appropriate. The Committee did not delegate any of its responsibilities during 2009. The Committee periodically approves and adopts, or makes recommendations to the Board, for Abraxas’ compensation decisions. In the first quarter of each year, Mr. Watson, the Chief Executive Officer, submits to the Compensation Committee his recommendations for salary adjustments and long-term equity incentive awards based upon his subjective evaluation of individual performance and his subjective judgment regarding each executive officer’s salary and equity incentives, for each executive officer except himself. For more information on our Compensation Committee, please refer to the discussion under “Proposal One—Election of Directors—Committees of the Board of Directors.” The Committee reviews all components of compensation for our executive officers, including base salary, annual incentive bonuses, long-term equity based awards, the dollar value to the executive and cost to Abraxas of all benefits and all severance and change of control arrangements. Based on this review, the Compensation Committee has determined that the compensation paid to our executive officers reflects our compensation philosophy and objectives. Compensation Philosophy and Objectives Our underlying philosophy in the development and administration of Abraxas’ annual and long-term compensation plans is to align the interests of our executive officers with those of Abraxas’ stockholders. Key elements of this philosophy are: • • • Establishing compensation plans that deliver base salaries which are competitive with companies in our industry, within Abraxas’ budgetary constraints and commensurate with Abraxas’ salary structure. Rewarding outstanding performance particularly where such performance is reflected by an increase in Abraxas’ Net Asset Value, as adjusted for changes in oil and gas prices. Providing equity-based incentives to ensure motivation over the long-term to respond to Abraxas’ business challenges and opportunities as owners rather than just as employees. The compensation currently paid to Abraxas’ executive officers consists of three core elements: base salary, annual bonuses under a performance-based, non-equity incentive plan and long-term equity based awards granted pursuant to our 2005 Employee Long-Term Equity Incentive Plan, which we refer to as the 2005 Employee Plan, plus other employee benefits generally available to all employees of Abraxas. We believe these elements support our underlying philosophy of aligning the interests of our executive officers with those of Abraxas’ stockholders by providing the executive officers a competitive salary, an opportunity for annual bonuses, and equity-based incentives to ensure motivation over the long-term. We view the three core elements of compensation as related but distinct. Although we review total compensation, we do not believe that significant compensation derived from one component of compensation should increase or reduce compensation from another component. We determine the 14 appropriate level for each component of compensation separately. We have not adopted any formal or informal policies or guidelines for allocating compensation among long-term incentives and annual base salary and bonuses, between cash and non-cash compensation, or among different forms of non-cash compensation; however, we do consider the age, tenure and seniority of each executive officer in making compensation decisions. Abraxas’ Board has adopted stock ownership guidelines. Please read “Stock Ownership Guidelines” for more information. Abraxas does not have any other deferred compensation programs or supplemental executive retirement plans and no benefits are provided to Abraxas’ executive officers that are not otherwise available to all employees of Abraxas, and no benefits are valued in excess of $10,000 per employee per year. Elements of Executive Compensation Executive compensation consists of the following elements: Base Salary. In determining base salaries for the executive officers of Abraxas, we aim to set base salaries at a level we believe enables us to hire and retain individuals in a competitive environment and to reward individual performance and contribution to our overall business goals. In addition, we take into consideration the responsibilities of each named executive officer and determine compensation appropriate for the positions held and expectations of services rendered during the year. We compare the salary structure of Abraxas to a group of exploration and production companies included in the William M. Mercer 2009 Energy Compensation Survey, which we refer to as the Mercer Energy Survey. We use the Mercer Energy Survey as a market check to ensure that we are paying competitive base salaries. Abraxas’ salary range is set by reference to the salaries paid by other companies in our industry considering the responsibilities and expectations of each named executive officer while remaining within Abraxas’ budgetary constraints. We utilize salary information from other companies in our industry to compare Abraxas’ salary structure with those other companies that compete with Abraxas for executives but without targeting salaries to be higher, lower or approximately the same as those in our industry. We believe that the base salary levels for our executive officers are consistent with the practices of companies in our industry and increases in base salary levels from time to time are designed to reflect competitive practices in the industry, individual performance and the officer’s contribution to our overall business goals. Individual performance and contribution to the overall business goals of Abraxas are subjective measures and evaluated by Mr. Watson and the Compensation Committee and, with respect to Mr. Watson, only the Compensation Committee. The base salaries paid to our named executive officers in 2009 are set forth below in the Summary Compensation Table. For 2009, base salaries, paid as cash compensation, were $1,129,000 with Mr. Watson receiving $350,000. We believe that the base salaries paid achieved our objectives. P r o x y S t a t e m e n t 15 Annual Bonuses. Abraxas’ current bonus plan was adopted by our Board of Directors in 2003, and later amended to include all of our executive officers. The purpose of the bonus plan is to create financial incentives for our executive officers that are tied directly to increases in Net Asset Value, or NAV, per share of Abraxas common stock. We chose NAV as the foundation of the bonus plan because we believe that NAV equates to the value of Abraxas’ oil and gas reserve base, giving risked credit for non-proven reserves, and adjusted for other assets and liabilities, including long-term debt. We believe that NAV is a better indicator of the health of Abraxas than its stock price, as the success of finding oil and gas is directly reflected in our NAV, while our stock price can be influenced by a number of factors outside the control of the executive officers of Abraxas. In addition, many exploration and production analysts use NAV per share comparisons to establish price targets for the companies they follow. Under the bonus plan, NAV is calculated at each year-end after receipt of the reserve report from our independent petroleum engineering firm and the audited financials, subject to certain adjustments, as follows: Net Asset Value Calculation: PV-10 Proved Reserves + PV-10 Probable Reserves + Property & Equipment + Acreage + Other Assets ± Net Working Capital – Debt = Net Asset Value (“NAV”) ÷ Shares Outstanding = NAV per share The proved and probable reserves are estimated at year-end in accordance with guidelines published by the Society of Petroleum Engineers, and all other items in the calculation are derived from our year-end audited financials. PV-10 is the estimated present value of the future net revenues from our oil and gas reserves before income taxes, discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. Due to our net loss carry-forwards and the tax basis of our properties, there is no impact of income taxes on our PV-10 calculation. As a result, there is no difference between the standardized measure of our oil and gas reserves, which is a GAAP financial measure, and the PV-10 of our oil and gas reserves. The annual bonuses are calculated by the percentage increase in the current year-end NAV per share over the previous year-end NAV per share up to the first 10%; after 10% has been achieved, all excess percentage increases are doubled, with a maximum award for any one-year of 70% of the executive officer’s base annual salary. For example, if the percentage increase in NAV for a given year was 15%, the calculated bonus would be equal to 20% of the executive officer’s annual base salary. Therefore, in order to compare NAV year-over-year, the current year-end PV-10 for proved and probable reserves are calculated with commodity prices used in the previous year-end PV-10 calculations. Then, for the ensuing year, the PV-10 for proved and probable reserves are calculated with current commodity prices to establish the NAV per share at the beginning of a given year, thus the difference between the calculated NAV per share at the end of a given year and the calculated NAV per share at the beginning of the following year. In the first quarter of each year, the NAV per share for the prior year is calculated after reserves are estimated and audited financial statements are available. Mr. Watson then submits the annual bonus calculation to the Compensation Committee for review and discussion. 16 For example, at the beginning of 2007, the calculated NAV per share was $1.60, utilizing commodity prices as of December 31, 2006 and the calculated NAV per share at the end of 2007 was $3.17, a 98% increase. As a result, on March 11, 2008, the Compensation Committee recommended 2007 annual bonus awards for our executive officers, and the board approved these annual bonus awards at its meeting on March 11, 2008. The following table details the 2007 bonus earned by our named executive officers: Name Base Salary Bonus Award Achieved (Percentage of Salary)(1) Maximum Award (Percentage of Salary) Annual Bonus Awarded Under the Annual Bonus Plan Robert L.G. Watson . . . . . . . . . . . . . . . . . . . . Chris E. Williford . . . . . . . . . . . . . . . . . . . . . . Lee T. Billingsley . . . . . . . . . . . . . . . . . . . . . . William H. Wallace . . . . . . . . . . . . . . . . . . . . Barbara M. Stuckey . . . . . . . . . . . . . . . . . . . . $343,000 209,000 195,000 195,000 140,000 186% 186% 186% 186% 186% 70% 70% 70% 70% 70% $240,100 146,300 136,500 136,500 98,000 (1) 98% increase in NAV: 1% for the first 10%, then 2% for each percent increase (10 + (88 x 2)) = 186% At the beginning of 2008, the calculated NAV per share was $3.61 and the calculated NAV per share at the end of 2008 was $2.96, utilizing commodity prices as of December 31, 2007. At the beginning of 2009, the calculated NAV per share was $1.52 and the calculated NAV per share at the end of 2009 was $0.69, utilizing commodity prices as of December 31, 2008. As a result, no bonuses were earned under this plan in 2008 or 2009. The award opportunities are reflected in the Grants of Plan-Based Awards table in the “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” columns and in the Summary Compensation Table as earned in the “Non-Equity Incentive Plan Compensation” column. The Compensation Committee has the discretion to defer all or any part of any bonus to future years, to pay all or any portion of any bonus, or deferred bonus, in shares of Abraxas common stock and has the discretion to pay bonuses even if no bonus would be payable under the bonus plan, and further has the discretion not to pay bonuses even if a bonus was earned under the bonus plan. In the past, the Committee has elected to pay a portion of the annual bonus in shares of Abraxas common stock and may continue to do so in the future. The Committee reviews the cash position of the Company and the amount of the annual bonus when making such determinations. The Compensation Committee also has the discretion to pay bonuses outside of this plan. P r o x y S t a t e m e n t Long-Term Equity Incentives. Our executive officers are eligible to receive long-term equity incentives under our 2005 Employee Plan. In determining whether to grant long-term incentive awards, such awards will be substantially contingent upon the conclusion of Mr. Watson and the Board of Directors (and only the Board of Directors, with respect to awards to be made to Mr. Watson) as to whether individual and management’s collective efforts have produced attractive long-term returns to Abraxas stockholders by increasing the market price of our common stock over time. In determining whether to grant long- term incentive awards, we anticipate that neither Mr. Watson nor the Board of Directors will have specific numerical targets, but rather will make a subjective determination based upon the state of the oil and gas exploration and production industry and other general economic factors at the time of their evaluation. In the first quarter of each year, Mr. Watson submits his recommendations for long-term equity incentive awards to the Compensation Committee based upon his subjective evaluation of the individual performance of each executive officer, except himself. Mr. Watson also factors in the quantity and value of the long-term incentives that each executive officer has been previously awarded. The Compensation Committee reviews and discusses Mr. Watson’s recommendations and makes final determinations as to such awards. For awards to be made to Mr. Watson, the Compensation Committee subjectively evaluates Mr. Watson’s performance and, in their sole authority, determine, how many, if any, long-term equity incentive awards to grant to Mr. Watson. The Compensation Committee also considers the quantity and value of the long-term equity incentive awards previously granted to Mr. Watson when considering making awards to him. In determining whether to grant long-term equity incentive awards, we seek to ensure that the total compensation package, including cash compensation, is comparable to other companies in our industry, yet such awards are substantially contingent upon the conclusion of Mr. Watson and the Compensation Committee, as to whether individual and management’s collective efforts have produced attractive long-term returns to Abraxas stockholders. We also consider past grants to each executive officer and the level to which such past grants are (or are not) “in-the-money.” Abraxas has historically granted long-term equity incentives after Mr. Watson presents his recommendations to the Compensation Committee in the first quarter; however, we have not granted long-term equity incentives every year and we 17 have awarded long-term equity incentive awards at other times during the year, principally in the event of a new hire, substantial promotion or significant event, such as the completion of a financing transaction or an accretive acquisition. We believe that such events warrant the granting of awards outside the normal course of business as these events are significant to the future success of Abraxas. We do not time award grants in coordination with the release of material non-public information. 2005 Employee Plan. Abraxas’ 2005 Employee Plan, which was approved by our stockholders at the 2006 annual meeting and amended by our stockholders at the 2008 annual meeting and at a special meeting held on October 5, 2009, authorizes us to grant incentive stock options, non-qualified stock options and shares of restricted stock to our executive officers, as well as to all employees of Abraxas. We use equity incentives as a form of long-term compensation because it provides our executive officers an opportunity to acquire an equity interest in Abraxas and further aligns their interest with those of our stockholders. Options grants generally have a term of 10 years and vest in equal increments over four years. Restricted stock grants vest in accordance with each individual grant agreement. Vesting is accelerated in certain events described under “Employment Agreements and Potential Payments Upon Termination or Change in Control.” The purposes of this plan are to employ and retain qualified and competent personnel and to promote the growth and success of Abraxas, which can be accomplished by aligning the long-term interests of the executive officers with those of the stockholders by providing the executive officers an opportunity to acquire an equity interest in Abraxas. All grants are made with an exercise price of no less than 100% of the fair market value on the date of such grant. A total of 5,200,000 shares of Abraxas common stock have been reserved under the 2005 Employee Plan, subject to adjustment following certain events, such as stock splits. The maximum annual award for any one employee is 500,000 shares of Abraxas common stock. If options, as opposed to restricted stock, are awarded, the exercise share price shall be no less than 100% of the fair market value on the date of the award, unless the employee is awarded incentive stock options and at the time of the award, owns more than 10% of the voting power of all classes of stock of Abraxas. Under this circumstance, the exercise share price shall be no less than 110% of the fair market value on the date of the award. Option terms and vesting schedules are at the discretion of the Compensation Committee. On October 5, 2009, outstanding restricted units and phantom units of the Partnership were exchanged for restricted shares of Abraxas common stock and unit options that were to be issued in connection with the initial public offering of the Partnership were exchanged for options of Abraxas common stock as a result of the Merger. In total, 420,552 restricted shares of Abraxas common stock were issued to employees of Abraxas and 1,058,035 options of Abraxas common stock were awarded to employees of Abraxas. Employment Contracts, Change-In-Control Arrangements and Certain Other Matters. We provide the opportunity for our executive officers to be protected under the severance and change in control provisions contained in their employment agreements. We believe that these provisions help us to attract and retain an appropriate caliber of talent for these positions. Our severance and change in control provisions for the executive officers are summarized in “Employment Agreements and Potential Payments Upon Termination or Change in Control” below. We believe that our severance and change in control provisions are consistent with the programs and levels of severance and post employment compensation of other companies in our industry and believe that these arrangements are reasonable. Other Employee Benefits. Abraxas’ executive officers are eligible to participate in all of our employee benefit plans, such as medical, dental, group life and long-term disability insurance, in each case on the same basis as other employees. In addition to employee group life insurance, Abraxas has a key-man life insurance policy on Mr. Watson. Abraxas’ executive officers are also eligible to participate in our 401(k) plan on the same basis as other employees. Abraxas’ Board of Directors, at its sole discretion, may authorize Abraxas to match (in part or in whole) the contributions of each employee to the 401(k) plan during a given year; Abraxas contributions may be in the form of cash, shares of common stock or a combination thereof. In addition, Abraxas’ Board of Directors has suggested a cap on the amount (or percentage) of Abraxas common stock that each employee should own in their individual 401(k) account to encourage diversification. The maximum suggested percentage has been set at 20% and each employee is encouraged to reduce their ownership of Abraxas common stock in their 401(k) account in the event such employee is over the suggested limit. 2010 Compensation Decisions Base Salaries. In general, base salaries for 2010 increased approximately 4% from 2009 for our named executive officers to adjust for cost of living increases over the past two years. Ms. Stuckey received an 18% increase in base salary for 2010 to reflect additional responsibilities. We believe this reflects current practices in the industry. 18 P r o x y S t a t e m e n t Annual Bonuses. At the beginning of 2010, the calculated NAV per share was $0.57, utilizing commodity prices based on the average, first day of the month price during the 12-month period preceding December 31, 2009. Long-Term Equity Incentives. On March 16, 2010, Abraxas’ Board of Directors awarded 889,600 options to employees of Abraxas, of which 330,000 were awarded to the named executive officers. Assessment of Compensation Policies and Practices During 2009 and early 2010, the Company and the Compensation Committee conducted an in-depth risk assessment of the Company’s compensation policies and practices in response to current public and regulatory concerns about the link between incentive compensation and excessive risk taking by companies. The Company and the Committee concluded that our compensation program does not motivate imprudent risk taking. In this regard, the Committee believes that: • • • • • The Company’s annual incentive compensation is based on performance metrics that promote a disciplined approach towards the long-term goals of the Company; The Company does not offer significant short-term incentives that might drive high-risk investments at the expense of the long-term value of the Company; The Company’s compensation programs are weighted towards offering long-term incentives that reward sustainable performance, especially when considering the Company’s stock ownership guidelines for executive officers; The Company’s compensation awards are capped at reasonable levels, as determined by a review of the Company’s financial position and prospects, as well as the compensation offered by companies in our industry; and The Board’s high level of involvement in approving material investments and capital expenditures. The Company’s compensation policies and practices were evaluated to ensure that they do not foster risk taking above the level of risk associated with the Company’s business and the Company concluded that it has a balanced pay and performance program and that the risks arising from its compensation policies and practices are not reasonably likely to have a material adverse effect on the Company. Impact of Regulatory Requirements Deductibility of Executive Compensation. In 1993, the federal tax laws were amended to limit the deduction a publicly- held company is allowed for compensation paid to the chief executive officer and to the four most highly compensated executive officers other than the chief executive officer. Generally, amounts paid in excess of $1.0 million to a covered executive, other than performance-based compensation, cannot be deducted. In order to constitute performance-based compensation for purposes of the tax law, stockholders must approve the performance measures. Since Abraxas does not anticipate that the compensation for any executive officer will exceed the $1.0 million threshold in the near term, stockholder approval necessary to maintain the tax deductibility of compensation at or above that level is not being requested. We will reconsider this matter if compensation levels approach this threshold, in light of the tax laws then in effect. We will consider ways to maximize the deductibility of executive compensation, while retaining the discretion necessary to compensate executive officers in a manner commensurate with performance and the competitive environment for executive talent. Non-Qualified Deferred Compensation. On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law, changing the tax rules applicable to non-qualified deferred compensation arrangements. We believe we are in compliance with the statutory provisions which were effective January 1, 2005 and the regulations which became effective on January 1, 2009. Accounting for Stock-Based Compensation. Beginning on October 1, 2005, we began accounting for stock-based compensation in accordance with the requirements of FASB ASC Topic 718 for all of our stock-based compensation plans. See note 6 of the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission on March 17, 2010 for a discussion of all assumptions made in the calculation of this amount. Policy on Recovery of Compensation. Our CEO and CFO are required to repay certain bonuses and stock-based compensation they receive if we are required to restate our financial statements as a result of misconduct as required by Section 304 of the Sarbanes-Oxley Act of 2002. 19 COMPENSATION COMMITTEE REPORT The Compensation Committee of Abraxas has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Proxy Statement. This report is submitted by the members of the Compensation Committee. Ralph F. Cox, Chairman Harold D. Carter Dennis E. Logue 20 SUMMARY COMPENSATION TABLE The following table sets forth a summary of compensation paid to each of its named executive officers for the last three fiscal years. Name and Principal Position Year Salary ($)(1) Bonus ($)(2) Stock Awards ($)(3) Option Awards ($)(4) Non-Equity Incentive Plan Compensation ($)(5) All Other Compensation ($)(6) Total ($)(7) Robert L.G. Watson . . . . . . . . . . . . . . . . . . . . . 2009 350,000 13,462 105,824 429,048 President, Chief Executive Officer and Chairman of the Board 2008 348,250 13,462 2007 339,750 13,192 8,638 — 49,950 91,324 Chris E. Williford . . . . . . . . . . . . . . . . . . . . . . . 2009 214,000 2008 212,750 2007 207,000 Executive Vice President, Chief Financial Officer and Treasurer Lee T. Billingsley . . . . . . . . . . . . . . . . . . . . . . . 2009 199,000 2008 198,000 2007 193,250 Vice President—Exploration William H. Wallace . . . . . . . . . . . . . . . . . . . . . 2009 199,000 2008 198,000 2007 193,250 Vice President—Operations 8,231 8,231 8,038 7,654 7,654 7,500 7,654 7,654 7,500 52,692 120,549 3,162 — 18,281 33,422 52,839 120,549 3,434 — 19,850 36,296 52,839 120,549 12,450 — 72,000 41,511 — — 240,100 — — 146,300 — — 136,500 — — 136,500 12,250 10,250 10,250 7,490 7,245 7,245 6,965 10,250 10,250 6,965 10,250 10,250 910,584 380,600 744,566 402,962 231,388 420,286 387,007 219,338 403,646 387,007 228,354 461,011 Barbara M. Stuckey . . . . . . . . . . . . . . . . . . . . . 2009 167,000 6,731 80,344 262,408 — 5,845 522,328 Vice President—Corporate Finance (1) The amounts in this column include any 401(k) plan account contributions made by the named executive officer. (2) The amounts in this column reflect a discretionary holiday bonus. (3) The amounts in this column reflect the aggregate grant date fair value of stock awards granted during a given year to the named executive officer calculated in accordance with FASB ASC Topic 718. See note 6 of the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission on March 17, 2010 for a discussion of all assumptions made in the calculation of this amount. Amounts for the years ended December 31, 2007 and 2008 have been recomputed to facilitate year-to-year comparisons. (4) The amounts in this column reflect the aggregate grant date fair value of options granted during a given year to the named executive officer calculated in accordance with FASB ASC Topic 718. See note 6 of the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission on March 16, 2010 for a discussion of all assumptions made in the calculation of this amount. Amounts for the years ended December 31, 2007 and 2008 have been recomputed to facilitate year-to-year comparisons. (5) The amounts in this column represent cash bonuses earned under the annual bonus plan. (6) The amounts in this column represent contributions by Abraxas to the named executive officers 401(k) plan account. (7) The dollar value in this column for each named executive officer represents the sum of all compensation reflected in the previous columns. P r o x y S t a t e m e n t 21 GRANTS OF PLAN-BASED AWARDS The following table provides information with regard to grants of non-equity incentive compensation and all other stock awards to our named executive officers. Name Estimated Future Payouts Under Non-Equity Incentive Plan Awards Grant Date Threshold ($) Target ($) Maximum ($) All Other Stock Awards: Number of Shares of Stock (#) All Other Option Awards: Number of Securities Underlying Options (#) Exercise or Base Price of Option Awards ($/share) Grant Date Fair Value of Stock and Option Awards ($)(6) Robert L.G. Watson . . . . . . . . . . . . . . . . n/a(1) — 240,100 245,000 03/17/2009(2) 09/15/2009(3) 10/05/2009(4) 10/05/2009(5) Chris E. Williford . . . . . . . . . . . . . . . . . . n/a(1) — 146,300 149,800 03/17/2009(2) 09/15/2009(3) 10/05/2009(4) 10/05/2009(5) Lee T. Billingsley . . . . . . . . . . . . . . . . . . n/a(1) — 136,500 139,300 03/17/2009(2) 09/15/2009(3) 10/05/2009(4) 10/05/2009(5) William H. Wallace . . . . . . . . . . . . . . . . n/a(1) — 136,500 139,300 03/17/2009(2) 09/15/2009(3) 10/05/2009(4) 10/05/2009(5) Barbara M. Stuckey . . . . . . . . . . . . . . . . n/a(1) — 98,000 122,500 03/17/2009(2) 09/15/2009(3) 10/05/2009(4) 10/05/2009(5) 3,696 57,345 1,582 28,772 1,681 28,772 1,681 28,772 1,109 44,973 125,000 0.99 267,750 1.75 88,588 5,470 340,460 100,354 50,000 0.99 66,937 1.75 50,000 0.99 66,937 1.75 50,000 0.99 66,937 1.75 35,435 2,341 85,114 50,351 35,435 2,488 85,114 50,351 35,435 2,488 85,114 50,351 50,000 0.99 178,500 1.75 35,435 1,641 226,973 78,703 (1) Awards potentially payable under our annual bonus plan. The annual bonus plan does not provide for a threshold level as the bonuses under the plan can range from 0 to the maximum, which equals 70% of each named executive officers base salary. The target amount was not determinable on the date of grant; therefore, the amount set forth in the target column reflects the amount each named executive officer earned under the plan in 2007, which was the most recent year in which bonuses under this plan were earned, as a representative amount. Please see the discussion under “Compensation Discussion and Analysis—Elements of Executive Compensation—Annual Bonuses” for more information. During 2007, our named executive officers earned an aggregate of $757,400 in bonuses under the annual bonus plan. Please refer to column 5 of the Summary Compensation Table. (2) The closing price of Abraxas’ common stock on the grant date was $0.99. (3) Restricted shares of Abraxas common stock issued on September 15, 2009 under the 2005 Employee Plan. (4) Options of Abraxas common stock issued on October 5, 2009 from to-be-issued unit options of the Partnership as a result of the Merger. The closing price of Abraxas’ common stock on the grant date was $1.75. (5) Restricted shares of Abraxas common stock issued on October 5, 2009 from previously issued restricted units of the Partnership as a result of the Merger. (6) The amounts in this column reflect the aggregate grant date fair value of stock awards and options granted in 2009 to the named executive officer calculated in accordance with FASB ASC Topic 718. See note 6 of the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission on March 17, 2010 for a discussion of all assumptions made in the calculation of this amount. 22 P r o x y S t a t e m e n t OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END The table below contains information concerning outstanding equity awards at December 31, 2009 for our named executive officers. Name Robert L.G. Watson . . . . . . . . . . . . . . . Chris E. Williford . . . . . . . . . . . . . . . . . Lee T. Billingsley . . . . . . . . . . . . . . . . . William H. Wallace . . . . . . . . . . . . . . . . Barbara M. Stuckey . . . . . . . . . . . . . . . . OPTION AWARDS STOCK AWARDS Number of Securities Underlying Unexercised Options (Exercisable) Number of Securities Underlying Unexercised Options (Unexercisable)(1) Option Exercise Price ($) Option Expiration Date Number of Shares of Stock That Have Not Vested(3) Market Value of Shares of Stock That Have Not Vested ($)(4) 60,000 60,000 30,000 30,000 6,856 6,857 90,000 100,000 20,812 40,000 20,000 43,000 100,000 7,617 15,000 22,000 15,000 50,000 8,272 15,000 22,000 15,000 50,000 9,460 25,000 5,000 5,094 20,812 125,000 267,750 7,616 50,000 66,937 8,271 50,000 66,937 9,460 50,000 66,937 5,094 50,000 178,500 0.66(2) 1.38(2) 0.66(2) 4.83(2) 0.66(2) 2.21(2) 0.65 4.59 3.60 0.99 1.75 0.66(2) 0.66(2) 0.65 4.59 3.60 0.99 1.75 0.66(2) 0.65 0.68 4.59 3.60 0.99 1.75 0.66(2) 0.65 0.68 4.59 3.60 0.99 1.75 4.59 6.05 3.60 0.99 1.75 05/26/2010 05/26/2010 03/23/2011 03/23/2011 09/17/2011 09/17/2011 11/22/2012 09/13/2015 08/28/2017 03/17/2019 10/05/2019 05/26/2010 03/23/2011 11/22/2012 09/13/2015 08/28/2017 03/17/2019 10/05/2019 03/23/2011 11/22/2012 04/24/2013 09/13/2015 08/28/2017 03/17/2019 10/05/2019 03/23/2011 11/22/2012 04/24/2013 09/13/2015 08/28/2017 03/17/2019 10/05/2019 09/13/2015 02/24/2016 08/28/2017 03/17/2019 10/05/2019 54,457 104,557 25,457 48,877 25,883 49,695 36,748 70,556 35,054 67,304 (1) Options vest in twenty-five percent (25%) increments each year for four (4) years on the anniversary of the grant date. (2) On December 6, 2002, the Board of Directors approved a plan pursuant to which the price of each outstanding stock option granted to employees of Abraxas with an exercise price greater than $0.66 per share was reduced to $0.66 per share. However, only one-half of Mr. Watson’s options were 23 re-priced at $0.66. The re-pricing was approved in connection with Abraxas’ financial restructuring which was consummated in January 2003. As part of the negotiations that Abraxas had undertaken with the beneficial holder of the largest block of Abraxas’ then outstanding second lien notes, the holder conditioned its participation in the exchange offer for the second lien notes on the re-pricing. Because the Board believed that the financial restructuring, including the exchange offer, represented the best alternative available to Abraxas to reduce its long term indebtedness and to increase its liquidity, the Board approved the re-pricing. The effectiveness of the re-pricing was conditioned upon the consummation of the financial restructuring which occurred on January 23, 2003. In general, stock awards vest in twenty-five percent (25%) increments each year for four (4) years on the anniversary of the grant date. As each increment vests, a new award equal to the most recently vested portion is granted and vests on the 4th anniversary after the grant date. (3) (4) The market value was calculated from the closing price of Abraxas’ common stock on December 31, 2009 of $1.92 per share multiplied by the number of shares of stock that had not vested as of December 31, 2009. OPTION EXERCISES AND STOCK VESTED The table below contains information concerning exercises of stock options and other stock awards by our named executive officers during the fiscal year ended December 31, 2009. Name OPTION AWARDS Number of Shares Acquired on Exercise Value Realized on Exercise ($) Robert L.G. Watson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chris E. Williford . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lee T. Billingsley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . William H. Wallace . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Barbara M. Stuckey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 30,000 30,000(1) — — — 7,800(2) 33,000(3) — (1) Of this amount, 11,250 shares were utilized as payment of the exercise price. (2) These options were exercised on July 15, 2009 with an exercise price of $0.66 and the closing price of Abraxas’ common stock on even date was $0.92, for a realized value of $0.26 per share. (3) These options were exercised on November 16, 2009 with an exercise price of $0.66 and the closing price of Abraxas’ common stock on even date was $1.76, for a realized value of $1.10 per share. Pension Benefits Abraxas does not sponsor any pension benefit plans and none of the named executive officer’s contribute to such a plan. Non-Qualified Deferred Compensation Abraxas does not sponsor any non-qualified defined compensation plans or other non-qualified deferred compensation plans and none of the named executive officer’s contributes to any such plans. Stock Ownership Guidelines Abraxas’ Board has established stock ownership guidelines to strengthen the alignment of director and executive officer interests with those of stockholders. As of December 31, 2009, we had eight non-employee directors and six executive officers subject to stock ownership guidelines. Under the guidelines below, each director and officer is precluded from selling any shares of Abraxas common stock until the director or officer satisfies the ownership guidelines set forth in the following table. The stock ownership guidelines may be satisfied by owning shares of Abraxas common stock. Satisfaction of the ownership guidelines will fluctuate with the market value of the shares of Abraxas common stock. Position Chief Executive Officer All other Executive Officers Non-employee Directors Stock Ownership Guidelines 5x annual base salary 3x annual base salary 3x all fees received during the prior 12-month period, including the value of common shares awarded in lieu of cash payments at the time of issuance Abraxas’ Board has discretion to review special situations; however, non-compliance without board approval can result in the loss of future bonuses and discretionary stock-based compensation. As of December 31, 2009, the market value of 24 P r o x y S t a t e m e n t Abraxas common stock was $1.92 per share. As an example, Mr. Watson, our chief executive officer, is required to own 911,458 common shares of Abraxas to meet the stock ownership guidelines at this price. As of December 31, 2009, one officer and five directors had satisfied the minimum stock ownership guidelines. Employment Agreements and Potential Payments Upon Termination or Change in Control Abraxas has entered into employment agreements with each of our named executive officers pursuant to which each will receive compensation as determined from time to time by the Board in its sole discretion. Abraxas has also established the Abraxas Petroleum Corporation Severance Plan, effective as of December 31, 2008, for all employees that are not subject to an employment agreement. This plan provides severance benefits in the event of a change of control and for certain other changes in conditions of employment. The affected employees would be entitled to receive one month of base salary for each year of service with Abraxas, up to a maximum of 12 months. The employment agreements for Messrs. Watson and Williford are scheduled to terminate on December 21, 2010, and are automatically extended for additional one-year terms unless Abraxas gives 120 days notice of its intention not to renew the employment agreement. The employment agreements for Mr. Wallace, Dr. Billingsley and Ms. Stuckey are scheduled to terminate on December 31, 2010, and are automatically extended for an additional year if by December 1 neither Abraxas nor Mr. Wallace, Dr. Billingsley or Ms. Stuckey, as the case may be, has given notice to the contrary. The employment agreements contain the following defined terms: “Cause” means termination upon (i) the continued failure by the officer to substantially perform his duties with Abraxas (other than any such failure resulting from his incapacity due to physical or mental illness or any such actual or anticipated failure resulting from termination by him for Good Reason) after a written demand for substantial performance is delivered to the officer by the Board, which demand specifically identifies the manner in which the Board believes that he has not substantially performed his duties, or (ii) the engaging by the officer in conduct which is demonstrably and materially injurious to the Company, monetarily or otherwise. The officer shall not be deemed to have been terminated for Cause unless and until the officer has been delivered a copy of a resolution duly adopted by the affirmative vote (which cannot be delegated) of not less than a majority of the members of the Board who are not officers of the Company at a meeting of the Board called and held for such purposes (after reasonable notice to the officer and an opportunity for the officer, together with the officer’s counsel, to be heard before the Board), finding that in the good faith opinion of the Board, the officer was guilty of conduct set forth above in clauses (i) or (ii) above and specifying the particulars thereof in detail. “Change in Control” means the occurrence of (i) any “person” or “group” (as such terms are used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”)) becoming the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), except that a person shall be deemed to be the “beneficial owner” of all shares that any such person has the right to acquire pursuant to any agreement or arrangement or upon exercise of conversion rights, warrants, options or otherwise, without regard to the sixty day period referred to in such Rule), directly or indirectly, of securities representing 20% or more of the combined voting power of the Company’s then outstanding securities, (ii) any person or group making a tender offer or an exchange offer for 20% or more of the combined voting power of the Company’s then outstanding securities, (iii) at any time during any period of two consecutive years, individuals who at the beginning of such period constituted the Board and any new directors, whose election by the Board or nomination for election by the Company’s stockholders was approved by a vote of at least two-thirds (2/3) of the Company directors then still in office who either were the Company directors at the beginning of the period or whose election or nomination for election was previously so approved (“Current Directors”), ceasing for any reason to constitute a majority thereof, (iv) the Company consolidating, merging or exchanging securities with any other entity and the stockholders of the Company immediately before the effective time of such transaction not beneficially owning, immediately after the effective 25 time of such transaction, shares entitling such stockholders to a majority of all votes (without consideration of the rights of any class of stock entitled to elect directors by a separate class vote) to which all stockholders of the corporation issuing cash or securities in the consolidation, merger or share exchange would be entitled for the purpose of electing directors or where the Current Directors immediately after the effective time of the consolidation, merger or share exchange not constituting a majority of the Board of Directors of the corporation issuing cash or securities in the consolidation, merger or share exchange, or (v) any person or group acquiring 50% or more of the Company’s assets. “Disability” means the incapacity of the officer due to physical or mental illness which causes the officer to have been absent from the full-time performance of his duties with the Company for six consecutive months, and within 30 days after the Company gives the officer written notice of termination, the officer has not returned to the full-time performance of his duties. “Good Reason” means, without the officer’s express written consent, any of the following: (i) a material adverse alteration in the nature or status of his position, duties or responsibilities, (ii) a reduction in his current annual base salary, (iii) a change in the principal place of his employment to a location more than twenty-five (25) miles from the Company’s current principal place of employment, excluding required travel on the Company’s business to an extent substantially consistent with the officer’s present business travel obligations, (iv) the failure by the Company, without his consent, to pay to him any portion of his current compensation, or to pay to him any portion of any deferred compensation, within ten (10) days of the date any such compensation payment is due, (v) the failure by the Company to continue in effect any compensation plan in which he participates, or any substitute plans or the failure by the Company to continue his participation therein on the same basis, both in terms of the amount of benefits provided and the level of his participation relative to other participants, as existing, (vi) the failure by the Company to continue to provide him with benefits at least as favorable to those enjoyed by him under any of the Company’s pension, life insurance, medical, health and accident, disability, deferred compensation or savings plans in which he is currently participating, the taking of any action by the Company which would directly or indirectly materially reduce any of such benefits or deprive the officer of any material fringe benefit enjoyed by him, or the failure by the Company to provide him with the number of paid vacation days to which he is entitled on the basis of the Company’s practice with respect to him, (vii) the failure of the Company to obtain a satisfactory agreement from any successor to assume and agree to perform his employment agreement, or (viii) any purported termination of his employment which is not effected pursuant to the employment agreement’s termination provisions. “Retirement” means termination in accordance with the Company’s retirement policy, generally applicable to its salaried employees or in accordance with any retirement arrangement established with the officer’s consent with respect to himself. If, during the term of the employment agreement for each named executive officer or any extension thereof, an officer’s employment is terminated other than for Cause or Disability, by reason of the officer’s death or Retirement, or by such officer for Good Reason, then such officer will be entitled to receive the following: Watson and Williford: a lump sum payment equal to the greater of (a) his annual base salary for the last full year during which he was employed by Abraxas or (b) his annual base salary for the remainder of the term of his employment agreement. 26 Wallace, Billingsley and Stuckey: no provisions for termination of employment because at all times during the term of each officer’s employment agreements, such officer’s employment is at will and may be terminated by Abraxas for any reason with notice or cause. If, during the term of the employment agreement for each of Mr. Wallace, Dr. Billingsley or Ms. Stuckey or any extension thereof, a change in control occurs, then such officer will be entitled to an automatic extension of the term of the officer’s employment agreement for a period of 36 months beyond the term in effect immediately before the change in control. If, following a change in control, an officer’s employment is terminated other than for Cause or Disability, by reason of the officer’s death or Retirement or by such officer for Good Reason, then such terminated officer will be entitled to the following: Watson and Williford: a lump sum payment equal to 2.99 times his annual base salary. Wallace, Billingsley and Stuckey: a lump sum payment equal to three times his or her annual base salary. If any lump sum payment to a named executive officer would individually or together with any other amounts paid or payable constitute an “excess parachute payment” within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended, and applicable regulations thereunder, the amounts to be paid will be increased so that each named executive officer, as the case may be, will be entitled to receive the amount of compensation provided in his contract after payment of the tax imposed by Section 280G. In addition, unvested options that have been awarded to our named executive officers will vest upon any change in control. As of December 31, 2009, 1,353,314 options were unvested, 972,061 of which were “in-the-money” as of December 31, 2009. The table below contains information concerning termination and change in control payments to each of our named executive officers as if the event occurred on December 31, 2009. P r o x y S t a t e m e n t Termination and Change in Control Payments Table Name Type of Benefit Before Change in Control Termination w/o Cause or for Good Reason ($)(1) After Change in Control Termination w/o Cause or for Good Reason ($)(2) Voluntary Termination ($) Death / Disability ($) Change in Control ($)(3) Robert L.G. Watson . . . . . . . . . . . . . . . Severance pay 350,000 1,046,500 Option acceleration Chris E. Williford . . . . . . . . . . . . . . . . . Severance pay 214,000 639,860 Option acceleration Lee T. Billingsley . . . . . . . . . . . . . . . . . Severance pay Option acceleration William H. Wallace . . . . . . . . . . . . . . . . Severance pay Option acceleration Barbara M. Stuckey . . . . . . . . . . . . . . . . Severance pay — — — 597,000 597,000 525,000 — — — — — Option acceleration — — — — — 350,000 161,768 214,000 57,879 597,000 57,879 597,000 57,879 525,000 76,845 (1) These amounts reflect a lump sum payment equal to the officer’s annual base salary as of December 31, 2009. (2) These amounts reflect a lump sum payment equal to 2.99x (Watson and Williford) and 3.0x (Wallace, Billingsley and Stuckey) the named executive officer’s annual base salary as of December 31, 2009. (3) These amounts on the severance pay row reflect a 12-month extension (Watson and Williford) and a 36-month extension (Wallace, Billinglsey and Stuckey) of each officer’s respective employment agreement based on the named executive officer’s annual base salary on December 31, 2009 and would be paid over the extension period. The amounts on the option acceleration row reflect 972,061 “in-the-money” options at a potential value of $0.43 per share (the difference between the fair market value on December 31, 2009 and the exercise price of the options). Compensation of Directors All compensation paid to directors is limited to non-employee directors. We use a combination of cash and stock-based incentive compensation to attract and retain qualified individuals to serve on the Board. 27 Compensation. Abraxas currently pays each director an annual retainer fee of $26,000 in four quarterly cash payments. Prior to April 2010, the annual retainer fee was $20,000, $12,000 of which was paid in shares of Abraxas common stock and the remaining $8,000 was paid in cash. The number of shares issued to each non-employee director was calculated each quarter by dividing $3,000 by the closing price of our common stock on the date of each quarterly board meeting. Fractional shares were not issued; therefore, any shortfall was paid in cash after the last quarterly board meeting of each year. In addition, Abraxas currently pays each director $1,500 for each board meeting attended and $1,000 for each committee meeting attended. The chairman of the audit committee receives an additional annual fee of $10,000, the chairman of the compensation committee receives an additional annual fee of $5,000 and the chairman of the governance and nominating committee receive an additional annual fee of $1,500. Stock Options. Abraxas has awarded each director stock options, depending on each director’s length of service, with exercise prices equal to the prevailing market prices at the time of issuance, ranging from $0.68 to $4.59 per share. In addition, each year at the first regular board meeting following the annual meeting, Abraxas awards each director 10,000 options, in accordance with the terms of the 2005 Directors Plan. The amended 2005 Directors Plan, which is subject to stockholder approval at the 2010 Annual Meeting of Stockholders, reserves 1,500,000 shares of Abraxas common stock, subject to adjustment following certain events, such as stock splits. The maximum annual award for any one director is 100,000 shares. The exercise price of all options awarded is no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the Compensation Committee. A description of the material terms of the 2005 Directors Plan is included in “Proposal Two—Amendment of the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan.” The following table sets forth a summary of compensation for the fiscal year ended December 31, 2009 that Abraxas paid to each director. Abraxas does not sponsor a pension benefits plan, a non-qualified deferred compensation plan or a non-equity incentive plan for our directors; therefore, these columns have been omitted from the following table. Except for reimbursement of travel expenses to attend board and committee meetings, no other or additional compensation for services were paid to any of the directors. Director Compensation Table Name C. Scott Bartlett, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Franklin A. Burke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Harold D. Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ralph F. Cox(5) Dennis E. Logue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Brian L. Melton(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paul A. Powell, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Edward P. Russell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fees Earned or Paid in Cash ($)(1) 33,000 27,000 29,000 30,750 22,500 13,250 34,000 3,500 Retainer Stock Awards ($)(2) 12,000 12,000 12,000 12,000 12,000 3,000 12,000 3,000 Restricted Stock and Option Awards ($)(3) 41,553 41,553 41,553 71,303 41,553 115,827 41,553 86,077 Total ($)(4) 86,553 80,553 82,553 114,053 76,053 132,077 87,553 92,577 (1) This column represents the amounts paid in cash to each director. (2) This column represents the dollar value of stock awarded to each director for his annual retainer fee. During 2009, each director, except Messrs. Melton and Russell, was awarded a total of 9,716 vested shares of Abraxas common stock. The quarterly awards were 3,030 shares on March 17, 2009, 2,830 shares on May 21, 2009, 2,027 shares on September 15, 2009 and 1,829 shares on November 12, 2009 and the closing price of our common stock on those dates was $0.99, $1.06, $1.48 and $1.64 per share, respectively. Messrs. Melton and Russell were awarded 1,829 vested shares of Abraxas common stock on November 12, 2009 and the closing price of our common stock on that date was $1.64. (3) The amounts in this column reflect the aggregate grant date fair value of stock awards and options granted in 2009 to each director calculated in accordance with FASB ASC Topic 718. See note 6 of the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission on March 17, 2010 for a discussion of all assumptions made in the calculation of this amount. (4) The dollar value in this column for each director represents the sum of all compensation reflected in the previous columns. (5) Included in fees earned by Messrs. Cox and Melton are $6,750 and $8,750, respectively, paid in cash for serving as a director on the Partnership board during 2009 and $29,750 for the recognized value of restricted stock awards that were converted from restricted unit awards of the Partnership in the Merger. 28 The table below contains information concerning outstanding option awards at December 31, 2009 for each of the directors. None of the named directors had outstanding stock awards at December 31, 2009. Outstanding Equity Awards at Fiscal-Year End Table Name C. Scott Bartlett, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Franklin A. Burke . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Harold D. Carter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ralph F. Cox . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dennis E. Logue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Brian L. Melton(1) Paul A. Powell, Jr. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Edward P. Russell(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1) Awards to Messrs. Melton and Russell are subject to stockholder approval of the amendment to the 2005 Directors Plan. Option Awards 90,000 145,000 145,000 100,000 168,000 75,000 145,000 75,000 P r o x y S t a t e m e n t 29 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS General On February 21, 2007, our Board of Directors adopted a formal written related person transaction approval policy, which sets out Abraxas’ policies and procedures for the review, approval, or ratification of “related person transactions.” For these purposes, a “related person” is a director, nominee for director, executive officer, or holder of more than 5% of our common stock, or any immediate family member of any of the foregoing. This policy applies to any financial transaction, arrangement or relationship or any series of similar financial transactions, arrangements or relationships in which Abraxas is a participant and in which a related person has a direct or indirect interest, other than the following: • • • • payment of compensation by Abraxas to a related person for the related person’s service in the capacity or capacities that give rise to the person’s status as a “related person;” transactions available to all employees or all stockholders on the same terms; purchases of supplies from Abraxas in the ordinary course of business at the same price and on the same terms as offered to our other customers, regardless of whether the transactions are required to be reported in Abraxas’ filings with the SEC; and transactions which when aggregated with the amount of all other transactions between the related person and Abraxas involve less than $10,000 in a fiscal year. Our Audit Committee is required to approve any related person transaction subject to this policy before commencement of the related person transaction, provided that if the related person transaction is identified after it commences, it shall be brought to the Audit Committee for ratification, amendment or rescission. The chairman of our Audit Committee has the authority to approve or take other actions in respect of any related person transaction that arises, or first becomes known, between meetings of the Audit Committee, provided that any action by the chairman must be reported to our Audit Committee at its next regularly scheduled meeting. Our Audit Committee will analyze the following factors, in addition to any other factors the members of the Audit Committee deem appropriate, in determining whether to approve a related person transaction: • • • • • whether the terms are fair to Abraxas; whether the transaction is material to Abraxas; the role the related person has played in arranging the related person transaction; the structure of the related person transaction; and the interest of all related persons in the related person transaction. Transactions in 2009 Abraxas did not have any related party transactions in 2009. Our Audit Committee may, in its sole discretion, approve or deny any related person transaction. Approval of a related person transaction may be conditioned upon Abraxas and the related person following certain procedures designated by the Audit Committee. 30 PROPOSAL TWO AMENDMENT OF THE ABRAXAS PETROLEUM CORPORATION 2005 NON-EMPLOYEE DIRECTORS LONG-TERM EQUITY INCENTIVE PLAN On June 1, 2005, the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan (the “2005 Directors Plan”) was approved by the stockholders. On March 16, 2010, subject to further stockholder approval, the Abraxas Board of Directors adopted an amendment to the Abraxas Petroleum Corporation 2005 Directors Plan, the full text of which, as amended, is set forth in Appendix A to this Proxy Statement. Proposed Amendment to the 2005 Directors Plan The purpose of the 2005 Directors Plan is to attract and retain members of the Board and promote the growth and success of Abraxas by aligning the long-term interests of Abraxas’ directors with those of Abraxas’ stockholders by providing an opportunity to acquire an interest in Abraxas and by providing both rewards for exceptional performance and long-term incentives for future contributions to the success of Abraxas. We provide equity-based incentives to our directors to ensure motivation over the long-term to respond to Abraxas’ business challenges and opportunities as owners rather than just as directors. When the 2005 Directors Plan was approved by stockholders, 900,000 shares of common stock were reserved for issuance. At December 31, 2009, awards for 781,351 shares had been granted out of the 2005 Directors Plan with awards for 118,649 shares remaining for issuance. The Board of Directors considers availability of shares of common stock for future grants under the 2005 Directors Plan to be important to the business prospects and operations of Abraxas and believes that, after giving effect to the proposed 600,000 share increase to the 2005 Directors Plan, we will have sufficient awards available for grant to our directors for the next three years. The additional shares will allow us to continue to provide long-term incentive awards that will assist us in attracting new non-employee directors as well as retaining key non-employee directors. If new shares are not approved for issuance under the 2005 Directors Plan, we may be required to curtail use of long- term incentives and the Board may consider other alternatives to compensate non-employee directors. P r o x y S t a t e m e n t Summary of the 2005 Directors Plan The following summary of the 2005 Directors Plan, as amended, is qualified in its entirety by reference to Appendix A. The effectiveness of the amendment to the 2005 Directors Plan is subject to approval by Abraxas stockholders. Shares Available. The proposed amendment increases the number of shares of common stock available for issuance under the 2005 Directors Plan to 1,500,000 from 900,000. Administration and Eligibility. The 2005 Directors Plan is administered by the Compensation Committee of the Board of Directors and authorizes the Board to grant non-qualified stock options or issue restricted stock to those persons who are non-employee directors of Abraxas. Shares Reserved and Awards. The 2005 Directors Plan reserves 1,500,000 shares of Abraxas common stock, subject to adjustment following certain events, as discussed below. The maximum annual award for any one director is 100,000 shares of Abraxas common stock. If options, as opposed to restricted stock, are awarded, the exercise share price shall be no less than 100% of the fair market value on the date of the award. Option terms and vesting schedules are at the discretion of the Compensation Committee. Options shall not be re-priced without stockholder approval. Option Exercise. An option is exercised when proper notice of exercise has been given to Abraxas, or the brokerage firm or firms approved by Abraxas, if any, to facilitate exercises and sales under the 2005 Directors Plan and full payment for the shares with respect to which the option is exercised has been received by Abraxas or the brokerage firm or firms, as applicable. The consideration to be paid and the method of payment, shall be determined by the Committee and may include: (i) a cashless exercise, whereby the exercise price is paid to Abraxas from the proceeds of a same-day sale of a portion of the stock underlying the option; (ii) cash; and (iii) tender of shares of common stock owned by the participant. Option shares used to pay the exercise price shall be valued at their fair market value on the exercise date. Payment of the aggregate exercise price by means of tendering previously-owned shares of common stock shall not be permitted when the same may, in the reasonable opinion of Abraxas, cause Abraxas to record a loss or expense as a result thereof. 31 Stockholder Rights. Except as otherwise provided in the 2005 Directors Plan, until the issuance of the share certificates evidencing the award shares, no right to vote or receive dividends or any other rights as a stockholder shall exist with respect to the award shares. Transferability of Awards. An award may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in exchange for consideration, except that an award may be transferred by will or by the laws of descent or distribution and may be exercised, during the lifetime of the participant, only by the participant, unless the Committee permits further transferability, on a general or specific basis, in which case the Committee may impose conditions and limitations on any permitted transferability. Termination of Awards. Unless otherwise provided in the applicable award agreement or any severance agreement, vested awards granted under the 2005 Directors Plan shall expire, terminate, or otherwise be forfeited as follows: • three (3) months after the date the Company delivers a notice of termination of a participant’s active status, other than in circumstances covered by the following three circumstances: • • • immediately upon termination for misconduct; twelve (12) months after the date of the death; and thirty-six (36) months after the date on which the director ceased performing services as a result of retirement. U.S. Federal Tax Consequences. Options. Participants will not recognize taxable income at the time an option is granted under the 2005 Directors Plan unless the option has a readily ascertainable market value at the time of grant. The Board understands that options to be granted under the 2005 Directors Plan will not have a readily ascertainable market value; therefore, income will not be recognized by participants before the time of exercise of an option. Upon exercise of the option, the optionee will recognize ordinary income in an amount equal to the difference between the fair market value of the shares at the time an option is exercised and the option exercise price for such shares, and Abraxas will be entitled to a deduction equal to the amount of the optionee’s ordinary income. Abraxas will satisfy federal income tax withholding requirements upon the exercise of the option. Restricted Stock. A participant who receives a grant of restricted stock and who does not otherwise elect to be taxed at the time of grant will not recognize income upon such grant, and Abraxas will not be entitled to a deduction until the termination of the restrictions on such shares of common stock under the award. Upon the termination of the restrictions on such shares, the participant will recognize ordinary income in an amount equal to the fair market value of the common stock at the time of such termination of restrictions (less any amount paid by the employee for such shares), and Abraxas will be entitled to a deduction in the same amount. However, the participant may elect, under Section 83(b) of the Internal Revenue Code (“Section 83(b)”), to recognize ordinary income in the year in which the restricted stock is granted in an amount equal to the fair market value of the shares at that time, determined without regard to the restrictions. In the event that a participant makes a valid election under Section 83(b), Abraxas will be entitled to a deduction in such year and in the same amount. Whether ordinary income is recognized due to the election of the participant or through the termination of restrictions, Abraxas will satisfy federal income tax withholding requirements upon such event. Any gain or loss recognized by the participant upon subsequent disposition of the stock (i.e. any disposition after a valid Section 83(b) election of the termination of restrictions, as applicable) will be capital in nature. Amendments. Abraxas’ Board or the Committee may amend or terminate the 2005 Directors Plan from time to time in such respects as the Board may deem advisable (including, but not limited, to amendments which the Board deems appropriate to enhance Abraxas’ ability to claim deductions related to stock option exercises); provided, that to the extent required by the Internal Revenue Code of 1986, as amended, or the rules of NASDAQ, such other exchange upon which Abraxas common stock is either quoted or traded, or the SEC, stockholder approval shall be required for any material amendment of the 2005 Directors Plan. Subject to the foregoing, it is specifically intended that the Board or Committee be able to amend the 2005 Directors Plan without stockholder approval to comply with legal, regulatory and listing requirements and to avoid unanticipated consequences deemed by the Committee to be inconsistent with the purpose of the 2005 Directors Plan or any award agreement. Adjustments. If the outstanding shares of Abraxas’ common stock shall be changed into or exchanged for a different number or kind of shares of stock or other securities or property of Abraxas or of another corporation, or if the number of such shares of common stock shall be increased by a stock dividend or stock split, there shall be substituted for or added to 32 each share of common stock reserved for the purposes of the 2005 Directors Plan, whether or not such shares are at the time subject to outstanding awards, the number and kind of shares of stock or other securities or property into which each outstanding share of common stock shall be so changed or for which it shall be so exchanged, or to which each such share shall be entitled, as the case may be. Outstanding awards shall also be considered to be appropriately amended as to price and other terms as may be necessary or appropriate to reflect the foregoing events. If there shall be any other change in the number or kind of the outstanding shares of Abraxas’ common stock, or of any stock or other securities or property into which such common stock shall have been changed, or for which it shall have been exchanged, and if the Committee shall in its sole discretion determine that such change equitably requires an adjustment in the number or kind or price of the shares then reserved for the purposes of the 2005 Directors Plan, or in any award previously granted or which may be granted under the 2005 Directors Plan, then such adjustment shall be made by the Committee and shall be effective and binding for all purposes of the 2005 Directors Plan. In addition, the Committee shall have the power, in the event of any merger or consolidation involving Abraxas to amend all outstanding awards to permit the exercise thereof in whole or in part at anytime, or from time to time, prior to the effective date of any such merger or consolidation and to terminate each such award as of such effective date. Although the benefits and amounts that will be received by the Non-Executive Director Group are not determinable, the benefits and amounts which would have been received by the Non-Executive Direct Group for the last completed fiscal year if the 2005 Directors Plan, as amended, had been in effect are provided in the table below: NEW PLAN BENEFITS Name Dollar Value ($) Number of Shares Non-Executive Director Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-Executive Director Group . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 246,000(1) 150,000 162,400(2) 80,000 230,000 408,400 (1) Calculated by multiplying the number of shares by the closing price for Abraxas common stock on the NASDAQ on November 12, 2009, the date the Board of Directors approved the issuance, subject to stockholder approval of the amended 2005 Directors Plan. Messrs. Melton and Russell were each awarded 75,000 options. (2) Calculated by multiplying the number of shares by the closing price for Abraxas common stock on the NASDAQ on April 6, 2010. Effectiveness. Upon effectiveness, the 2005 Directors Plan shall remain in effect until the tenth anniversary of the effective date or until terminated under the terms of the plan or extended by an amendment approved by Abraxas stockholders. Votes Required. Assuming the presence of a quorum, the proposal to amend the 2005 Non-Employee Directors Long- Term Equity Incentive Plan must receive a majority of the total votes cast. The enclosed form of proxy provides a means for stockholders to vote to approve the amendment to the 2005 Directors Plan, to vote against it or to abstain from voting with respect to it. If a stockholder executes and returns a proxy, but does not specify how the shares represented by such stockholder’s proxy are to be voted, such shares will be voted FOR the approval to amend the 2005 Directors Plan. Abstentions will have the same legal effect as a vote against the proposal. Non-votes are not considered present at the meeting for this proposal and will have no effect on the approval to amend the 2005 Directors Plan. The Board of Directors recommends a vote “FOR” the approval to amend the 2005 Non-Employee Directors Long-Term Equity Incentive Plan. P r o x y S t a t e m e n t 33 RATIFICATION OF SELECTION OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM PROPOSAL THREE The Abraxas Board of Directors has selected BDO Seidman, LLP to serve as its independent registered public accounting firm for the fiscal year ending December 31, 2010. Although stockholder ratification is not required, the Board of Directors has directed that such appointment be submitted to the stockholders of Abraxas for ratification at the annual meeting. BDO Seidman, LLP provided audit services to Abraxas for the year ended December 31, 2009. A representative of BDO Seidman, LLP will be present at the annual meeting, will have an opportunity to make a statement if he or she desires to do so and will be available to respond to appropriate questions. No report of BDO Seidman, LLP on Abraxas’ financial statements for either of Abraxas’ last two fiscal years contained any adverse opinion or disclaimer of opinion, nor was any such report qualified or modified as to uncertainty, audit scope or accounting principles. In connection with the audits of Abraxas’ financial statements for the last two fiscal years, there were no disagreements with BDO Seidman, LLP on any matters of accounting principles, financial statement disclosure or audit scope and procedures which, if not resolved to the satisfaction of BDO Seidman, LLP, would have caused the firm to make reference to the matter in its report. During Abraxas’ last there were no reportable events as described in two fiscal years, Item 304(a)(1)(v) of Regulation S-K. Assuming the presence of a quorum, the affirmative vote of the holders of a majority of the total votes cast is necessary to ratify the appointment of Abraxas’ independent registered public accounting firm. The enclosed proxy card provides a means for stockholders to vote for the ratification of the selection of Abraxas’ independent registered public accounting firm, to vote against it or to abstain from voting with respect to it. If a stockholder executes and returns a proxy, but does not specify how the shares represented by such stockholder’s proxy are to be voted, such shares will be voted FOR the ratification of selection of Abraxas’ independent registered public accounting firm. Abstentions will have the same legal effect as a vote against the proposal. Since this proposal is considered a “routine” matter, brokers will be permitted to vote on behalf of their clients, if no voting instructions are furnished. The Board of Directors recommends a vote “FOR” the ratification of the selection of BDO Seidman, LLP, as Abraxas’ independent registered public accounting firm for the fiscal year ending December 31, 2010. 34 AUDIT COMMITTEE REPORT The Audit Committee represents and assists the Board in fulfilling its responsibilities for general oversight of the integrity of Abraxas’ financial statements, Abraxas’ compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence, the performance of Abraxas’ internal audit function and independent audit firm, and risk assessment and risk management. The Audit Committee manages Abraxas’ relationship with its independent auditors (which report directly to the Audit Committee). The Audit Committee has the authority to obtain advice and assistance from outside legal, accounting or other advisors as the Audit Committee deems necessary to carry out its duties and receives appropriate funding, as determined by the Audit Committee, from Abraxas for such advice and assistance. Abraxas’ management is primarily responsible for Abraxas’ internal control and financial reporting process. Abraxas’ independent auditors, BDO Seidman, LLP, are responsible for performing an independent audit of Abraxas’ consolidated financial statements and issuing opinions on the conformity of those audited financial statements with United States generally accepted accounting principles. The Audit Committee monitors Abraxas’ financial reporting process and reports to the Board on its findings. In this context, the Audit Committee hereby reports as follows: 1. The Audit Committee has reviewed and discussed the audited financial statements with Abraxas’ management. 2. The Audit Committee has discussed with the independent auditors the matters required to be discussed by the Statement on Auditing Standards No. 61, as amended (Codification of Statements on Auditing Standards, AU 380), as adopted by the Public Company Accounting Oversight Board (“PCAOB”) in Rule 3200T. 3. The Audit Committee has received the written disclosures and the letter from the independent auditors required by the PCAOB regarding the independent auditors’ communications with the Audit Committee concerning independence, and has discussed with the independent auditors their independence. 4. Based on the review and discussions referred to in paragraphs (1) through (3) above, the Audit Committee recommended to the Board, and the Board has approved, that the audited financial statements be included in Abraxas’ Annual Report on Form 10-K for the year ended December 31, 2009, and for filing with the Securities and Exchange Commission. P r o x y S t a t e m e n t This report is submitted by the members of the Audit Committee. C. Scott Bartlett, Jr., Chairman Franklin A. Burke Paul A. Powell, Jr. Brian L. Melton 35 PRINCIPAL AUDITOR FEES AND SERVICES Audit Fees. The aggregate fees billed for professional services rendered by BDO Seidman, LLP for the audit of Abraxas’ annual financial statements for the years ended December 31, 2009 and December 31, 2008, for the audit of Abraxas’ internal controls over financial reporting as of December 31, 2008, and the reviews of the condensed financial statements included in Abraxas’ quarterly reports on Form 10-Q for the years ended December 31, 2009 and December 31, 2008, were $433,181 and $622,327, respectively. Audit-Related Fees. The aggregate fees billed by BDO Seidman, LLP for assurance and related services that were reasonably related to the performance of the audit or review of Abraxas’ financial statements and are not reported in “audit fees” above, for the years ended December 31, 2009 and December 31, 2008, were $31,530 and $23,350, respectively. These fees were for services provided by BDO Seidman, LLP related to consulting services associated with technical accounting treatment of various transactions. All Other Fees. The aggregate fees billed for other services, exclusive of the fees disclosed above relating to financial statement audit services, rendered by BDO Seidman, LLP during the years ended December 31, 2009 and December 31, 2008, were $146,070 and $366,453, respectively. These fees were for services provided by BDO Seidman, LLP related to the audit of the Partnership’s annual financial statements for the year ended December 31, 2008, the Partnership’s registration statement and for services related to the Merger transaction and related proxy statements. Consideration of Non-audit Services Provided by the Independent Auditors. The Audit Committee has considered whether the services provided for non-audit services are compatible with maintaining BDO Seidman, LLP’s independence, and has concluded that the independence of such firm has been maintained. AUDIT COMMITTEE PRE-APPROVAL POLICY The Audit Committee’s policy is to pre-approve all audit, audit-related and non-audit services provided by the independent registered public accounting firm. These services may include audit services, audit-related services, tax services and other services. The Audit Committee may also pre-approve particular services on a case-by-case basis. The independent public accountants are required to periodically report to the Audit Committee regarding the extent of services provided by the independent public accountants in accordance with such pre-approval. The Audit Committee may also delegate pre-approval authority to one or more of its members. Such member(s) must report any decisions to the Audit Committee at the next scheduled meeting. 36 P r o x y S t a t e m e n t STOCKHOLDER PROPOSALS FOR 2011 ABRAXAS ANNUAL MEETING Abraxas intends to hold its next annual meeting during the second quarter of 2011, according to its normal schedule. In order to be included in the proxy material for the 2011 Annual Meeting, Abraxas must receive eligible proposals from stockholders intended to be presented at the annual meeting on or before December 21, 2010, directed to the Abraxas Secretary at the address indicated on the first page of this proxy statement. According to our Amended and Restated Bylaws, Abraxas must receive timely written notice of any stockholder nominations and proposals to be properly brought before the 2011 Annual Meeting. To be timely, such notice must be delivered to the Abraxas Secretary at the principal executive offices set forth on the first page of this proxy statement between February 19, 2011 and the close of business on March 19, 2011. The written notice must set forth, as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (i) the name and address of such stockholder, as they appear on Abraxas’ books, and of such beneficial owner, if any, (ii) (a) the class or series and number of Abraxas shares which are, directly or indirectly, owned beneficially and of record by such stockholder and such beneficial owner, (b) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any class or series of Abraxas shares or with a value derived in whole or in part from the value of any class or series of Abraxas shares, whether or not such instrument or right shall be subject to settlement in the underlying class or series of Abraxas capital stock or otherwise (a “Derivative Instrument”) directly or indirectly owned beneficially by such stockholder and any other direct or indirect opportunity to profit or share in any profit derived from any increase or decrease in the value of Abraxas shares, (c) any proxy, contract, arrangement, understanding, or relationship pursuant to which such stockholder has a right to vote any shares of any Abraxas security, (d) any short interest in any Abraxas security (for purposes of this Section 13, a person shall be deemed to have a short interest in a security if such person, directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise, has the opportunity to profit or share in any profit derived from any decrease in the value of the subject security), (e) any rights to dividends on the Abraxas shares owned beneficially by such stockholder that are separated or separable from the underlying Abraxas shares, (f) any proportionate interest in Abraxas shares or Derivative Instruments held, directly or indirectly, by a general or limited partnership in which such stockholder is a general partner or, directly or indirectly, beneficially owns an interest in a general partner and (g) any performance-related fees (other than an asset-based fee) that such stockholder is entitled to based on any increase or decrease in the value of Abraxas shares or Derivative Instruments, if any, as of the date of such notice including, without limitation, any such interests held by members of such stockholder’s immediate family sharing the same household (which information shall be supplemented by such stockholder and beneficial owner, if any, not later than 10 days after the record date for the meeting to disclose such ownership as of the record date), and (iii) any other information relating to such stockholder and beneficial owner, if any, that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested election pursuant to Section 14 of the Exchange Act, and the rules and regulations promulgated thereunder. If the notice relates to any business other than a nomination of a director or directors that the stockholder proposes to bring before the meeting, the notice must set forth (i) a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest of such stockholder and beneficial owner, if any, in such business and (ii) a description of all agreements, arrangements and understandings between such stockholder and beneficial owner, if any, and any other person or persons (including their names) in connection with the proposal of such business by such stockholder. As to each person, if any, whom the stockholder proposes to nominate for election or reelection to the Board of Directors (i) all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected) and (ii) a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among such stockholder and beneficial owner, if any, and their respective affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation all information that would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K (or any successor rule) if the stockholder making the nomination and any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant and with respect to each nominee for election or reelection to the Board of Directors, include a completed, dated and signed questionnaire, representation and agreement. 37 To be eligible to be a nominee for election or reelection as a director of Abraxas, a person must deliver (in accordance with the time periods prescribed above for delivery of notice) to the Secretary at the principal executive offices of Abraxas a written questionnaire with respect to the background and qualification of such person and the background of any other person or entity on whose behalf the nomination is being made (which questionnaire shall be provided by the Secretary upon written request) and a written representation and agreement (in the form provided by the Secretary upon written request) that such person (i) is not and will not become a party to (a) any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how such person, if elected as a director of Abraxas, will act or vote on any issue or question (a “Voting Commitment”) that has not been disclosed to Abraxas or (b) any Voting Commitment that could limit or interfere with such person’s ability to comply, if elected as a director of Abraxas, with such person’s fiduciary duties under applicable law, (ii) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than Abraxas with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director that has not been disclosed therein, and (iii) in such person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a director of Abraxas, and will comply with all applicable publicly disclosed corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines of Abraxas. Abraxas may also require any proposed nominee to furnish such other information as may reasonably be required by Abraxas to determine the eligibility of such proposed nominee to serve as an independent director of Abraxas or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such nominee. In the event that the 2011 Annual Meeting is more than 30 days from May 19, 2011 (the anniversary of the 2010 Annual Meeting), the dates for submission with the proxy materials and to be properly brought before the 2011 Annual Meeting will change according to Abraxas’ Amended and Restated Bylaws and Regulation 14A under the Exchange Act. A copy of Abraxas’ Amended and Restated Bylaws setting forth the advance notice provisions and requirements for submission of stockholder nominations and proposals may be obtained from the Abraxas Secretary at the address indicated on the first page of this proxy statement. OTHER MATTERS No business other than the matters set forth in this document is expected to come before the meeting, but should any other matters requiring a stockholder’s vote arise, including a question of adjourning the meeting, the persons named in the accompanying proxy will vote thereon according to their best judgment in the interests of Abraxas. If a nominee for office of director should withdraw or otherwise become unavailable for reasons not presently known, the persons named as proxies may vote for another person in his place in what they consider the best interests of Abraxas. Upon the written request of any person whose proxy is solicited hereunder, Abraxas will furnish without charge to such person a copy of its annual report filed with the United States Securities and Exchange Commission on Form 10-K, including financial statements and schedules thereto, for the fiscal year ended December 31, 2009. Such written request is to be directed to Investor Relations, 18803 Meisner Drive, San Antonio, Texas 78258. San Antonio, Texas April 15, 2010 By Order of the Board of Directors Stephen T. Wendel SECRETARY 38 APPENDIX A P r o x y S t a t e m e n t ABRAXAS PETROLEUM CORPORATION 2005 NON-EMPLOYEE DIRECTORS LONG-TERM EQUITY INCENTIVE PLAN (As Amended March 17, 2009 and March 16, 2010) ABRAXAS PETROLEUM CORPORATION 2005 NON-EMPLOYEE DIRECTORS LONG-TERM EQUITY INCENTIVE PLAN TABLE OF CONTENTS PART I PURPOSE, ADMINISTRATION AND RESERVATION OF SHARES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 Purpose of this Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1 Administration of this Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2 Shares Subject to this Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3 Adjustments to Shares Subject to this Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4 SECTION 1. SECTION 2. SECTION 3. SECTION 4. SECTION 5. PART II TERMS APPLICABLE TO ALL AWARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4 . . . . . . . . . . . . . A-4 General Eligibility; Maximum Annual Participant Award and Formula Awards. Procedure for Exercise of Awards; Rights as a Stockholder. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-4 Expiration of Awards. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-5 Effect of Change of Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-5 SECTION 6. SECTION 7. SECTION 8. SECTION 9. PART III SPECIFIC TERMS APPLICABLE TO OPTIONS AND STOCK AWARDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6 SECTION 10. Grant, Terms and Conditions of Options. SECTION 11. Grant, Terms and Conditions of Stock Awards. P r o x y S t a t e m e n t PART IV TERM OF PLAN AND STOCKHOLDER APPROVAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6 Term of Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 12. SECTION 13. Amendment and Termination of this Plan. SECTION 14. Stockholder Approval PART V MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 15. Unfunded Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 16. Representations and Legends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 17. Assignment of Benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 18. Governing Laws . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 19. Application of Funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 SECTION 20. Right of Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-7 i ABRAXAS PETROLEUM CORPORATION 2005 Non-Employee Directors Long-Term Equity Incentive Plan PART I PURPOSE, ADMINISTRATION AND RESERVATION OF SHARES SECTION 1. Purpose of this Plan. The purposes of this Plan are (a) to attract and retain members of the Board of Directors, and (b) to promote the growth and success of the Company’s business, (i) by aligning the long-term interests of the Company’s Directors with those of the Company’s stockholders by providing an opportunity to acquire an interest in the Company and (ii) by providing both rewards for exceptional performance and long term incentives for future contributions to the success of the Company and its Subsidiaries. This Plan permits the grant of Nonqualified Stock Options or Restricted Stock, at the discretion of the Committee and as reflected in the terms of the Award Agreement. Each Award will be subject to conditions specified in this Plan. SECTION 2. Definitions. As used herein, the following definitions shall apply: (a) “Active Status” shall mean that the Director has not been removed from the Board for cause by the Company’s stockholders as provided in the Company’s Articles of Incorporation, as amended, and Bylaws, as amended. (b) “Award” shall mean any award or benefits granted under this Plan, including Options and Restricted Stock. (c) “Award Agreement” shall mean a written or electronic agreement between the Company and the Participant setting forth the terms of the Award. (d) “Beneficial Ownership” shall have the meaning set forth in Rule 13d-3 promulgated under the Exchange Act. (e) “Board” shall mean the Company’s Board of Directors. (f) “Change of Control” shall mean the first day that any one or more of the following conditions shall have been satisfied: P r o x y S t a t e m e n t (i) the sale, transfer, or assignment to, or other acquisition by any other entity or entities, of all or substantially all of the Company’s assets and business in one or a series of related transactions; (ii) a third person, including a “group” as determined in accordance with Section 13(d) or 14(d) of the Exchange Act, obtains the Beneficial Ownership of Common Stock having thirty percent (30%) or more of the then total number of votes that may be cast for the election of members of the Board; or (iii) a cash tender or exchange offer, merger, consolidation, reorganization or other business combination, sale of assets or contested election, or any combination of the foregoing transactions (each a “Transaction”) in connection with the Company, as a result of which the persons who are then members of the Board before the Transaction shall cease to constitute a majority of the Board of the Company or any successor to the Company after the Transaction. (g) “Code” shall mean the Internal Revenue Code of 1986, as amended. (h) “Committee” shall mean the Compensation Committee appointed by the Board. (i) “Common Stock” shall mean the common stock of the Company, par value $0.01 per share. (j) “Company” shall mean Abraxas Petroleum Corporation, a Nevada corporation, and any successor thereto. (k) “Director” shall mean a member of the Board and, except with respect to the ability to vote on any issues before the Board or the delegation of authority from the Board, shall also be deemed to include advisory directors. (l) “Effective Date” shall mean the date on which the Company’s stockholders have approved this Plan in accordance with applicable NASDAQ rules. (m) “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended. (n) “Fair Market Value” shall mean the closing price per share of the Common Stock on the NASDAQ as to the date specified (or the previous trading day if the date specified is a day on which no trading occurred), or if NASDAQ shall cease to be the principal exchange or quotation system upon which the shares of Common Stock are listed or quoted, then such exchange or quotation system upon which the Company elects to list or quote its shares of Common Stock. (o) “FLSA” shall mean the Fair Labor Standards Act of 1938, as amended. (p) “Independent Director” shall mean a Director who: (i) meets the independence requirements of the NASDAQ, or if the NASDAQ shall cease to be the principal exchange or quotation system upon which the shares of Common Stock are listed or quoted, then such exchange or quotation system upon which the Company elects to list or quote its shares of Common Stock; (ii) qualifies as an “outside director” under Section 162(m) of the Code; (iii) qualifies as a “non-employee director” under Rule 16b-3 promulgated under the Exchange Act; and (iv) satisfies independence criteria under any other applicable laws or regulations relating to the issuance of Shares to Non-Employee Directors. (q) “Maximum Annual Participant Award” shall have the meaning set forth in Section 6(b). (r) “Misconduct” shall mean the removal from the Board for cause. (s) “NASDAQ” shall mean the NASDAQ Capital Market. (t) “Nominating and Corporate Governance Committee” shall mean the Nominating and Corporate Governance Committee appointed by the Board. (u) “Non-Employee Director” shall mean a Director who is not a common law employee of the Company or any Subsidiary of the Company. (v) “Option” shall mean a stock option granted pursuant to Section 10 of this Plan. (w) “Optionee” shall mean a Participant who has been granted an Option. (x) “Participant” shall mean any Non-Employee Director granted an Award. (y) “Plan” shall mean this Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan, including any amendments thereto. (z) “Reprice” shall mean the adjustment or amendment of the exercise price of Options or previously awarded whether through amendment, cancellation, replacement of grants or any other means. (aa) “Restricted Stock” shall mean a grant of Shares pursuant to Section 11 of this Plan. (bb) “Retirement” shall mean ceasing to be a Director pursuant to election by the Company’s stockholders or by voluntary resignation with the approval of the Board’s chair after having served continuously on the Board for at least six years. (cc) “SEC” shall mean the Securities and Exchange Commission. (dd) “Share” shall mean one share of Common Stock, as adjusted in accordance with Section 5 of this Plan. (ee) “Subcommittee” shall have the meaning set forth in Section 3(d). (ff) “Subsidiary” shall mean a “subsidiary corporation,” whether now or hereafter existing, as defined in Section 424(f) of the Code, a limited liability company, partnership or other entity in which the Company controls fifty percent (50%) or more of the voting power or equity interests, or an entity with respect to which the Company possesses the power, directly or indirectly, to direct or cause the direction of the management and policies of that entity, whether through the Company’s ownership of voting securities, by contract or otherwise. SECTION 3. Administration of this Plan. (a) Authority. This Plan shall be administered by the Committee. The Committee shall have full and exclusive power to administer this Plan on behalf of the Board, subject to such terms and conditions as the Committee may prescribe. Notwithstanding anything herein to the contrary, the Committee’s power to administer this Plan, and actions the Committee takes under this Plan, shall be limited by the provisions set forth in the Committee’s charter, as such charter may be amended from time to time, and the further limitation that certain actions may be subject to review and approval by either the full Board or a panel consisting of all of the Independent Directors of the Company. (b) Powers of the Committee. Subject to the other provisions of this Plan, the Committee shall have the authority, in its discretion: (i) to determine the Participants, to whom Awards, if any, will be granted hereunder; (ii) to grant Options and Restricted Stock to Participants and to determine the terms and conditions of such Awards, including the determination of the Fair Market Value of the Shares, the number of Shares to be represented by each Award and the vesting schedule, the exercise price, the timing of such Awards, and to modify or amend each Award, with the consent of the Participant when required; A-2 (iii) to construe and interpret this Plan and the Awards granted hereunder; (iv) to prescribe, amend, and rescind rules and regulations relating to this Plan, including the form of Award Agreement, and manner of acceptance of an Award, such as correcting a defect or supplying any omission, or reconciling any inconsistency so that this Plan or any Award Agreement complies with applicable law, regulations and listing requirements and to avoid unanticipated consequences deemed by the Committee to be inconsistent with the purposes of this Plan or any Award Agreement; (v) to accelerate or defer (with the consent of the Participant) the exercise or vested date of any Award; (vi) to authorize any person to execute on behalf of the Company any instrument required to effectuate the grant of an Award previously granted by the Committee; and (vii) to make all other determinations deemed necessary or advisable for the administration of this Plan; provided, that, no consent of a Participant is necessary under clauses (i) or (v) if a modification, amendment, acceleration, or deferral, in the reasonable judgment of the Committee confers a benefit on the Participant or is made pursuant to an adjustment in accordance with Section 5. (c) Effect of Committee’s Decision. All decisions, determinations, and interpretations of the Committee shall be final and binding on all Participants, the Company (including its Subsidiaries), any stockholder and all other persons. (d) Delegation. Consistent with the Committee’s charter, as such charter may be amended from time to time, the Committee may delegate its authority and duties under this Plan to one or more separate committees consisting of members of the Committee or other Directors who are Independent Directors (any such committee a “Subcommittee”), and such actions shall be treated for all purposes as if taken by the Committee; provided that the grant of Awards shall be made in accordance with parameters established by the Committee. Any action by any such Subcommittee within the scope of such delegation shall be deemed for all purposes to have been taken by the Committee. P r o x y S t a t e m e n t SECTION 4. Shares Subject to this Plan. (a) Reservation of Shares. The shares of Common Stock reserved under this Plan shall be 1,500,000 shares of Common Stock. If an Award expires, is forfeited or becomes unexercisable for any reason without having been exercised in full, the undelivered Shares which were subject thereto shall, unless this Plan shall have been terminated, become available for future Awards under this Plan. Without limiting the foregoing, unless this Plan shall have been terminated, Shares underlying an Award that has been exercised, either in part or in full, including any Shares that would otherwise be issued to a Participant that are used to satisfy any withholding tax obligations that arise with respect to any Award, shall become available for future Awards under this Plan except to the extent Shares were issued in settlement of the Award. The Shares may be authorized but unissued, or reacquired shares of Common Stock. The Company, during the term of this Plan, will at all times reserve and keep available such number of Shares as shall be sufficient to satisfy the requirements of this Plan. (b) Time of Granting Awards. The date of grant of an Award shall, for all purposes, be the date on which the Company completes the corporate action relating to the grant of such Award and all conditions to the grant have been satisfied, provided that conditions to the exercise of an Award shall not defer the date of grant. Notice of a grant shall be given to each Participant to whom an Award is so granted within a reasonable time after the determination has been made. (c) Securities Law Compliance. Shares shall not be issued pursuant to the exercise of an Award unless the exercise of such Award and the issuance and delivery of such Shares pursuant thereto shall comply with all relevant provisions of law, including, without limitation, the Securities Act of 1933, as amended, the Exchange Act, the rules and regulations promulgated under either such Acts, and the requirements of any stock exchange or quotation system upon which the Shares may then be listed or quoted, and shall be further subject to the approval of counsel for the Company with respect to such compliance. (d) Substitutions and Assumptions. The Board or the Committee shall have the right to substitute or assume Awards in connection with mergers, reorganizations, separations, or other transactions to which Section 424(a) of the Code applies, provided such substitutions and assumptions are permitted by Section 424 of the Code and the regulations promulgated thereunder. The number of Shares reserved pursuant to Section 4(a) may be increased by the corresponding number of Awards assumed and, in the case of a substitution, by the net increase in the number of Shares subject to Awards before and after the substitution. A-3 SECTION 5. Adjustments to Shares Subject to this Plan. (a) Adjustments. If the outstanding shares of Common Stock shall be changed into or exchanged for a different number or kind of shares of stock or other securities or property of the Company or of another corporation (whether by reason of merger, consolidation, recapitalization, reclassification, split up, combination of shares or otherwise), or if the number of such shares of Common Stock shall be increased by a stock dividend or stock split, there shall be substituted for or added to each share of Common Stock theretofore reserved for the purposes of this Plan, whether or not such shares are at the time subject to outstanding Awards, the number and kind of shares of stock or other securities or property into which each outstanding share of Common Stock shall be so changed or for which it shall be so exchanged, or to which each such share shall be entitled, as the case may be. Outstanding Awards shall also be considered to be appropriately amended as to price and other terms as may be necessary or appropriate to reflect the foregoing events. If there shall be any other change in the number or kind of the outstanding shares of Common Stock, or of any stock or other securities or property into which such Common Stock shall have been changed, or for which it shall have been exchanged, and if the Committee shall in its sole discretion determine that such change equitably requires an adjustment in the number or kind or price of the shares then reserved for the purposes of this Plan, or in any Award theretofore granted or which may be granted under this Plan, then such adjustment shall be made by the Committee and shall be effective and binding for all purposes of the Plan. In making any such substitution or adjustment pursuant to this Section 5, fractional shares may be ignored. (b) Amendments. The Committee shall have the power, in the event of any merger or consolidation of the Company with or into any other corporation, or the merger or consolidation of any other corporation with or into the Company, to amend all outstanding Awards to permit the exercise thereof in whole or in part at anytime, or from time to time, prior to the effective date of any such merger or consolidation and to terminate each such Award as of such effective date. (c) No Other Adjustment. Except as expressly provided herein, no issuance by the Company of shares of any class, or securities convertible into shares of any class, shall affect, and no adjustment by reason thereof shall be made with respect to, the number or price of shares subject to an Award. PART II TERMS APPLICABLE TO ALL AWARDS SECTION 6. General Eligibility; Maximum Annual Participant Award and Formula Awards. (a) Awards. Awards may be granted only to Participants who are Non-Employee Directors. (b) Maximum Annual Participant Award. The aggregate number of Shares with respect to which an Award or Awards may be granted to any one Participant in any one taxable year of the Company (the “Maximum Annual Participant Award”) shall not exceed 100,000 shares of Common Stock (subject to adjustment as set forth in Section 5(a)) pursuant to the Awards to be granted pursuant to Section 6(c) and Section 6(d). (c) Formula Awards. Each year at the first regular meeting of the Board of Directors immediately following the Company’s annual stockholders meeting for that year, each Non-Employee Director at the time of such Board meeting, shall be granted Awards of 10,000 shares of Common Stock (subject to adjustment as set forth in Section 5(a)), unless the Committee shall decide otherwise prior to or at such Board meeting. The Awards granted pursuant to this Section 6(c) are intended to compensate each Non-Employee Director for that Non-Employee Director’s participation in Board and Committee meetings during the Company’s previous calendar year. Any Non-Employee Director who leaves the Board (including ceasing to be an advisory Director) prior to the date of the first regular meeting of the Board of Directors shall not be entitled to any Awards under this Section 6(c). (d) Other Director Awards. For Non-Employee Directors who are appointed to the Board after the Effective Date of the Plan, the Board may grant an Award to the Non-Employee Director and the terms and conditions of that grant shall be determined by the Committee. In addition, at any other time, the Board may grant an Award to a Non-Employee Director and the terms and conditions of that grant shall be determined by the Committee. The Awards granted pursuant to this Section 6(d) are intended to compensate each Non-Employee Director for that Non-Employee Director’s commitment to the Board of Directors by aligning the long-term interests of the Company’s Directors with those of the Company’s stockholders. SECTION 7. Procedure for Exercise of Awards; Rights as a Stockholder. (a) Procedure. An Award shall be exercised when written, electronic or verbal notice of exercise has been given to the Company, or the brokerage firm or firms approved by the Company to facilitate exercises and sales under this Plan, A-4 P r o x y S t a t e m e n t in accordance with the terms of the Award by the person entitled to exercise the Award and full payment for the Shares with respect to which the Award is exercised has been received by the Company or the brokerage firm or firms, as applicable. The notification to the brokerage firm shall be made in accordance with procedures of such brokerage firm approved by the Company. Full payment may, as authorized by the Committee, consist of any consideration and method of payment allowable under Section 7(b) of this Plan. The Company shall issue (or cause to be issued) such share certificate promptly upon exercise of the Award. No adjustment will be made for a dividend or other right for which the record date is prior to the date the share certificate is issued, except as provided in Section 5 of this Plan. (b) Method of Payment. The consideration to be paid for any Shares to be issued upon exercise or other required settlement of an Award, including the method of payment, shall be determined by the Committee at the time of settlement and which forms may include (without limitation): (i) with respect to an Option, a request that the Company or the designated brokerage firm conduct a cashless exercise of the Option; (ii) cash; and (iii) tender of shares of Common Stock owned by the Participant in accordance with rules established by the Committee from time to time. Shares used to pay the exercise price shall be valued at their Fair Market Value on the exercise date. Payment of the aggregate exercise price by means of tendering previously-owned shares of Common Stock shall not be permitted when the same may, in the reasonable opinion of the Company, cause the Company to record a loss or expense as a result thereof. (c) Withholding Obligations. To the extent required by applicable federal, state, the Committee may and/or a Participant shall make arrangements satisfactory to the Company for the satisfaction of any withholding tax obligations that arise with respect to any Option or Restricted Stock or any sale of Shares. The Company shall not be required to issue Shares or to recognize the disposition of such Shares until such obligations are satisfied. These obligations may be satisfied by having the Company withhold a portion of the Shares that otherwise would be issued to a Participant under such Award or by tendering Shares previously acquired by the Participant in accordance with rules established by the Committee from time to time. local or foreign law, (d) Stockholder Rights. Except as otherwise provided in this Plan, until the issuance (as evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company) of the share certificate evidencing such Shares, no right to vote or receive dividends or any other rights as a stockholder shall exist with respect to the Shares subject to the Award, notwithstanding the exercise of the Award. (e) Non-Transferability of Awards. An Award may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in exchange for consideration, except that an Award may be transferred by will or by the laws of descent or distribution and may be exercised, during the lifetime of the Participant, only by the Participant; unless the Committee permits further transferability, on a general or specific basis, in which case the Committee may impose conditions and limitations on any permitted transferability. SECTION 8. Expiration of Awards. (a) Expiration, Termination or Forfeiture of Awards. Unless otherwise provided in the applicable Award Agreement or any severance agreement, vested Awards granted under this Plan shall expire, terminate, or otherwise be forfeited as follows: (i) three (3) months after the date the Company delivers a notice of termination of a Participant’s Active Status, other than in circumstances covered by (ii), (iii) or (iv) below; (ii) immediately upon termination of a Participant’s Active Status for Misconduct; (iii) twelve (12) months after the date of the death of a Participant whose Active Status terminated as a result of his or her death; and (iv) thirty-six (36) months after the date on which the Participant ceased performing services as a result of Retirement. (b) Extension of Term. Notwithstanding subsection (a) above, the Committee shall have the authority to extend the expiration date of any outstanding Option in circumstances in which it deems such action to be appropriate (provided that no such extension shall extend the term of an Option beyond the date on which the Option would have expired if no termination of the Participant’s Active Status had occurred). SECTION 9. Effect of Change of Control. Notwithstanding any other provision in this Plan to the contrary, the following provisions shall apply unless otherwise provided in the most recently executed agreement between the Participant A-5 and the Company, or specifically prohibited under applicable laws, or by the rules and regulations of any applicable governmental agencies or national securities exchanges or quotation systems. (a) Acceleration. Awards of a Participant shall be Accelerated (as defined in Section 9(b)) upon the occurrence of a Change of Control. (b) Definition. For purposes of this Section 9, Awards of a Participant being “Accelerated” means, with respect to such Participant: (i) any and all Options shall become fully vested and immediately exercisable, and shall remain exercisable throughout their entire term; and (ii) any restriction periods and restrictions imposed on Restricted Stock shall lapse. SPECIFIC TERMS APPLICABLE TO OPTIONS AND STOCK AWARDS PART III SECTION 10. Grant, Terms and Conditions of Options. (a) Term of Options. The term of Options shall be at the discretion of the Committee. (b) Option Exercise Prices. The per Share exercise price under an Option shall be no less than one hundred percent (100%) of the Fair Market Value per Share on the date of grant. In no event shall the Board or the Committee be permitted to Reprice an Option after the date of grant without stockholder approval. (c) Vesting. Options granted pursuant to this section 10 shall vest pursuant to the periods, terms and conditions determined by the Committee in its sole discretion. To the extent Options vest and become exercisable in increments, such Options shall cease vesting as of the termination of such Optionee’s Active Status for reasons other than Retirement or death, in each of which cases such Options shall immediately vest in full. (d) Exercise. Any Option granted hereunder shall be exercisable at such times and under such conditions as determined by the Committee at the time of grant, and as are permissible under the terms of this Plan. An Option may not be exercised for a fraction of a Share. SECTION 11. Grant, Terms and Conditions of Stock Awards. (a) Designation. Restricted Stock may be granted either alone, in addition to, or in tandem with other Awards granted under this Plan. After the Committee determines that it will offer Restricted Stock, it will advise the Participant in writing or electronically, by means of an Award Agreement, of the terms, conditions and restrictions, including vesting, if any, related to the offer, including the number of Shares that the Participant shall be entitled to receive or purchase, the price to be paid, if any, and, if applicable, the time within which the Participant must accept the offer. The offer shall be accepted by execution of an Award Agreement or as otherwise directed by the Committee. The term of each award of Restricted Stock shall be at the discretion of the Committee. (b) Vesting. The Committee shall determine the time or times within which an Award of shares of Restricted Stock may be subject to forfeiture, the vesting schedule and the rights to acceleration thereof, and all other terms and conditions of the Award. Subject to the applicable provisions of the Award Agreement and this Section 11, upon termination of a Participant’s Active Status for any reason, all Restricted Stock subject to the Award Agreement may vest or be forfeited in accordance with the terms and conditions established by the Committee as specified in the Award Agreement. PART IV TERM OF PLAN AND STOCKHOLDER APPROVAL SECTION 12. Term of Plan. This Plan shall become effective as of the Effective Date. It shall continue in effect until the tenth anniversary of the Effective Date or until terminated under Section 14 of this Plan or extended by an amendment approved by the stockholders of the Company pursuant to Section 14(a). SECTION 13. Amendment and Termination of this Plan. (a) Amendment and Termination. The Board or the Committee may amend or terminate this Plan from time to time in such respects as the Board may deem advisable (including, but not limited, to amendments which the Board deems A-6 P r o x y S t a t e m e n t appropriate to enhance the Company’s ability to claim deductions related to stock option exercises); provided, that to the extent required by the Code or the rules of the NASDAQ, such other exchange upon which the Company’s Common Stock is either quoted or traded, or the SEC, stockholder approval shall be required for any material amendment of this Plan. Subject to the foregoing, it is specifically intended that the Board or Committee may amend this Plan without stockholder approval to comply with legal, regulatory and listing requirements and to avoid unanticipated consequences deemed by the Committee to be inconsistent with the purpose of this Plan or any Award Agreement. (b) Effect of Amendment or Termination. Any amendment or termination of this Plan shall not affect Awards already granted and such Awards shall remain in full force and effect as if this Plan had not been amended or terminated, unless mutually agreed otherwise between the Participant and the Committee, which agreement must be in writing and signed by the Participant and the Company. SECTION 14. Stockholder Approval. The effectiveness of this Plan is subject to approval by the stockholders of the Company in accordance with applicable NASDAQ rules. PART V MISCELLANEOUS SECTION 15. Unfunded Plan. The adoption of this Plan and any setting aside of amounts by the Company with which to discharge its obligations hereunder shall not be deemed to create a trust. The benefits provided under this Plan shall be a general, unsecured obligation of the Company payable solely from the general assets of the Company, and neither a Participant nor the Participant’s beneficiaries or estate shall have any interest in any assets of the Company by virtue of this Plan. Nothing in this Section 15 shall be construed to prevent the Company from implementing or setting aside funds in a grantor trust subject to the claims of the Company’s creditors. Legal and equitable title to any funds set aside, other than any grantor trust subject to the claims of the Company’s creditors, shall remain in the Company and any funds so set aside shall remain subject to the general creditors of the Company, present and future. Any liability of the Company to any Participant with respect to an Award shall be based solely upon contractual obligations created by this Plan and the Award Agreements. SECTION 16. Representations and Legends. The Committee may require each person purchasing shares pursuant to an Award under this Plan to represent to and agree with the Company in writing that the purchaser is acquiring the shares without a view to distribution thereof. In addition to any legend required by this Plan, the certificate for such shares may include any legend which the Committee deems appropriate to reflect a restriction on transfer. All certificates for shares of Common Stock delivered under this Plan shall be subject to such stock transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the SEC, any stock exchange upon which the Common Stock is listed, applicable federal or state securities laws, and any applicable corporate law, and the Committee may cause the legend or legends to be put on any such certificates to make appropriate reference to such restriction. SECTION 17. Assignment of Benefits. No Award or other benefits payable under this Plan shall, except as otherwise provided under this Plan or as specifically provided by law, be subject in any manner to anticipation, alienation, attachment, sale, transfer, assignment, pledge, encumbrance or charge. Any attempt to anticipate, alienate, attach, sell, transfer, assign, pledge, encumber or charge, any such benefit shall be void, and any such benefit shall not in any manner be subject to the debts, contracts, liabilities, engagements or torts of any person who shall be entitled to such benefit, nor shall such benefit be subject to attachment or legal process for or against that person. SECTION 18. Governing Laws. This Plan and actions taken in connection herewith shall be governed, construed and enforced in accordance with the laws of the State of Nevada. SECTION 19. Application of Funds. The proceeds received by the Company from the sale of shares of Common Stock pursuant to Awards granted under this Plan will be used for general corporate purposes. SECTION 20. Right of Removal. Nothing in this Plan or in any Award or Award Agreement shall confer upon any Non-Employee Director or any other individual the right to continue as a Director of the Company, or affect any right the Company or the Company’s stockholders may have to remove the Non-Employee Director as a Director at any time for any reason. A-7 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) È ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2009 ‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 001-16071 ABRAXAS PETROLEUM CORPORATION (Exact name of Registrant as specified in its charter) Nevada (State or Other Jurisdiction of Incorporation or Organization) 74-2584033 (I.R.S. Employer Identification Number) 18803 Meisner Drive San Antonio, TX 78258 (Address of principal executive offices) (210) 490-4788 Registrant’s telephone number, including area code SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class: Common Stock, par value $.01 per share Preferred Stock Purchase Rights Name of each exchange on which registered: The NASDAQ Stock Market, LLC 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 È Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes È No ‘ 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 È No ‘ Indicate by check mark if 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 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. Yes È No ‘ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one): Large accelerated filer ‘ Non-accelerated filer È (Do not check if a smaller reporting company) Accelerated filer ‘ Smaller reporting company ‘ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ‘ No È As of June 30, 2009, the last day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of the common stock held by non-affiliates of the registrant was $43,053,752 based on the closing sale price as reported on The NASDAQ Stock Market. As of March 12, 2010, there were 76,230,187 shares of common stock outstanding. Documents Incorporated by Reference: Document Portions of the registrant’s Proxy Statement relating to the 2010 Annual Meeting of Shareholders to be held on May 19, 2010. Parts Into Which Incorporated Part III F o r m 1 0 - K ABRAXAS PETROLEUM CORPORATION FORM 10-K TABLE OF CONTENTS Part I Item 1. Item 1A. Item 1B. Item 2. Item 3. Item 4. Part II Item 5. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Removed and Reserved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 6. Management’s Discussion And Analysis Of Financial Condition And Results of Operations . . . . . . . . . . Item 7. Quantitative and Qualitative Disclosure about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 7A. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . Item 9A(T). Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9B. Part III Item 10. Item 11. Item 12. Item 13. Item 14. Part IV Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . . . . . . . . . Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 4 16 25 25 30 30 31 33 33 50 51 51 52 52 54 54 54 54 54 Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 F o r m 1 0 - K i FORWARD-LOOKING INFORMATION We make forward-looking statements throughout this document. Whenever you read a statement that is not simply a statement of historical fact (such as statements including words like “believe,” “expect,” “anticipate,” “intend,” “will,” “plan,” “seek,” “estimate,” “could,” “potentially” or similar expressions), you must remember that these are forward-looking statements, and that our expectations may not be correct, even though we believe they are reasonable. The forward-looking information contained in this document is generally located in the material set forth under the headings “Business,” “Risk Factors,” “Properties,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” but may be found in other locations as well. These forward-looking statements generally relate to our plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends. The factors that may affect our expectations regarding our operations include, among others, the following: • • • • • • • • • • • • • our success in development, exploitation and exploration activities; our ability to make planned capital expenditures; declines in our production of oil and gas; prices for oil and gas; our ability to raise equity capital or incur additional indebtedness; political and economic conditions in oil producing countries, especially those in the Middle East; price and availability of alternative fuels; our restrictive debt covenants; our acquisition and divestiture activities; weather conditions and events; the proximity, capacity, cost and availability of pipelines and other transportation facilities; results of our hedging activities; and other factors discussed elsewhere in this document. F o r m 1 0 - K 1 GLOSSARY OF TERMS Unless otherwise indicated in this report, gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit. Oil and gas equivalents are determined using the ratio of six Mcf of gas to one barrel of oil, condensate or NGLs. The following definitions shall apply to the technical terms used in this report. Terms used to describe quantities of oil and gas: “Bbl” – barrel or barrels. “Bcf” – billion cubic feet of gas. “Bcfe” – billion cubic feet of gas equivalent. “Boe” – barrels of oil equivalent. “Boepd” – barrels of oil equivalent per day. “MBbl” – thousand barrels. “MBoe” – thousand barrels of oil equivalent. “Mcf” – thousand cubic feet of gas. “Mcfe” – thousand cubic feet of gas equivalent. “MMBbls” – million barrels. “MMBoe” – million barrels of oil equivalent. “MMbtu” – million British Thermal Units. “MMcf” – million cubic feet of gas. “MMcfe” – million cubic feet of gas equivalent. “MMcfepd” – million cubic feet of gas equivalent per day. “MMcfpd” – million cubic feet of gas per day. Terms used to describe our interests in wells and acreage: “Developed acreage” means acreage which consists of leased acres spaced or assignable to productive wells. “Development well” is a well drilled within the proved area of an oil or gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved oil or gas reserves. “Dry hole” is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. “Exploratory well” is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be producing oil or gas in another reservoir, or to extend a known reservoir. “Gross” means gross acres refer to the number of acres in which we own a working interest. “Gross well” is a well in which we own an interest. “Net acres” are deemed to exist when the sum of fractional ownership working interests in gross acres equals one (e.g., a 50% working interest in a lease covering 320 gross acres is equivalent to 160 net acres). “Net well” is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. “Productive well” is an exploratory or a development well that is not a dry hole. “Undeveloped acreage” means those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. 2 Terms used to assign a present value to or to classify our reserves: “Proved reserves” or “reserves” means oil and gas, condensate and NGLs on a net revenue interest basis, found to be commercially recoverable. “Probable reserves” are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. “Possible reserves” are those additional reserves which analysis of geosciences and engineering data suggest are less likely to be recoverable than probable reserves. “Proved undeveloped reserves” includes those proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. “PV-10” means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC. “Standardized Measure” means estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, calculated in accordance with ASC 932, formerly Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.” F o r m 1 0 - K 3 Item 1. Business Part I Information contained in this report represents the operations of Abraxas Petroleum Corporation and Abraxas Energy Partners, L.P., which we refer to as the Partnership or Abraxas Energy Partners, which are consolidated for financial reporting purposes. On October 5, 2009, Abraxas Petroleum Corporation acquired 100% ownership of the Partnership, which we refer to as the Merger. The non-controlling interest of the former limited partners of the Partnership is presented as non-controlling interest in the accompanying Consolidated Statement of Operations through the date that their interest was acquired by Abraxas. The terms “Abraxas,” “we,” “us,” “our,” or the “Company,” refer to Abraxas Petroleum Corporation, together with its consolidated subsidiaries including Abraxas Energy Partners, L.P., unless the context otherwise requires. General We are an independent energy company primarily engaged in the development and production of oil and gas. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves. At December 31, 2009, our properties were located in the Rocky Mountain, Mid-Continent, Permian Basin and Gulf Coast regions of the United States. The following table sets forth certain information related to our properties as of and for the year ended December 31, 2009: Gross Producing Wells Average Working Interest Rocky Mountain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Continent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gulf Coast 900 617 237 74 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,828 12% 14% 67% 64% 22% Estimated Net Proved Reserves (MMBOE) 7,237.1 3,109.0 5,541.8 9,031.9 Net Production (MBOE) 434.8 263.1 500.5 435.2 24,919.8 1,633.6 Our Rocky Mountain properties consist of the following: • • Northern Rockies—Our properties in the Northern Rockies are located in the Williston Basin of North Dakota, South Dakota and Montana and consist of wells that produce oil from Paleozoic-aged carbonate reservoirs from the Madison formation at 8,000 feet down to the Red River formation at 12,000 feet, including the Bakken at 9,000 feet, and the underlying Three Forks. Southern Rockies—Our properties in the Southern Rockies are located in the Green River, Powder River and Uinta Basins of Wyoming, Colorado and Utah and consist of wells that produce oil from Cretaceous-aged fractured shales in the Mowry and Niobrara formation and oil and gas from Cretaceous-aged sandstones in the Turner, Muddy and Frontier formations. Well depths range from 7,000 feet down to 10,000 feet. We have 900 gross (110 net) producing wells in the Rocky Mountain region. Our Mid-Continent properties consist of the following: • • Arkoma Basin—Our properties in the Arkoma Basin are located in Oklahoma and Arkansas and consist of wells that mainly produce gas from Hartshorne coals at 3,000 feet. Anadarko Basin—Our properties in the Anadarko Basin are located in Oklahoma and the Texas Panhandle and consist of wells that mainly produce gas from Pennsylvanian-aged sandstones (Atoka/Morrow) from depths down to 18,000 feet. 4 • ARK-LA-TEX—Our properties in the ARK-LA-TEX region principally produce from the East Texas/North Louisiana Basins and include wells that produce oil and gas from various formations. We have 617 gross (89 net) producing wells in the Mid-Continent region. Our Permian Basin properties consist of the following: • • • ROC Complex—Our properties in the ROC Complex are located in Pecos, Reeves and Ward Counties, Texas and consist of wells that produce oil and gas from multiple stacked formations from the Bell Canyon at 5,000 feet down to the Ellenburger at 16,000 feet. Oates SW—Our properties in the Oates SW area are located in Pecos County, Texas and consist of wells that produce gas from the Devonian formation at a depth of approximately 13,500 feet. Eastern Shelf—Our properties in the Eastern Shelf are predominately located in Coke, Scurry and Mitchell Counties, Texas and consist of wells that produce oil and gas from the Strawn Reef formation at 5,000 to 6,000 feet and oil from the shallower Clearfork formation at depths ranging from 2,300 to 3,300 feet. We have 237 gross (158 net) producing wells in the Permian Basin region. Our Gulf Coast properties consist of the following: • • Edwards—Our properties in the Edwards trend are located in DeWitt and Lavaca Counties, Texas and consist of wells that produce gas from the Edwards formation at a depth of 13,500 feet. Portilla—Our properties in the Portilla field are located in San Patricio County, Texas, were discovered in 1950 by The Superior Oil Company, predecessor to Mobil Oil Corporation, and consist of wells that produce oil and gas from the Frio sands and the deeper Vicksburg from depths of approximately 7,000 to 9,000 feet. • Wilcox—Our properties in the Wilcox are located in Goliad, Bee, DeWitt and Karnes Counties, Texas and consist of wells that produce gas from various sands in the Wilcox formation at depths ranging from 8,000 to 11,000 feet. We have 74 gross (48 net) producing wells in the Gulf Coast region. F o r m 1 0 - K Recent Developments Merger Agreement On June 30, 2009, Abraxas Petroleum and Abraxas Energy Partners signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which Abraxas Energy agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum, Abraxas Energy Partners and Abraxas Merger Dub, LLC, which we refer to as Merger Sub, signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which Abraxas Energy Partners agreed to merge with and into Merger Sub with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, which we refer to as the Effective Time, the common units of Abraxas Energy Partners not owned by Abraxas Petroleum and its subsidiaries were converted into the right to receive 4.25 shares of Abraxas Petroleum common stock for each Abraxas Energy Partners common unit not owned by Abraxas Petroleum or its subsidiaries. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of Abraxas Energy Partners under the Abraxas Petroleum Corporation 2005 Long-Term Equity Incentive Plan, or LTIP. Credit Facility Simultaneously with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. In connection with the Merger, we borrowed $145.0 million under the credit facility, of which $135.0 million was borrowed under the revolving portion and $10.0 million was borrowed under the term loan portion. As of December 31, 2009, $138.5 million was outstanding under the revolving portion and $8.0 million was outstanding under the term portion. For more information about the credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Long-Term Indebtedness—Credit Facility. 5 2010 Capital Budget We anticipate making capital expenditures of $30.0 million in 2010 for the development of our existing properties. The capital program for 2010 will be selected from our inventory of projects and will include new drills and re-completions / workovers in our primary producing regions of the Rocky Mountain, Mid-Continent, Permian Basin and onshore Gulf Coast. The ultimate mix of projects will be based on commodity prices, services costs and drilling results but will predominately target oil projects. These anticipated expenditures are subject to adequate cash flow from operations and availability under the credit facility. Non-Core Divestitures We have initiated a divestiture program, principally aimed at non-operated, non-core assets, to generate cash for debt repayment and to accelerate our drilling program. During the fourth quarter of 2009 and the first quarter of 2010, we have sold certain non-core assets for combined net proceeds of approximately $11.2 million ($2.4 million in 2009 and $8.8 million in 2010). In total, these properties produced approximately 142 Boepd (approximately 3% of our daily net production) and had approximately 606 MBoe of proved reserves (approximately 2% of our net proved reserves), which equates to $78,385 per producing Boepd and $18.41 per proved Boe. The first $10 million of net proceeds will be used to repay the term loan portion of our credit facility after which, any net proceeds will be allocated approximately 50% for further debt reduction and 50% to accelerate our capital program. We have identified an additional $20 to $30 million of similar non-core assets that we will attempt to divest on similar terms over the next several months. Tax Benefits Preservation Plan On March 16, 2010, our board of directors adopted a Tax Benefits Preservation Plan (the “Tax Benefits Preservation Plan”) and declared a dividend of one preferred share purchase right for each outstanding share of Abraxas common stock. The dividend is payable to our stockholders of record as of March 16, 2010. The terms of the rights and the Tax Benefits Preservation Plan are set forth in a Rights Agreement, by and between us and American Stock Transfer & Trust Company, as Rights Agent, dated as of March 16, 2010. This summary of rights provides only a general description of the Tax Benefits Preservation Plan. We adopted the Tax Benefits Preservation Plan in an effort to protect stockholder value by attempting to protect against a possible limitation on our ability to use our net operating loss carryforwards, or NOL’s, to reduce potential future federal income tax obligations. We have experienced and continue to experience substantial operating losses, and under the Internal Revenue Code and rules promulgated by the Internal Revenue Service, we may “carry forward” these losses in certain circumstances to offset any current and future earnings and thus reduce our federal income tax liability, subject to certain requirements and restrictions. To the extent that the NOLs do not otherwise become limited, we believe that we will be able to carry forward a significant amount of NOLs, and therefore these NOLs could be a substantial asset to us. However, if we experience an “Ownership Change,” as defined in Section 382 of the Internal Revenue Code, our ability to use the NOLs will be substantially limited, and the timing of the usage of the NOLs could be substantially delayed, which could therefore significantly impair the value of that asset. As of December 31, 2009, we had net operating loss carryforwards of $121.7 million. The Tax Benefits Preservation Plan is intended to act as a deterrent to any person or group acquiring 4.9% or more of our outstanding common stock, or an Acquiring Person, without our approval. Stockholders who own 4.9% or more of our outstanding common stock as of the close of business on March 16, 2010 will not trigger the Tax Benefits Preservation Plan so long as they do not (i) acquire any additional shares of common stock or (ii) fall under 4.9% ownership of common stock and then re–acquire 4.9% or more of the common stock. The Tax Benefits Preservation Plan does not exempt any future acquisitions of common stock by such persons. Any rights held by an Acquiring Person are null and void and may not be exercised. We may, in our sole discretion, exempt any person or group from being deemed an Acquiring Person for purposes of the Tax Benefits Preservation Plan. The Rights. We authorized the issuance of one right per each outstanding share of our common stock payable to our stockholders of record as of March 16, 2010. Subject to the terms, provisions and conditions of the Tax Benefits Preservation Plan, if the rights become exercisable, each right would initially represent the right to purchase from us one one–thousandth of a share of our Series 2010 Junior Participating Preferred Stock (“Series 2010 Preferred Stock”) for a purchase price of $7.00 (the “Purchase Price”) . If issued, each fractional share of Series 2010 Junior Preferred Stock would give the 6 stockholder approximately the same dividend, voting and liquidation rights as does one share of our common stock. However, prior to exercise, a right does not give its holder any rights as a stockholder of the Company, including without limitation any dividend, voting or liquidation rights. Series 2010 Preferred Stock Provisions. Each one one-thousandth of a share of Series 2010 Preferred Stock, if issued: (1) will not be redeemable; (2) will entitle holders to quarterly dividend payments of $0.01 per one one-thousandth of a share of Series 2010 Preferred Stock, or an amount equal to the dividend paid on one share of common stock, whichever is greater, if, as and when declared by our board of directors out of funds legally available therefor; (3) will entitle holders upon liquidation either to receive $1.00 per one one-thousandth of a share of Series 2010 Preferred Stock or an amount equal to the payment made on one share of common stock, whichever is greater; (4) will have the same voting power as one share of common stock; and (5) if shares of our common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock. The value of one one-thousandth interest in a Preferred Share should approximate the value of one share of common stock. Exercisability. The rights will not be exercisable until the earlier of (i) 10 business days after a public announcement by us that a person or group has become an Acquiring Person or (ii) 10 business days after the commencement of a tender or exchange offer by a person or group for 4.9% of the common stock. We refer to the date that the rights become exercisable as the “Distribution Date.” Until the Distribution Date, our common stock certificates will evidence the rights and will contain a notation to that effect. Any transfer of shares of common stock prior to the Distribution Date will constitute a transfer of the associated rights. After the Distribution Date, the rights may be transferred other than in connection with the transfer of the underlying shares of common stock. After the Distribution Date, each holder of a right, other than rights beneficially owned by the Acquiring Person (which will thereupon become void), will thereafter have the right to receive upon exercise of a right and payment of the Purchase Price, that number of shares of common stock having a market value at the time of exercise of two times the Purchase Price. Exchange. After the Distribution Date, we may exchange the rights (other than rights owned by an Acquiring Person, which will have become void), in whole or in part, at an exchange ratio of one share of common stock, or a fractional share of Series 2010 Preferred Stock (or of a share of a similar class or series of the Company’s preferred stock having similar rights, preferences and privileges) of equivalent value, per right (subject to adjustment). Expiration. The rights and the Tax Benefits Preservation Plan will expire on the earliest of (i) March 16 2015, (ii) the time at which the rights are redeemed pursuant to the Rights Agreement, (iii) the time at which the rights are exchanged pursuant to the Rights Agreement, (iv) the repeal of Section 382 of the Code or any successor statute if we determine that the Rights Agreement is no longer necessary for the preservation of NOLs and (v) the beginning of a taxable year of the Company of which we determine that no NOLs may be carried forward. Redemption. At any time prior to the time an Acquiring Person becomes such, we may redeem the rights in whole, but not in part, at a price of $0.01 per right (the “Redemption Price”). The redemption of the rights may be made effective at such time, on such basis and with such conditions as we in our sole discretion may establish. Immediately upon any redemption of the rights, the right to exercise the rights will terminate and the only right of the holders of rights will be to receive the Redemption Price. Anti—Dilution Provisions. We may adjust the purchase price of the shares of Series 2010 Preferred Stock, the number of shares Series 2010 Preferred Stock issuable and the number of outstanding rights to prevent dilution that may occur as a result of certain events, including among others, a stock dividend, a stock split or a reclassification of the shares of Series 2010 Preferred Stock or our common stock. No adjustments to the purchase price of less than 1% will be made. Amendments. Before the Distribution Date, we may amend or supplement the Tax Benefits Preservation Plan without the consent of the holders of the rights. After the Distribution Date, we may amend or supplement the Tax Benefits Preservation Plan only to cure an ambiguity, to alter time period provisions, to correct inconsistent provisions, or to make any additional changes to the Tax Benefits Preservation Plan, but only to the extent that those changes do not impair or adversely affect any rights holder. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group who attempts to acquire the Company on terms not approved by us. The rights should not interfere with any merger or other business combination approved by us since we may redeem the rights at $0.01 per right at any time until the date on which a person or group has become an Acquiring Person. 7 F o r m 1 0 - K Markets and Customers The revenue generated by our operations is highly dependent upon the prices of oil and gas. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other oil-producing and gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation and policies. Decreases in the prices of oil and gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenue, profitability and cash flow from operations. You should read the discussion under “Risk Factors – Risks Relating to Our Industry – Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows, profitability and growth” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies” for more information relating to the effects of decreases in oil and gas prices on us. To help mitigate the impact of commodity price volatility, we hedge a portion of our production through the use of fixed price swaps. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General – Commodity Prices and Derivative Activities” and Note 12 of the notes to our consolidated financial statements for more information regarding our derivative activities. Substantially all of our oil and gas is sold at current market prices under short-term arrangements, as is customary in the industry. During the year ended December 31, 2009, two purchasers accounted for approximately 21% of our gas sales, and no single purchaser accounted for more that 10% of our oil sales. We believe that there are numerous other purchasers available to buy our oil and gas and that the loss of one or more of these purchasers would not materially affect our ability to sell oil and gas. Regulation of Oil and Gas Activities The exploration, production and transportation of all types of hydrocarbons are subject to significant governmental regulations. Our properties are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by industry specific price controls, taxes, conservation, safety, environmental and other laws relating to the petroleum industry, and by changes in such laws and by constantly changing administrative regulations. Federal, state and local laws and regulations govern oil and gas activities. Operators of oil and gas properties are required to have a number of permits in order to operate such properties, including operator permits and permits to dispose of salt water. We possess all material requisite permits required by the states and other local authorities in which we operate properties. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits in order to operate such properties such as hazardous materials certificates, which we have obtained. Development and Production The operations of our properties are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring the operator of oil and gas properties to possess permits for the drilling and development of wells, post bonds in connection with various types of activities, and file reports concerning operations. Most states, and some counties and municipalities in which we operate, regulate one or more of the following: • • • • • the location of wells; the method of developing and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to surface owners and other third parties. Some states regulate the size and shape of development and spacing units or proration units for oil and gas properties. Some states allow forced pooling or unitization of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum allowable rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of 8 production. These laws and regulations may limit the amount of oil and gas we can produce from their wells or limit the number of wells or the locations at which these wells can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. Operations on Federal or Indian oil and gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies, including the Bureau of Land Management, which we refer to as BLM, and the Minerals Management Service, which we refer to as MMS. MMS establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas leases. Accordingly, we believe that the impact of royalty regulation on the operations of our properties should generally be the same as the impact on our competitors. We believe that the operations of our properties are in material compliance with all applicable regulations as they pertain to Federal or Indian oil and gas leases. The failure to comply with these rules and regulations can result in substantial penalties, including lease suspension or termination in the case of federal leases. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect us. Regulation of Transportation and Sale of Natural Gas Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended, which we refer to as NGA, the Natural Gas Policy Act of 1978, as amended, which we refer to as NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, which we refer to as FERC and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended, which we refer to as the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders, which we refer to, collectively, as Order No. 636, to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. FERC continues to regulate the rates that interstate pipelines may charge for such transportation and storage services. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry. In 2000, FERC issued Order No. 637 and subsequent orders, which we refer to, collectively, as Order No. 637, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect. The Energy Policy Act of 2005, which we refer to as EP Act 2005, gave FERC increased oversight and penalty authority regarding market manipulation and enforcement. EP Act 2005 amended the NGA to prohibit market manipulation and also amended the NGA and the NGPA to increase civil and criminal penalties for any violations of the NGA, NGPA and any rules, regulations or orders of FERC to up to $1,000,000 per day, per violation. In addition, FERC issued a final rule effective January 26, 2006, regarding market manipulation, which makes it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC jurisdiction, to defraud, make an untrue statement, 9 F o r m 1 0 - K or omit a material fact or engage in any practice, act, or course of business that operates or would operate as a fraud. This final rule works together with FERC’s enhanced penalty authority to provide increased oversight of the natural gas marketplace. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers. Generally, intrastate natural gas transportation is subject to regulation by state regulatory agencies, although FERC does regulate the rates, terms, and conditions of service provided by intrastate pipelines that transport gas subject to FERC’s NGA jurisdiction pursuant to Section 311 of the NGPA. The basis for state regulation of intrastate 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. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors. Natural Gas Gathering Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. FERC has developed tests for determining which facilities constitute jurisdictional transportation facilities under the NGA and which facilities constitute gathering facilities exempt for FERC’s NGA jurisdiction. From time to time, FERC reconsiders its test for defining non-jurisdictional gathering. For example, there is currently pending at FERC a proposed rulemaking to reformulate its test for non-jurisdictional gathering in the shallow waters of the Outer Continental Shelf. In recent years, FERC has also permitted jurisdictional pipelines to “spin down” exempt gathering facilities into affiliated entities that are not subject to FERC jurisdiction, although FERC continues to examine the circumstances in which such a “spin down” is appropriate and whether it should reassert jurisdiction over certain gathering companies and facilities that previously had been “spun down.” We cannot predict the effect that FERC’s activities in this regard may have on the operations of our properties, but we do not expect these activities to affect the operations in any way that is materially different from the effect thereof on our competitors. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take or service requirements, but does not generally entail rate regulation. In the United States, gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under FERC Order 636. For example, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the state’s more active review of rates, services and practices associated with the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates. Regulation of Transportation of Oil Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, FERC, in February 2003, increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect the operations of our properties in any way that is materially different from the effect of such regulation on our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under 10 the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors. Environmental Matters Oil and gas operations are subject to numerous federal, state and local laws and regulations controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may: • • • • • • require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; restrict injection of liquids into subsurface strata that may contaminate groundwater; and impose substantial liabilities for pollution resulting from our operations. Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations. F o r m 1 0 - K We are not currently involved in any administrative, judicial or legal proceedings arising under federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our respective financial positions or results of operations. Moreover, we maintain insurance against the costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area. The following is a discussion of the current relevant environmental laws and regulations that relate to our operations. Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, also known as Superfund, and which we refer to as CERCLA, and comparable state statutes impose strict, joint, and several liability, without regard to fault or legality of conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, such persons or companies may be retroactively liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, certain wastes may be generated that may fall within CERCLA’s definition of a “hazardous substance.” We may be liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed. Although CERCLA currently contains a “petroleum exclusion” from the definition of “hazardous substance,” state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including oil cleanups. 11 We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA (as defined below), and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators; to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent future contamination. Oil Pollution Act of 1990. Federal regulations also require certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The Federal Oil Pollution Act, which we refer to as OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our financial position or results of operations. Resource Conservation Recovery Act. The Resource Conservation and Recovery Act, which we refer to as RCRA, is the principal federal statute governing the treatment, storage and disposal of hazardous and non-hazardous solid wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and gas exploration and production wastes to be classified and regulated as non-hazardous wastes. A similar exemption is contained in many of the state counterparts to RCRA. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and gas exploration and production wastes from regulation as hazardous wastes. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose and would cause us to incur increased operating expenses. Also, in the ordinary course of our operations, we generate small amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. Naturally Occurring Radioactive Materials, which we refer to as NORM, are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and protection; limitations upon the release of NORM contaminated land for unrestricted use. We believe that the operations of our properties are in material compliance with all applicable NORM standards established by the various states in which we operate wells. Clean Water Act. The Clean Water Act, which we refer to as the CWA, and analogous state laws, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of the CWA require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a petroleum hydrocarbon tank spill, rupture or leak. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that the operations of our properties comply in all material respects with the requirements of the CWA and state statutes enacted to control water pollution. Safe Drinking Water Act. Our operations also produce wastewaters that are disposed via underground injection wells. These activities are regulated by the Safe Drinking Water Act, which we refer to as the SDWA, and analogous state and local 12 laws. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production. The main goal of the SDWA is the protection of usable aquifers. The primary objective of injection well operating requirements 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. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In most states, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits. Clean Air Act. The Clean Air Act, which we refer to as the CAA, and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. The operations of our properties utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require oil and natural gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. Oil and natural gas exploration and production facilities may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws. Hydraulic Fracturing. Many of our operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Many of our newer wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at existing and new well sites as well as increased costs to make our wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. If enacted, these laws could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have considered imposing various conditions and restrictions on hydraulic fracturing operations, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells. Climate change legislation and greenhouse gas regulation. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change 13 F o r m 1 0 - K in presidential administrations, on December 7, 2009, the EPA issued a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA’s finding, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry. On June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. On November 5, 2009 the Senate Committee on Environment and Public Works approved the “Clean Energy Jobs and American Power Act of 2009,” authored by John Kerry and Barbara Boxer, that is similar in many ways to ACESA. One of the purposes of these bills is to control and reduce emissions of greenhouse gases in the United States. These bills would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% to 20% (from 2005 levels) by 2020, and by over 80% by 2050. Under these bills, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet the overall emission reduction goals of the bills. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of these bills would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. President Obama has indicated that he is in support of the adoption of legislation such as the two bills discussed above, and the White House is expending significant efforts to push for the legislation. Two recent court decisions, one before the United States Second Circuit Court of Appeals and one before the United States Fifth Circuit Court of Appeals have allowed GHG related cases to proceed. In the first case, Connecticut v. American Electric Power, the Second Circuit ruled that several states and other plaintiffs could continue a suit to impose GHG reductions on several utility defendants, concluding that a political question and standing objections of the defendants did not prohibit the suit from going forward. The Fifth Circuit, in Comer v. Murphy Oil, ruled that plaintiffs could similarly pursue a damage suit and the political question did not prohibit the suit. This case involves claims by plaintiffs who suffered damages from Hurricane Katrina that are seeking to recover damages from certain GHG emitters asserting their emissions contributed to their increased damages. In another case filed in the State District Court in Austin, Texas on October 6, 2009, a citizens group sued the Texas Commission on Environmental Quality (TCEQ) asserting that the agency was required to regulate carbon dioxide emissions from parties applying for permits under the Texas Clean Air Act. The result of this lawsuit could impose additional regulations on our operations, if the Texas courts require the TCEQ to regulate carbon dioxide and perhaps other GHGs such as methane, and these rules are applied to our operations in Texas. We may be subject to the EPA GHG monitoring and reporting rule, and potentially new EPA permitting rules if adopted to apply GHG permitting obligations and emissions limitations under the federal Clean Air Act. Even if no federal greenhouse gas regulations are enacted, or if the EPA issues regulations, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed: the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations. National Environmental Policy Act. Oil and gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, which we refer to as NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. If we were to conduct any exploration and production activities on federal lands in the future, those activities would need to obtain governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and gas projects. 14 Endangered Species Act. The Endangered Species Act, which we refer to as the ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our properties may be located in areas that may be designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the discovery of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. Abandonment Costs. All of our oil and gas wells will require proper plugging and abandonment at some time in the future. We have posted bonds with most regulatory agencies to ensure compliance with their plugging responsibility. Plugging and abandonment operations and associated reclamation of the surface production site are important components of our environmental management system. We plan accordingly for the ultimate disposition of properties that are no longer producing. Title to Properties As is customary in the oil and gas industry, we make only a cursory review of title to undeveloped oil and gas leases at the time we acquire them. However, before drilling commences, we require a thorough title search to be conducted, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller/lessor of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our properties, some of which are subject to immaterial encumbrances, easements and restrictions. The oil and gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties. Competition We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future, we cannot assure you that such materials and resources will be available to us. Employees As of March 12, 2010, we had 70 full-time employees. We retain independent geological, land and engineering consultants from time to time on a limited basis and expect to continue to do so in the future. Available Information We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission. You may read and copy any document we file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet web site that contains annual, quarterly and current reports, proxy statements and other information that issuers (including Abraxas) file electronically with the SEC. The SEC’s web site is www.sec.gov. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments filed with the Securities and Exchange Commission are available free of charge on our web site at www.abraxaspetroleum.com in the Investor Relations section as soon as practicable after such reports are filed. Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. F o r m 1 0 - K 15 Item 1A. Risk Factors Risks Related to Our Business We have substantial indebtedness which may adversely affect our cash flow and business operations. At December 31, 2009, we had a total of $146.5 million of indebtedness under our credit facility. Our indebtedness could have important consequences to us, including: • • • • our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; covenants contained in our credit facility and future debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; we may need a substantial portion of our cash flow from operations to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and our level of debt will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally, than our competitors with less debt. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying acquisitions and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional debt or equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all. A breach of the terms and conditions of the credit facility, including the inability to comply with the required financial covenants, could result in an event of default. If an event of default occurs (after any applicable notice and cure periods), the lenders would be entitled to terminate any commitment to make further extensions of credit under the credit facility and to accelerate the repayment of amounts outstanding (including accrued and unpaid interest and fees). Upon a default under the credit facility, the lenders could also foreclose against any collateral securing such obligations, which may be all or substantially all of our assets. If that occurred, we may not be able to continue to operate as a going concern. We may not be able to fund the capital expenditures that will be required for us to increase reserves and production. We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capital expenditures primarily with cash flow from operations, borrowings under credit facilities, sales of producing properties, and sales of debt and equity securities and we expect to continue to do so in the future. We cannot assure you that we will have sufficient capital resources in the future to finance all of our planned capital expenditures. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of planned capital expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital expenditures would, by necessity, be decreased. The borrowing base under our credit facility will be determined from time to time by the lenders. Reductions in estimates of oil and gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lenders’ inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves. If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result, our ability to replace production may be limited. In addition, if the borrowing base under the credit facility is reduced, we would be required to reduce our borrowings under the credit 16 facility so that such borrowings do not exceed the borrowing base. This could further reduce the cash available to us for capital spending and, if we did not have sufficient capital to reduce our borrowing level, we may be in default under the credit facility. We have sold producing properties to provide us with liquidity and capital resources in the past and we may continue to do so in the future. After any such sale, we would expect to utilize the proceeds to reduce our indebtedness and to drill new wells on our remaining properties. If we cannot replace the production lost from properties sold with production from the remaining properties, our cash flow from operations will likely decrease, which in turn, would decrease the amount of cash available for additional capital spending. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition would be adversely affected. Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced. Unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, we cannot assure you that our exploration and development activities will result in increases in our proved reserves. Approximately 93% of the estimated ultimate recovery of our proved developed producing reserves as of December 31, 2009 had been produced. Based on the reserve information set forth in our reserve report as of December 31, 2009, our average annual estimated decline rate for our net proved developed producing reserves is 13% during the first five years, 8% in the next five years, and approximately 7% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and prior property sales. As our proved reserves and consequently our production decline, our cash flow from operations, and the amount that we are able to borrow under our credit facility will also decline. In addition, approximately 44% of our total estimated proved reserves at December 31, 2009 were classified as undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Even if we are successful in our development efforts, it could take several years for a significant portion of these undeveloped reserves to generate positive cash flow. We may not find any commercially productive oil and gas reservoirs. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our capital investment. Drilling for oil and gas may be unprofitable. Dry holes and wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable. The inherent risk of not finding commercially productive reservoirs will be compounded by the fact that 44% of our total estimated proved reserves as of December 31, 2009 were classified as undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. In addition, our properties may be susceptible to drainage from production by other operations on adjacent properties. If the volume of oil and gas we produce decreases, our cash flow from operations will decrease. F o r m 1 0 - K Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors that are beyond our control or not covered by insurance. Our drilling operations are subject to a number of risks, including: • • • • • • • unexpected drilling conditions; facility or equipment failure or accidents; shortages or delays in the availability of drilling rigs, equipment and crews; adverse weather conditions; title problems; unusual or unexpected geological formations; pipeline ruptures; 17 • • fires, blowouts and explosions; and uncontrollable flows of oil or gas or well fluids. Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation. We maintain insurance against some but not all of these risks. 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. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations. Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests. Our credit facility contains a number of significant covenants that, among other things, limit our ability to: • • • • • • • • • incur or guarantee additional indebtedness and issue certain types of preferred stock or redeemable stock; transfer or sell assets; create liens on assets; pay dividends or make other distributions on capital stock or make other restricted payments, including repurchasing, redeeming or retiring capital stock or subordinated debt or making certain investments or acquisitions; engage in transactions with affiliates; guarantee other indebtedness; make any change in the principal nature of our business; permit a change of control; or consolidate, merge or transfer all or substantially all of our assets. In addition, our credit facility requires us to maintain compliance with specified financial covenants. Our ability to comply with these covenants may be adversely affected by events beyond our control, and we cannot assure you that we can maintain compliance with these covenants. These financial covenants could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary or desirable business activities. A breach of any of these covenants could result in a default under our credit facility. A default, if not cured or waived, could result in all of our indebtedness becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable or favorable to us. The marketability of our production depends largely upon the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities. The marketability of our production depends in part upon processing and transportation facilities. Transportation space on such gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to such facilities or due to such space being utilized by other companies with priority transportation agreements. Our access to transportation options can also be affected by U.S. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand. These factors and the availability of markets are beyond our control. If market factors dramatically change, the financial impact on us could be substantial and adversely affect our ability to produce and market oil and gas. 18 An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations. Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Canadian and Rocky Mountain producers, combined with limited refining and pipeline capacity in the Rocky Mountain area, have gradually widened differentials in this area. During 2009, differentials averaged $7.67 per Bbl of oil and $0.70 per Mcf of gas. Approximately 43% of our production during 2009 was from the Rocky Mountain and Mid-Continent regions. Historically, these regions have experienced wider differentials than our Permian Basin and Gulf Coast properties. As the percentage of our production from the Rocky Mountain and Mid-Continent regions increases, we expect that our price differentials will also increase. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations. Our derivative contracts could result in financial losses or could reduce our cash flow. To achieve more predictable cash flow and reduce our exposure to adverse fluctuations in the prices of oil and gas and to comply with the requirements under our credit facility, we enter into derivative contracts, which we sometimes refer to as hedging arrangements, for a significant portion of our oil and gas production that could result in both realized and unrealized derivative contract losses. We have entered into NYMEX-based fixed price commodity swap arrangements on approximately 85% of the oil and gas production from our estimated net proved developed producing reserves through December 31, 2012 and 70% for 2013 in order to comply with the requirements of our credit facility. Any new hedging arrangements will be priced at then-current market prices and may be significantly lower than the commodity swaps we currently have in place. The extent of our commodity price exposure will be related largely to the effectiveness and scope of our commodity price derivative contract activities. For example, the prices utilized in our derivative instruments are currently NYMEX-based, which may differ significantly from the actual prices we receive for oil and gas which are based on the local markets where oil and gas are produced. The prices that we receive for our oil and gas production are typically lower than the relevant benchmark prices that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. As a result, our cash flow from operations could be affected if the basis differentials widen more than we anticipate. For more information see “—An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.” We currently do not have any basis differential hedging arrangements in place. Our cash flow from operations could also be affected based upon the levels of our production. If production is higher than we estimate, we will have greater commodity price exposure than we intended. If production is lower than the nominal amount that is subject to our hedging arrangements, we may be forced to satisfy all or a portion of our hedging arrangements without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial reduction in cash flows. If the prices at which we hedge our oil and gas production are less than current market prices, our cash flow from operations could be adversely affected. When our derivative contract prices are higher than market prices, we will incur realized and unrealized gains on our derivative contracts and when our contract prices are lower than market prices, we will incur realized and unrealized losses. For the year ended December 31, 2009, we recognized a realized gain on oil and gas derivative contracts of $17.9 million and an unrealized loss of $28.4 million. The realized gain resulted in an increase in cash flow from operations. We expect to continue to enter into similar hedging arrangements in the future to reduce our cash flow volatility. On July 29, 2009, we entered into hedging arrangements for specified volumes, which equate to approximately 85% of the estimated oil and gas production from our proved developed producing reserves through December 31, 2012 and 70% for 2013. We cannot assure you that the derivative contracts that we have entered into, or will enter into, will adequately protect us from financial loss in the future due to circumstances such as: • • • highly volatile oil and gas prices; our production being less than expected; or a counterparty to one of our hedging transactions defaulting on its contractual obligations. 19 F o r m 1 0 - K The counterparties to our derivative contracts may be unable to perform their obligations to us which could adversely affect our cash flow. At times when market prices are lower than our derivative contract prices, we are entitled to payments from our counterparties. The worldwide financial and credit crisis may adversely affect the ability of our counterparties to fulfill their contractual obligations to us. If one of our counterparties is unable or unwilling to make the required payments to us, it could adversely affect our cash flow. Lower oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This charge does not impact cash flow from operating activities, but does reduce our stockholders’ equity and earnings. The risk that we will be required to write- down the carrying value of oil and gas properties increases when oil and gas prices are low, which could be further impacted by the new modernized oil and gas reporting disclosures, which requires us to use an average price over the prior 12-month period, rather than the year-end price. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though oil and gas prices may have increased the ceiling applicable to the subsequent period. At December 31, 2009, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves. However, at December 31, 2008, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $116.4 million resulting in a write down of $116.4 million. We cannot assure you that we will not experience additional write downs in the future. Use of our net operating loss carryforwards may be limited. At December 31, 2009, we had, subject to the limitation discussed below, $121.7 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire in varying amounts through 2028 if not otherwise used. The use of our net operating loss carryforwards may be limited if an “ownership change” of over 50 percentage points occurs during any three-year period. Based on current estimates, we believe that we have not surpassed this threshold. It is feasible that even a modest change of ownership (including, but not limited to, a shift in common stock ownership by one reasonably large stockholder or any offering of common stock) during the three- year period following the Merger, which was consummated on October 5, 2009, could trigger a significant limitation of the amount of such net operating loss carryforwards available to offset future taxable income. Additionally, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, we have established a valuation allowance of $47.2 million for deferred tax assets at December 31, 2007, $60.8 million at December 31, 2008 and $91.5 million at December 31, 2009. We depend on our Chairman, President and CEO and the loss of his services could have an adverse effect on our operations. We depend to a large extent on Robert L.G. Watson, our Chairman of the Board, President and Chief Executive Officer, for our management and business and financial contacts. Mr. Watson may terminate his employment agreement with us at any time on 30 days notice, but, if he terminates without cause, he would not be entitled to the severance benefits provided under the terms of that agreement. Mr. Watson is not precluded from working for, with or on behalf of a competitor upon termination of his employment with us. If Mr. Watson were no longer able or willing to act as our Chairman, the loss of his services could have an adverse effect on our operations. Our financial statements are complex. Due to the nature of our business, and accounting principles generally accepted in the United States of America, our financial statements continue to be complex, particularly with reference to derivative contracts, asset retirement obligations, equity awards, deferred taxes and the accounting for our deferred compensation plans. We expect such complexity to continue and possibly increase. 20 Risks Related to Our Industry Market conditions for oil and gas, and particularly volatility of prices for oil and gas, could adversely affect our revenue, cash flows, profitability and growth. Our revenue, cash flows, profitability and future rate of growth depend substantially upon prevailing prices for oil and gas. Gas prices affect us more than oil prices because 65% of our production and 65% of our proved reserves were gas at December 31, 2009. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also make it uneconomical for us to increase or even continue current production levels of oil and gas. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of other factors beyond our control, including: • • • • • changes in foreign and domestic supply and demand for oil and gas; political stability and economic conditions in oil producing countries, particularly in the Middle East; general economic conditions; domestic and foreign governmental regulation; and the price and availability of alternative fuel sources. The current global recession has had a significant impact on commodity prices and our operations. If gas prices remain depressed or oil prices decline significantly, our revenues, profitability and cash flow from operations may decrease which could cause us to alter our business plans, including reducing our drilling activities. Estimates of proved reserves and future net revenue are inherently imprecise. The process of estimating oil and gas reserves is complex involving decisions and assumptions in evaluating the available geological, geophysical, engineering and economic data. Accordingly, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of our reserves set forth in this document. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. The estimates of our reserves as of December 31, 2009, are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved reserves and the PV-10 thereof for our oil and gas properties are based on the assumption that future oil and gas prices remain the same as the twelve month un-weighted first-day-of-the-month average oil and gas prices for the year ended December 31, 2009. The average realized sales prices as of such date used for purposes of such estimates were $3.42 per Mcf of gas and $55.05 per Bbl of oil. This compares with average realized sales prices of $4.77 per Mcf of gas and $41.74 per Bbl of oil as of December 31, 2008. The December 31, 2009 estimates also assume that we will make future capital expenditures of approximately $138.4 million in the aggregate primarily from 2010 through 2014, which are necessary to develop and realize the value of proved reserves on our properties. In addition, approximately 44% of our total estimated proved reserves as of December 31, 2009 were classified as undeveloped. By their nature, estimates of undeveloped reserves are less certain than proved developed reserves. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of our reserves set forth or incorporated by reference in this document. The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. As required by SEC regulations, we based the December 31, 2009 estimated discounted future net cash flows from our proved reserves on the twelve month un-weighted first-day-of-the-month average oil and gas prices and costs in effect on the day of the estimate. However, actual future net cash flows from our properties will be affected by factors such as: • • supply of and demand for oil and gas; actual prices we receive for oil and gas; 21 F o r m 1 0 - K • • • • our actual operating costs; the amount and timing of our capital expenditures; the amount and timing of actual production; and changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flow, which is required by the SEC, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition. Our operations are subject to the numerous risks of oil and gas drilling and production activities. Our oil and gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, ruptures and discharges of toxic gases. In addition, title problems, weather conditions and mechanical difficulties or shortages or delays in delivery of drilling rigs and other equipment could negatively affect our operations. If any of these or other similar industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. We operate in a highly competitive industry which may adversely affect our operations. We operate in a highly competitive environment. The principal resources necessary for the exploration and production of oil and gas are leasehold prospects under which oil and gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of oil and gas operations. We must compete for such resources with both major oil and gas companies and independent operators. Many of these competitors have financial and other resources substantially greater than ours. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future, we cannot assure you that such resources will be available to us. The unavailability or high cost of drilling rigs, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. Our industry is cyclical and, from time to time, there could be a shortage of drilling rigs, equipment, supplies, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wages of, qualified drilling rig crews rise as the number of active rigs in service increases. When oil and gas prices are high, the demand for oilfield services rises and the cost of these services increases. Our oil and gas operations are subject to various Federal, state and local regulations that materially affect our operations. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on production. In order to conserve supplies of oil and gas, these agencies have restricted the rates of flow from oil and gas wells below actual production capacity. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and gas, by-products from oil and gas and other substances and materials produced or used in connection with oil and gas operations. To date, our expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant. We believe that we are in substantial compliance with all applicable laws and regulations. However, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. 22 Proposed federal legislation concerning tax deductions currently available with respect to oil and gas drilling may adversely affect our net earnings and proposed legislative initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions and delays. The Obama administration has proposed the outright elimination of many of the key federal income tax benefits historically associated with the oil and gas industry. Although presented in very summary form, among other significant energy tax items, the administration’s budget appears to propose the complete elimination of (i) expensing of intangible drilling costs, and (ii) the “percentage depletion” method of deduction with respect to oil and gas wells. Although no legislation has been formally introduced, if this proposal (or others) is enacted into law, it could adversely affect our net earnings. Additionally, Congress is currently considering legislation to amend the Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells. The sponsors of the bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process as well as additional levels of regulation that could lead to operational restrictions and delays and increased operating costs. Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas. Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries including the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs. At the federal level, in June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill or ACESA. The United States Senate passed out of committee the Clean Energy Jobs and American Power Act, also known as the Kerry-Boxer Bill. Although these bills differ in certain ways, they both contain provisions that would establish a cap and trade system for restricting greenhouse gas emissions in the United States. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this federal legislative initiative remains uncertain. In addition to pending climate legislation, the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules this year. In the courts, several decisions have been issued that may increase the risk of claims being filed by government entities and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and gas that we produce. F o r m 1 0 - K 23 Risks Related to Our Common Stock Future issuance of additional shares of common stock could cause dilution of ownership interests and adversely affect the stock price. We are currently authorized to issue 200,000,000 shares of common stock with such rights as determined by our board of directors. We may in the future issue previously authorized and unissued securities, resulting in the dilution of the ownership interests of current stockholders. The potential issuance of any such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of common stock or other securities that are convertible into or exercisable for common stock for capital raising or other business purposes. Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of our common stock. We cannot pay dividends on common stock. We have never paid a cash dividend on our common stock and the terms of the credit facility prohibit us from paying dividends on our common stock. Shares eligible for future sale may depress our stock price. At December 31, 2009, we had 76,231,751 shares of common stock outstanding of which 5,836,963 shares were held by affiliates and, in addition, 4,089,892 shares of common stock were subject to outstanding options granted under stock option plans (of which 1,807,622 shares were vested at December 31, 2009). All of the shares of common stock held by affiliates are restricted or control securities under Rule 144 promulgated under the Securities Act of 1933, as amended. The shares of common stock issuable upon exercise of stock options have been registered under the Securities Act. Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of our common stock and could impair our ability to raise additional capital through the sale of equity securities. The price of our common stock has been volatile and could continue to fluctuate substantially. Our common stock is traded on The NASDAQ Stock Market. The market price of our common stock has been volatile and could fluctuate substantially based on a variety of factors, including the following: • • • • • • fluctuations in commodity prices; variations in results of operations; legislative or regulatory changes; general trends in the industry; market conditions; and analysts’ estimates and other events in the oil and gas oil industry. We may issue shares of preferred stock with greater rights than our common stock. Subject to the rules of The NASDAQ Stock Market, our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of our common stock. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than our common stock. On March 16, 2010, our board of directors adopted a tax benefits preservation plan and declared a dividend of one preferred share purchase right for each outstanding share of our common stock. These rights are only activated if the plan is triggered by any person or group acquiring 4.9% or more of our outstanding common stock without our approval. Anti-takeover provisions could make a third party acquisition of Abraxas difficult. Our articles of incorporation and bylaws provide for a classified board of directors, with each member serving a three- year term, and eliminate the ability of stockholders to call special meetings or take action by written consent. Each of the provisions in the articles of incorporation, bylaws and the tax benefits plan, could make it more difficult for a third party to acquire Abraxas without the approval of its board. In addition, the Nevada corporate statute also contains certain provisions 24 that could make an acquisition by a third party more difficult. On March 16, 2010, our board of directors adopted a tax benefits preservation plan designed to preserve our substantial tax assets. In addition, the plan is intended to act as a deterrent to any person or group acquiring 4.9% or more of our outstanding common stock without our approval. An active market may not continue for our common stock and we could face de-listing if our stock price declines. Our common stock is quoted on The NASDAQ Stock Market. While there are currently three market makers in our common stock, these market makers are not obligated to continue to make a market in our common stock. In this event, the liquidity of our common stock could be adversely impacted and a stockholder could have difficulty obtaining accurate stock quotes. If our stock price declines and remains below $1.00 per share for an extended period of time, we could be de-listed from The NASDAQ Stock Market as the minimum threshold for a continued listing is $1.00 per share. Item 1B. Unresolved Staff Comments None. Item 2. Properties Exploratory and Developmental Acreage Our principal oil and gas properties consist of producing and non-producing oil and gas leases, including reserves of oil and gas in place. The following table indicates our interest in developed and undeveloped acreage and fee mineral acreage as of December 31, 2009. There are no material lease expirations in 2010. Rocky Mountain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Continent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Developed Acreage Undeveloped Acreage Fee Mineral Acreage(1) Gross Acres 62,649 84,961 24,494 11,210 Net Acres 32,237 21,715 17,397 6,200 Gross Acres 86,551 1,957 15,025 7,651 Net Acres Gross Acres 57,005 1,120 988 — 13,395 5,214 — 12,007 Net Acres 1,120 — 5,272 — Total Net Acres(2) 90,362 22,703 36,064 11,414 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183,314 77,549 111,184 76,602 13,127 6,392 160,543 (1) Fee mineral acreage represents fee simple absolute ownership of the mineral estate or fraction thereof. (2) Includes 3,981 acres that are included in developed and undeveloped gross acres. Productive Wells The following table sets forth our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2009: F o r m 1 0 - K Rocky Mountain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Continent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gulf Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 390.0 124.0 177.0 34.5 92.8 13.5 129.6 25.8 510.0 493.0 60.0 39.5 Productive Wells Oil Gas Gross Net Gross Net 17.1 75.6 28.2 21.9 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 725.5 261.7 1,102.5 142.8 Reserves Information In December 2009, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved reserves with the Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The new accounting standard requires that the average, first-day-of-the-month price during the 12-month period preceding the end of the year, rather than the year-end price, be used when estimating reserve quantities and permits the use of reliable technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Prior-year data are presented in accordance with Financial Accounting Standards Board (“FASB”) oil and gas disclosure requirements effective during those periods. 25 Oil and gas reserves have been estimated as of December 31, 2007 for all of our properties by DeGolyer and MacNaughton, of Dallas, Texas. DeGolyer and MacNaughton estimated reserves for properties comprising approximately 92% and 95% of the PV-10 of our oil and gas reserves as of December 31, 2008 and December 31, 2009, respectively. Reserves for the remaining 8% and 5% of our properties were estimated by Abraxas personnel because we determined that it was not practical for DeGolyer and MacNaughton to prepare reserve estimates for all of our properties because we own a large number of properties with relatively low values. DeGolyer and MacNaughton’s reserve report as of December 31, 2009 included a total of 402 properties, which comprised approximately 95% of the PV-10 of all our properties as of that date. A total of 867 properties were included in the reserve estimates prepared by Abraxas personnel which comprised approximately 5% of our PV-10 at December 31, 2009. DeGolyer and MacNaughton’s reserve report as of December 31, 2008 included a total of 412 properties, which comprised approximately 92% of the PV-10 of all our properties as of that date. A total of 889 properties were included in the reserve estimates prepared by Abraxas personnel which comprised approximately 8% of our PV-10 at December 31, 2008. The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. DeGolyer and MacNaughton’s opinions indicate that the estimates of proved reserves prepared by us for the properties reviewed by DeGolyer and MacNaughton, when compared in total do not differ materially from the estimates prepared by DeGolyer and MacNaughton. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by Abraxas. The report of DeGolyer and MacNaughton dated February 26, 2010, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer and MacNaughton as well as the qualifications of DeGolyer and MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report. Estimates of proved reserves at December 31, 2009, 2008 and 2007 were based on studies performed by the operations department of Abraxas. The operations department is directly responsible for Abraxas’ reserve evaluation process. The Vice President of Operations is the manager of this department and is the primary technical person responsible for this process. The Vice President of Operations holds a Bachelor of Science degree in Petroleum Engineering, and has 25 years of experience in reserve evaluations. The operations department consists of four petroleum engineers with Bachelor degrees in Petroleum Engineering, one of whom is a Registered Professional Engineer in the State of Texas, and various other technical professionals. Reserve information as well as models used to estimate such reserves are stored on secured databases. Non-technical inputs used in reserve estimation models, including oil and gas prices, production costs, future capital expenditures and Abraxas’ net ownership percentages are obtained from other departments within the Company. Oil and gas reserves, and the estimates of the present value of future net revenues therefrom, were determined based on prices and costs as prescribed by SEC and FASB guidelines. Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, year-end prices and costs were used in estimating net cash flows for the years ended December 31, 2007 and 2008. For the year ended December 31, 2009, commodity prices over the prior 12-month period and year end costs were used in estimating net cash flows. 26 The following table sets forth certain information regarding estimates of our oil and gas reserves as of December 31, 2007, December 31, 2008 and December 31, 2009. All of our reserves are located in the United States. Estimated Proved Reserves Proved Developed Proved Undeveloped Total Proved Probable(1) Possible(1) As of December 31, 2007 Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,184 33,908 947 54,095 3,131 88,003 As of December 31, 2008 Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,563 48,209 1,482 60,207 7,045 108,416 As of December 31, 2009 Oil (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,891 47,861 2,941 48,665 8,832 96,526 2,086 31,740 2,010 18,546 1. Disclosure of probable and possible reserves became optional under SEC guidelines for years ended December 31, 2009, accordingly, no probable or possible reserves are included for the years ended December 31, 2007 and 2008. The process of estimating oil and gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. You should not assume that the present value of future net revenues referred to in this Annual Report on Form 10-K is the current market value of our estimated oil and gas reserves. In accordance with new SEC requirements, the estimated discounted future net cash flows from proved reserves require us to use an average price over the prior 12-month period, rather than the year-end price on December 31, 2009. In prior years, discounted future net cash flows from proved reserves was generally based on prices and costs as of the end of the year of the estimate, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of our consolidated financial statements may be used. Because we use the full cost method to account for our oil and gas operations, we are susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. This is known as a “ceiling limitation write-down.” This charge does not impact cash flow from operating activities but does reduce our stockholders’ equity and reported earnings. We have experienced ceiling limitation write-downs in the past and we cannot assure you that we will not experience additional ceiling limitation write-downs in the future. As of December 31, 2009, the Company’s net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves. However, at December 31, 2008, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $116.4 million resulting in a write down of $116.4 million. We cannot assure you that we will not experience additional write downs in the future. Based on managements’ review of average first-day-of-the-month prices for the twelve months April 2009 through March 2010, we do not anticipate a write down at the end of the first quarter of 2010. For more information regarding the full cost method of accounting, you should read the information under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies.” Actual future prices and costs may be materially higher or lower than the prices and costs used in the estimate. Any changes in consumption by gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the oil and gas industry in general will affect the accuracy of the 10% discount factor. The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of oil and gas reserves, future net revenue from proved 27 F o r m 1 0 - K reserves and the PV-10 thereof for the oil and gas properties described in this report are based on the assumption that future oil and gas prices remain the same as oil and gas prices utilized in the December 31, 2009 report. The average realized sales prices used for purposes of such estimates were $55.05 per Bbl of oil and $3.42 per Mcf of gas. It is also assumed that we will make future capital expenditures of approximately $138.4 million in the aggregate primarily in the years 2010 through 2014, which are necessary to develop and realize the value of proved reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein. We file reports of our estimated oil and gas reserves with the Department of Energy. The reserves reported to this agency are required to be reported on a gross operated basis and therefore are not comparable to the reserve data reported herein. Proved Undeveloped Reserves At December 31, 2009, we had 11,052 MBbls of proved undeveloped reserves. During 2009 approximately 4,954 MBoes of December 31, 2008 proved undeveloped reserves were re-classified to the probable and possible categories as a result of the reserves having been on our reserve report for more than five years. None of the proved undeveloped reserves at December 31, 2008 were developed and re-classified to developed producing, during 2009. Reconciliation of Standardized Measure to PV-10 PV-10 is the estimated present value of the future net revenues from our proved oil and gas reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. Due to our loss carry-forwards and the tax basis of our properties, there is no impact of income taxes on our PV-10 calculation as a result, there is no difference between the standardized measure of our oil and gas reserves, which is a GAAP financial measure and the PV-10 of our reserves. The following matrix reflects Abraxas’ total proved reserves (MMBoe) and PV10 (in millions) at various price decks: Gas Price $4.00 $5.00 $6.00 $7.00 $8.00 $40.00 22.5 $ 62.4 23.5 $109.0 24.1 $156.8 24.6 $205.3 24.9 $254.3 Oil Price $60.00 24.6 $137.0 25.5 $184.1 26.1 $232.2 26.5 $280.9 26.8 $330.0 $70.00 25.3 $177.3 26.1 $224.4 26.7 $272.6 27.1 $321.3 27.4 $370.5 $80.00 25.8 $218.4 26.6 $265.6 27.1 $313.9 27.5 $362.6 27.8 $411.8 $50.00 23.7 $ 98.4 24.6 $145.3 25.2 $193.2 25.6 $241.9 26.0 $290.9 28 Oil and Gas Production and Sales Prices The following table presents our net oil and gas production, the average sales price per Bbl of oil and per Mcf of gas produced and the average cost of production per BOE of production sold, for the three years ended December 31, 2009: Oil production (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas production (Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total production (MBOE)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average sales price per Bbl of oil(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average sales price per Mcf of gas(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average sales price per BOE(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average cost of production per BOE produced(3) 196,944 5,567,668 1,125 69.22 5.98 41.70 10.02 $ $ $ $ 549,887 6,342,934 1,607 92.66 7.59 61.66 16.57 $ $ $ $ 578,784 6,329,216 1,634 54.14 3.24 31.73 16.05 $ $ $ $ 2007 2008 2009 (1) Oil and gas were combined by converting gas to a BOE equivalent on the basis 6 Mcf of gas to 1 Bbl of oil. (2) Before the impact of hedging activities. (3) Production costs include direct operating costs, ad valorem taxes and production taxes. Drilling Activities The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended December 31, 2009: 2007 2008 2009 Gross Net Gross Net Gross Net Exploratory Productive Oil Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dry holes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 1.0 1.0 — — 0.6 1.0 1.0 — — 1.0 0.6 — — — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.0 1.6 1.0 0.6 1.0 Development Productive 3.0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.0 Dry holes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.0 2.6 1.0 — 3.6 14.0 35.0 — 49.0 7.2 2.2 — 9.4 2.0 12.0 1.0 15.0 1.0 — — 1.0 2.0 0.2 1.0 3.2 Present Activities As of March 12, 2010, we had four operated wells and seven non-operated wells in process of drilling and/or completing. The following provides an overview of our present activities by region: Rocky Mountain: • • In the Bakken/Three Forks oil play in the Williston Basin, Abraxas is in the process of spacing and permitting its first two operated wells in the play. Both wells are located in eastern McKenzie County, North Dakota and will be drilled on 1,280 acre spacing units – one well will target the middle Bakken formation and the other well will target the underlying Three Forks formation. It is anticipated that each well will have horizontal laterals of approximately 9,000 feet and that each well will be completed with 20 or more stages of fracture stimulation. The first well is currently scheduled to spud in June. Abraxas continues to acquire leases in western North Dakota and eastern Montana as it fills out its existing acreage blocks in anticipation of additional operated drilling in the last half of 2010. In Divide County, North Dakota, Abraxas participated in what appears to be a successful Three Forks horizontal well for its 10.3% working interest. The well has been plagued with small mechanical issues, which combined with the shortage of oil field services in the area, has delayed completion. To date, the well has been fracture stimulated with 12 stages out of a planned 20. The remaining 8 stages are scheduled for March 18th. In the interim, the well has been flowing significant amounts of oil and gas while cleaning up fluid from the first 12 stages of fracture stimulation. 29 F o r m 1 0 - K • In Divide County, North Dakota, Abraxas committed for its 1.9% working interest in another Three Forks horizontal well to be drilled by one of the more active Bakken players. Mid-Continent: • In Hemphill County, Texas, Abraxas participated for its 8.3% working interest in a successful Granite Wash horizontal well operated by a large independent active in the play. The well was drilled to a total measured depth of 15,800 feet, including a 5,000 foot lateral, and completed with a 12-stage fracture stimulation. The well has been on production for several weeks and is currently flowing approximately 17.0 MMcf of liquids-rich gas and 500 Bbl of condensate, or 3,333 Boepd. Net to Abraxas’ interest, this production rate equates to approximately 200 Boepd plus natural gas liquids. Abraxas owns additional held-by-production acreage in this play. Permian Basin: • In Nolan County, Texas, the Spires Ranch 202 #1 tested oil out of the Ellenburger and Caddo formations and a test of the Strawn formation is pending. Despite concerns about formation pressures, the oil recovery and updated 3-D seismic evaluation has provided Abraxas with sufficient encouragement to drill two (2) additional wells in the near future. One vertical well will test the Strawn, Caddo and Ellenburger formations and a second horizontal well will evaluate the Strawn formation. Abraxas owns a 100% working interest in this play. Gulf Coast: • • • In the Eagle Ford shale play of South Texas, Abraxas continues to acquire acreage in geologically specific areas in anticipation of drilling its first Eagle Ford horizontal well later this year. In Bee County, Texas, Abraxas drilled the Bradford #1 in the first quarter of 2010 to a total depth of 10,300 feet. Casing has been set in the well to test several zones in the Wilcox formation after encouraging open hole logs and formation tests. Abraxas owns a 40% working interest in this well. In San Patricio County, Texas, Abraxas drilled two oil development wells in the first quarter of 2010. The Welder #86 and #87 were each drilled to a total depth of 8,700 feet. While drilling, both wells encountered a number of oil-prone horizons in the Frio formation and completion operations should be finished during the second quarter of 2010. Abraxas owns a 100% working interest in each of these wells. Office Facilities Our executive and administrative offices are located at 18803 Meisner Drive, San Antonio, Texas 78258, and consist of approximately 21,000 square feet. The building is owned by Abraxas, and is subject to a real estate lien note. The note bears interest at a fixed rate of 6.375%, and is payable in monthly installments of principal and interest of $39,754 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2009, $5.2 million was outstanding on the note. We lease office space in Calgary, Alberta for a monthly rental of $5,600CN. The lease expires on August 31, 2011. Other Properties We own 10 acres of land, an office building, workshop, warehouse and house in Sinton, Texas, 603 acres of land and an office building in Scurry County, Texas, 50 acres of land in Lavaca County, Texas, 160 acres of land in Coke County, Texas and 12,177 acres of land in Pecos County, Texas. We also own 22 vehicles which are used in the field by employees. We own two workover rigs, which are used for servicing our wells. Item 3. Legal Proceedings From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31, 2009, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on our financial condition. Item 4. (Removed and Reserved) 30 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Part II Securities Market Information Abraxas common stock began trading on the American Stock Exchange on August 18, 2000, under the symbol “ABP.” On July 25, 2008, Abraxas common stock began trading on The NASDAQ Stock Market under the symbol “AXAS”. The following table sets forth certain information as to the high and low sales price quoted for Abraxas’ common stock on the American Stock Exchange and NASDAQ. Period 2008 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter 2009 First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter High Low $4.35 5.41 5.31 2.48 $1.50 1.39 1.88 2.55 $3.11 3.25 2.15 0.65 $0.74 0.85 0.86 1.55 2010 First Quarter (Through March 12, 2010) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.50 $1.78 Holders As of March 12, 2010, Abraxas had 76,230,187 shares of common stock outstanding and had approximately 1,211 stockholders of record. Dividends Abraxas has not paid any cash dividends on its common stock and it is not presently determinable when, if ever, Abraxas will pay cash dividends in the future. In addition, our credit facility prohibits the payment of cash dividends on our common stock. F o r m 1 0 - K 31 Performance Graph Set forth below is a performance graph comparing yearly cumulative total stockholder return on the Abraxas common stock with (a) the monthly index of stocks included in the Standard and Poor’s 500 Index and (b) the Small Cap Index of stocks of oil and gas exploration and production companies with a market capitalization of less than $800 million (the “Comparable Companies”). The Comparable Companies are: American Oil & Gas Inc., Endeavour International Corporation., Evolution Petroleum Corp., Gulfport Energy Corp., GMX Resources Inc., Petroleum Development Corporation, PetroQuest Energy Inc., and Warren Resources Inc. All of these cumulative total returns are computed assuming the value of the investment in Abraxas common stock and each index as $100.00 on December 31, 2004, and the reinvestment of dividends at the frequency with which dividends were paid during the applicable years. The years compared are 2005, 2006, 2007, 2008 and 2009. $400.00 $350.00 $300.00 $250.00 $200.00 $150.00 $100.00 $50.00 $0.00 D ec-0 4 M ar-0 5 Ju n-0 5 Se p-0 5 D ec-0 5 M ar-0 6 Ju n-0 6 Se p-0 6 D ec-0 6 M ar-0 7 Ju n-0 7 Se p-0 7 D ec-0 7 M ar-0 8 Ju n-0 8 Se p-0 8 D ec-0 8 M ar-0 9 Ju n-0 9 Se p-0 9 D ec-0 9 Small Cap Index S&P 500 AXAS Dec. 31, 2004 Dec. 31, 2005 Dec. 31, 2006 Dec. 31, 2007 Small Cap Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S&P 500 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AXAS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $100.00 $100.00 $100.00 $197.41 $103.00 $227.59 $224.81 $117.03 $133.19 $279.59 $121.16 $166.38 Dec. 31, 2008 $99.52 $74.53 $31.03 Dec. 31, 2009 $138.15 $ 92.01 $ 82.76 The information contained above under the caption “Performance Graph” is being “furnished” to the Securities and Exchange Commission and shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate it by reference into such filing. 32 Item 6. Selected Financial Data The following selected financial data as of and for the years ended is derived from our Consolidated Financial Statements. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto, and other financial information included herein. See “Financial Statements” in Item 8. Year Ended December 31, 2005 2006 2007 2008 2009 Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income – discontinued operations . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per common share – diluted . . . . . . . . . . . . Weighted average shares outstanding – diluted (in $ 49,216(1) $ 51,077 $ 19,117(2) $ 700 $ 12,846(2) $ — 6,271(1) $ $ $ 0.46 $ (Dollars in thousands except per share data) $ 48,309 $ 52,750 $100,310 $ 56,702(3) $ (52,403)(4) $ (18,780) $ — $ 56,702 1.19 $ $ — $ (18,780) (0.34) $ $ — $ (52,403) (1.07) $ 700 0.02 thousands) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt, excluding current maturities . . . . . . . . . . . . . Total stockholders’ equity (deficit) . . . . . . . . . . . . . . . . . . . . . 41,164 $121,866 $129,527 $ (23,701) 43,862 $116,940 $127,614 $ (22,165) 47,593 $147,119 $ 45,900 $ 55,847 49,005 $211,839 $130,835 4,658 $ 55,499 $176,236 $143,592 $ (18,363) (1) Reflects continuing operations only. Discontinued operations in 2005 represent the results of operations of Grey Wolf Exploration, Inc. which was a wholly-owned Canadian subsidiary of Abraxas until February 2005. In February 2005, Grey Wolf completed its initial public offering resulting in the substantial divestiture of Abraxas’ investment in Grey Wolf. Includes gain on the sale of foreign subsidiary of $17.3 million net of non-cash tax of $6.1 million. Includes gain on sale of assets of $59.4 million. Includes proved property impairment of $116.4 million in 2008. (2) (3) (4) Item 7. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See “Financial Statements” in Item 8. General We are an independent energy company primarily engaged in the development and production of oil and gas. Historically, we have grown through the acquisition and subsequent development and exploitation of producing properties, principally through the redevelopment of old fields utilizing new technologies such as modern log analysis and reservoir modeling techniques as well as 3-D seismic surveys and horizontal drilling. As a result of these activities, we believe that we have a number of development opportunities on our properties. In addition, we intend to expand upon our development activities with complementary exploration projects in our core areas of operation. Success in our development and exploration activities is critical in the maintenance and growth of our current production levels and associated reserves. While we have attained positive net income from continuing operations in three of the last five years, there can be no assurance that operating income and net earnings will be achieved in future periods. Our financial results depend upon many factors which significantly affect our results of operations including the following: F o r m 1 0 - K • • • • • commodity prices and the effectiveness of our hedging arrangements; the level of total sales volumes of oil and gas; the availability of, and our ability to raise additional capital resources and provide liquidity to meet cash flow needs; the level of and interest rates on borrowings; and the level and success of exploration and development activity. Commodity Prices and Hedging Arrangements. The results of our operations are highly dependent upon the prices received for our oil and gas production. The prices we receive for our production are dependent upon spot market prices, price differentials and the effectiveness of our derivative contracts, which we sometimes refer to as hedging arrangements. Substantially all of our sales of oil and gas are made in the spot market, or pursuant to contracts based on spot market prices, 33 and not pursuant to long-term, fixed-price contracts. Accordingly, the prices received for our oil and gas production are dependent upon numerous factors beyond our control. Significant declines in prices for oil and gas could have a material adverse effect on our financial condition, results of operations, cash flows and quantities of reserves recoverable on an economic basis. Recently, the prices of oil and gas have been volatile. During 2007, oil prices remained strong while gas prices began 2007 strong but weakened during the course of the year. During the first half of 2008, prices for oil and gas were sustained at record or near-record levels, however, during the second half of 2008, and the first half of 2009 there was a significant drop in prices. Prices began to improve during the second half of 2009. New York Mercantile Exchange (NYMEX) futures price for West Texas Intermediate (WTI) oil averaged $99.73 per barrel for 2008. WTI oil ended 2008 at $44.60 per barrel. NYMEX Henry Hub futures price for gas averaged $8.85 per million British thermal units (MMBtu) during 2008 and ended the year at $5.62. For 2009, NYMEX futures price for WTI oil averaged $61.82 and ended 2009 at $79.36 per barrel. NYMEX Henry Hub futures price for gas averaged $3.94 per MMBtu during 2009 and ended the year at $5.81. If commodity prices decline, our revenue and cash flow from operations could also decline. In addition, lower commodity prices could also reduce the amount of oil and gas that we can produce economically. The current global recession has had a significant impact on commodity prices and our operations. If gas prices remain depressed or oil prices decline significantly, our revenues, profitability and cash flow from operations may decrease which could cause us to alter our business plans, including reducing our drilling activities. The decline in commodity prices during 2008 resulted in downward adjustments to our estimated proved reserves at December 31, 2008. For 2008 we incurred a “ceiling limitation write-down” under applicable accounting rules. Under these rules, if the net capitalized cost of our oil and gas properties exceeds the PV-10 of our reserves, we must charge the amount of the excess to earnings. As of December 31, 2008, the net capitalized costs of our oil and gas properties exceeded the present value of our estimated proved reserves by $116.4 million. These amounts were calculated considering 2008 year-end prices of $44.60 per Bbl of oil and $5.62 per Mcf of gas as adjusted to reflect the expected realized prices for each of our oil and gas reserves compared to the full cost pool. This charge did not impact cash flow from operating activities, but did reduce our stockholder’s equity and earnings. As of December 31, 2009, the net capitalized costs of our oil and gas properties did not exceed the present value of our estimated proved reserves. These amounts were calculated considering 2009 first-day-of-the-month average prices of $61.18 per Bbl of oil and $4.19 per Mcf of gas as adjusted to reflect the expected realized prices for each of our oil and gas reserves compared to the full cost pool. The risk that we will be required to write- down the carrying value of oil and gas properties increases when oil and gas prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. The realized prices that we receive for our production differ from NYMEX futures and spot market prices, principally due to: • • • basis differentials which are dependent on actual delivery location, adjustments for BTU content; and gathering, processing and transportation costs. During 2009, differentials averaged $7.67 per barrel of oil and $0.70 per Mcf of gas compared to $7.07 per barrel of oil and $1.30 per Mcf of gas in 2008 and $3.10 per barrel of oil and $1.00 per Mcf of gas in 2007. We experienced greater oil differentials during 2009 compared to prior years because of the increased percentage of our production from the Rocky Mountain and Mid-Continent regions which experience higher differentials than our Permian Basin and Gulf Coast properties. Approximately 43% of our production during 2009 was from our Rocky Mountain and Mid-Continent properties. As the percentage of our production from the Rocky Mountain and Mid-Continent regions increases, we expect that our price differentials will also increase. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations. Our credit facility also required us to enter into hedging arrangements for specified volumes, which equate to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2012 and 70% for 2013. By removing a significant portion of price volatility on our future oil and gas production, we believe we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations for those periods. 34 However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained and in the future will sustain realized and unrealized losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on our commodity derivative contracts. For example, in 2007, we sustained an unrealized loss of $6.3 million and a realized gain of $1.9 million. In 2008, we incurred a realized loss of $9.3 million and an unrealized gain of $40.5 million. In 2009 we incurred a realized gain of $17.9 million and an unrealized loss of $28.4 million. We have not designated any of these derivative contracts as a hedge as prescribed by applicable accounting rules. The following table sets forth our derivative position at December 31, 2009: Contract Periods Fixed Price Swap Oil Gas Daily Volume (Bbl) Swap Price Daily Volume (Mmbtu) Swap Price 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,158 1,035 946 705 $73.28 76.61 70.89 80.79 11,258 9,580 8,303 5,962 $5.73 6.52 6.77 6.84 At December 31, 2009, the aggregate fair market value of our oil and gas derivative contracts was a liability of approximately $14.0 million. Production Volumes. Because our proved reserves will decline as oil and gas are produced, unless we find, acquire or develop additional properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Approximately 93% of the estimated ultimate recovery of our proved developed producing reserves as of December 31, 2009 had been produced. Based on the reserve information set forth in our reserve estimates as of December 31, 2009, our average annual estimated decline rate for net proved developed producing reserves is 13% during the first five years, 8% in the next five years, and approximately 7% thereafter. These rates of decline are estimates and actual production declines could be materially higher. While we have had some success in finding, acquiring and developing additional reserves, we have not always been able to fully replace the production volumes lost from natural field declines and prior property sales. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. We had capital expenditures during 2009 of $16.5 million. We have a capital budget for 2010 of approximately $30.0 million. The final amount of our capital expenditures for 2010 will depend on our success rate, production levels, the availability of capital and commodity prices. The following table presents historical net production volumes for the years ended December 31, 2007, 2008 and 2009: Year Ended December 31, 2007 2008 2009 Total production (MBOE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average daily production (BOEpd) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,125 3,082 1,607 4,391 1,634 4,476 Availability of Capital. As described more fully under “Liquidity and Capital Resources” below, our sources of capital going forward will primarily be cash flow from operating activities, funding under our credit facility, cash on hand and proceeds from the sale of properties and is an appropriate opportunity presents itself, sales of debt or equity securities, although we may not be able to complete any financing on terms acceptable to us, if at all. As of December 31, 2009, we had $6.5 million of availability under our credit facility. Exploration and Development Activity. We believe that our high quality asset base, high degree of operational control and inventory of drilling projects position us for future growth. At December 31, 2009, we operated properties accounting for approximately 76% of our PV-10, giving us substantial control over the timing and incurrence of operating and capital expenditures. We have identified numerous additional drilling locations (of which 84 were classified as proved undeveloped at December 31, 2009) on our existing leaseholds the successful development of which we believe could significantly increase our production and proved reserves. Over the five years ended December 31, 2009, we drilled or participated in 89 gross (33.03 net) wells of which 95.5% resulted in commercially productive wells. 35 F o r m 1 0 - K Our future oil and gas production, and therefore our success, is highly dependent upon our ability to find, acquire and develop additional reserves that are profitable to produce. The rate of production from our oil and gas properties and our proved reserves will decline as our reserves are produced unless we acquire additional properties containing proved reserves, conduct successful development and exploration activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves. We cannot assure you that our exploration and development activities will result in increases in our proved reserves. If our proved reserves decline in the future, our production may also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility will also decline. In addition, approximately 44% of our estimated proved reserves at December 31, 2009 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may be unable to acquire or develop additional reserves, in which case our results of operations and financial condition could be adversely affected. Borrowings and Interest. At December 31, 2009, we had a total of $146.5 million outstanding under our credit facility and availability of $6.5 million. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our numerous drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR-based debt. The two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% expires on August 12, 2010. This interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009, lowering our fixed rate to 2.55% on the swap, and extending the term through August 12, 2012. Results of Operations Selected Operating Data. The following table sets forth certain of our operating data for the periods presented. Average prices reflect realized prices excluding the impact of hedging activities. Years Ended December 31, (dollars in thousands, except per unit data.) 2008 2007 2009 Operating revenue(1): Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,633 33,273 1,403 $ 50,954 48,130 1,226 $ 31,340 20,489 921 Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48,309 $100,310 $ 52,750 Operating income (loss)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 15,524 $ (74,017) $ 177 Oil production (MBbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas production (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 196.9 5,567.7 549.9 6,342.9 578.8 6,329.2 Average oil sales price (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average gas sales price (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 69.22 5.98 $ $ $ 92.66 7.59 $ 54.15 3.24 $ (1) Revenue is before the impact of hedging activities. (2) Operating loss in 2008 includes a $116.4 million proved property impairment. Comparison of Year Ended December 31, 2009 to Year Ended December 31, 2008 Operating Revenue. During the year ended December 31, 2009, operating revenue from oil and gas sales decreased by $47.3 million from $99.1 million in 2008 to $51.8 million in 2009. The decrease in revenue was due to lower oil and gas prices in 2009 as compared to 2008 which were partially offset by increased production volumes in 2009 as compared to 2008. The decrease in commodity prices had negative impact of $49.8 million while increased production volumes contributed $2.5 million to revenue. Oil production volumes increased from 549.9 MBbls for the year ended December 31, 2008 to 578.8 MBbls for the same period of 2009, primarily due to production from new wells placed on production during 2009. Gas production volumes decreased from 6,343 MMcf for the year ended December 31, 2008 to 6,329 MMcf for the same period of 2009, primarily due to natural field declines. 36 Average sales prices in 2009, before realized gain (loss) on derivative contracts were: • • $54.15 per Bbl of oil, and $3.24 per Mcf of gas. Average sales prices in 2008, before realized gain (loss) on derivative contracts were: • • $92.66 per Bbl of oil, and $7.59 per Mcf of gas. Lease Operating Expense and Production Taxes. Lease operating expense (LOE), decreased from $26.6 million in 2008 to $26.2 million in 2009 as a result of lower operating costs. LOE per BOE for the year ended December 31, 2009 was $16.05 per BOE compared to $16.57 for the same period of 2008. The decrease in per BOE was attributable to lower lease operating expenses. G&A Expense. General and administrative expense, or G&A, excluding stock-based compensation increased from $5.7 million in 2008 to $6.5 million in 2009. The increase in G&A expenses in 2009 as compared to 2008 was primarily due to higher professional and consulting fees, as well as increased cost for director fees related to the Merger. G&A expense per BOE was $3.96 for 2009 compared to $3.56 for the same period of 2008. The increase per BOE cost was attributable to the higher G&A during 2009 as compared to 2008. Stock-based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. In addition to options, restricted shares of common stock have been granted. For the years ended December 31, 2009 and 2008, stock-based compensation was approximately $1.2 million and $1.4 million, respectively. The decrease in 2009 as compared to 2008 was due to expenses related to higher valued options granted in prior years that have been fully amortized. DD&A Expense. Depreciation, depletion and amortization, (DD&A) expense decreased from $23.3 million in 2008 to $17.9 million in 2009. The decrease in DD&A was primarily the result of the producing property impairment in 2008 which reduced our full cost pool. Our DD&A per BOE for 2009 was $10.95 per BOE as compared to $14.53 per BOE in 2008. The decrease on a per BOE basis in 2009 was primarily the result of the book value of our full cost pool being reduced, due the impairment incurred in 2008. Interest Expense. Interest expense increased to $11.3 million in 2009 compared to $10.5 million for 2008. The increase in interest expense was primarily due to higher interest rates. Income taxes. For the year ended December 31, 2009 we incurred $1.3 million in federal and state income taxes. The taxes were the result of a tax basis gain on the merger of Abraxas Energy Partners into Abraxas Petroleum. No income tax expense or benefit has been recognized due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits. Income (loss) from derivative contracts. We account for derivative contract gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The estimated value of our derivative contracts was a liability of approximately $16.3 million as of December 31, 2009. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the year ended December 31, 2009, we realized a gain on our derivative contracts of $15.3 million, which included a realized gain of $17.9 million on our commodity swaps and a realized loss of $2.6 million on our interest rate swap. For the year-ended December 31, 2009, we incurred an unrealized loss of $27.6 million, which included an unrealized loss of $28.4 million on our commodity swaps and an unrealized gain of $0.8 million on our interest rate swap. For the year ended December 31, 2008, we realized a loss on our derivative contracts of $9.5 million and we incurred an unrealized gain of $37.9 million. Other Expense. For the year ended December 31, 2008, as the result of the exchange and registration rights agreement whereby Partnership unitholders, under certain circumstances could convert their Partnership units into Abraxas common 37 F o r m 1 0 - K stock, we recognized an expense of $7.4 million, including approximately $293,000 relating to shares converted during the fourth quarter of 2008 and $7.1 million representing the fair value of potential conversions. During 2009, other expense consisted primarily of costs related to the planned initial public offering of the Partnership, which had previously been capitalized. Ceiling Limitation Write-down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders’ equity. In accordance with new SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using average price over the prior 12-month period. As of December 31, 2008, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $116.4 million. These amounts were calculated in accordance with previous SEC rules considering 2008 year-end prices of $44.60 per Bbl for oil and $5.62 per Mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves as compared to the full cost pool. As of December 31, 2009, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves. The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long- term contracts for our gas. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required. Based on managements’ review of average first-day-of-the-month prices for the twelve months April 2009 through March 2010, we do not anticipate a write down at the end of the first quarter of 2010. Non-Controlling Interest. Non-controlling interest represents the share of the net income (loss) of the Partnership for the period owned by the partners other than Abraxas. Additionally, in accordance with generally accepted accounting principles in effect at the time, when cumulative losses applicable to the non-controlling interest exceed the non-controlling interest equity capital in the entity, such excess and any further losses applicable to the non-controlling interest are charged to the earnings of the controlling interest. If future earnings are recognized by the non-controlling interest, such earnings will then be credited to the controlling interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. For the year ended December 31, 2008, primarily as a result of the ceiling test impairment, losses applicable to the non-controlling interest exceeded the controlling interest equity capital by $9.3 million. As a result, $9.3 million of the non-controlling interest loss in excess of equity was charged to earnings attributable to Abraxas and was reflected as a reduction of the loss applicable to the non-controlling interest. Comparison of Year Ended December 31, 2008 to Year Ended December 31, 2007 Operating Revenue. During the year ended December 31, 2008, operating revenue from oil and gas sales increased by $52.2 million from $46.9 million in 2007 to $99.1 million in 2008. The increase in revenue was due to increased production volumes in 2008 as compared to 2007 as well as higher oil and gas prices realized in 2008 as compared to 2007. The increase in production volumes contributed $29.1 million to revenue while increased commodity prices contributed $23.1 million to oil and gas revenue. Oil production volumes increased from 196.9 MBbls for the year ended December 31, 2007 to 549.9 MBbls for the same period of 2008. The increase in oil volumes was primarily due to production from properties acquired in the St. Mary acquisition that closed on January 31, 2008. Production for the year ended December 31, 2008 from these properties added 313.4 MBbls of oil. Gas production volumes increased from 5,568 MMcf for the year ended December 31, 2007 to 6,343 MMcf for the same period of 2008. The properties acquired in the St. Mary acquisition contributed 1,566 MMcf of gas production during the year, which was partially offset by natural field declines. 38 Average sales prices in 2008, before realized gain (loss) on derivative contracts were: • • $92.66 per Bbl of oil, and $7.59 per Mcf of gas. Average sales prices in 2007, before realized gain (loss) on derivative contracts were: • • $69.22 per Bbl of oil, and $5.98 per Mcf of gas. Lease Operating Expense and Production Taxes. LOE increased from $11.3 million in 2007 to $26.6 million in 2008. The increase in LOE was primarily due to the properties acquired from St. Mary in January of 2008 as well as an increase in ad valorem and severance taxes. Severance and ad valorem taxes increased from $3.8 million in 2007 to $9.1 million in 2008. LOE related to the properties acquired in the St. Mary property acquisition added $13.1 million to LOE during 2008. LOE per BOE for the year ended December 31, 2008 was $16.57 per BOE compared to $10.02 for the same period of 2007. The increase per BOE was attributable to the increase in the number of oil wells as a result of the St. Mary acquisition, which are generally more expensive to operate than gas wells, as well as the overall increase in costs. G&A Expense. G&A expense, excluding stock-based compensation, increased from $5.4 million in 2007 to $5.7 million in 2008. The increase in G&A was primarily due to higher personnel expenses associated with additional staff added to manage the properties acquired from St. Mary. G&A per BOE was $3.56 for 2008 compared to $4.84 for the same period of 2007. The decrease per BOE was attributable to the higher G&A expense being offset by higher production volumes during 2008 as compared to 2007. Stock-based Compensation. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. In addition to options, restricted shares of common stock have been granted. For the year ended December 31, 2008 and 2007, stock-based compensation was approximately $1.4 million and $996,000, respectively. DD&A Expense. DD&A expense increased from $14.3 million in 2007 to $23.3 million in 2008. The increase in DD&A was primarily the result of increased production as well as an increase in the depletion base as a result of the St. Mary acquisition. Our DD&A expense per BOE for 2007 was $12.71 per BOE as compared to $14.53 per BOE in 2008. The per BOE increase was due to the increased production volumes in 2008 as compared to 2007. Interest Expense. Interest expense increased to $10.5 million in 2008 compared to $8.4 million in 2007. The increase in interest expense was primarily due to the increase in long term debt incurred with the St. Mary acquisition. Long-term debt as of December 31, 2008 was $165.6 million compared to $45.9 million as of December 31, 2007. Income taxes. No current or deferred income tax expense or benefit has been recognized due to losses or loss carryforwards and valuation allowance, which has been recorded against such benefits. Income (loss) from derivative contracts. We account for derivative contract gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps and interest rate swaps. The estimated unearned value of our derivative contracts was an asset of approximately $39.2 million as of December 31, 2008. When our derivative contract prices are higher than prevailing market prices, we incur realized and unrealized gains and conversely, when our derivative contract prices are lower than prevailing market prices, we incur realized and unrealized losses. For the year ended December 31, 2008, we realized a loss on our derivative contracts of $9.5 million and an unrealized gain of $37.9 million. For the year ended December 31, 2007, we realized a gain on our derivative contracts of $1.9 million and we incurred an unrealized loss of $6.3 million. Other Expense. For the year ended December 31, 2008 as the result of the exchange and registration rights agreement whereby Partnership unitholders, under certain circumstances could convert their Partnership units into Abraxas common stock, we recognized an expense of $7.4 million, including approximately $293,000 relating to shares converted during the fourth quarter of 2008 and $7.1 million representing the fair value of potential conversions. 39 F o r m 1 0 - K Ceiling Limitation Write-down. We record the carrying value of our oil and gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of oil and gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of oil and gas properties exceeds the ceiling limit, we are subject to a ceiling limitation write-down to the extent of such excess. A ceiling limitation write-down is a charge to earnings which does not impact cash flow from operating activities. However, such write-downs do impact the amount of our stockholders’ equity. The cost ceiling, under SEC rules in effect at the time, represents the present value (discounted at 10%) of net cash flows from sales of future production, using commodity prices on the last day of the year, or alternatively, if prices subsequent to that date have increased, a price near the periodic filing date of the our financial statements. As of December 31, 2008, our net capitalized costs of oil and gas properties exceeded the present value of our estimated proved reserves by $116.3 million. These amounts were calculated considering 2008 year-end prices of $44.60 per Bbl for oil and $5.62 per Mcf for gas as adjusted to reflect the expected realized prices for our oil and gas reserves as compared to the full cost pool. The risk that we will be required to write-down the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, write-downs may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long- term contracts for our gas. We cannot assure you that we will not experience additional write-downs in the future. If commodity prices decline or if any of our proved reserves are revised downward, a further write-down of the carrying value of our oil and gas properties may be required. Non-Controlling Interest. Non-controlling interest represents the share of the net income (loss) of the Partnership for the period owned by the partners other than Abraxas. Additionally, in accordance with generally accepted accounting principles in effect at the time, when cumulative losses applicable to the non-controlling interest exceed the non-controlling interest equity capital in the entity, such excess and any further losses applicable to the non-controlling interest are charged to the earnings of the controlling interest. If future earnings are recognized by the non-controlling interest, such earnings will then be credited to the controlling interest (Abraxas) to the extent of such losses previously absorbed and any excess earnings will increase the recorded value. For the year ended December 31, 2008, primarily as a result of the ceiling test impairment, losses applicable to the non-controlling interest exceeded the controlling interest equity capital by $9.3 million and, as a result, $9.3 million of the non-controlling interest loss in excess of equity was charged to earnings and was reflected as a reduction of the loss applicable to the non-controlling interest. Liquidity and Capital Resources General. The oil and gas industry is a highly capital intensive and cyclical business. Our capital requirements are driven principally by our obligations to service debt and to fund the following costs: • • • the development of existing properties, including drilling and completion costs of wells; acquisition of interests in additional oil and gas properties; and production and transportation facilities. The amount of capital expenditures we are able to make has a direct impact on our ability to increase cash flow from operations and, thereby, will directly affect our ability to service our debt obligations and to continue to grow the business through the development of existing properties and the acquisition of new properties. Our principal sources of capital going forward will be cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete any financings on terms acceptable to us, if at all. Working Capital (Deficit). At December 31, 2009, our current liabilities of $28.9 million exceeded our current assets of $11.5 million resulting in working capital deficit of $17.4 million. This compares to working capital deficit $26.0 million as of December 31, 2008. Current liabilities as of December 31, 2009 consisted of trade payables of $8.8 million, revenues due third parties of $3.6 million, other accrued liabilities of $1.4 million, current derivative liabilities of $7.0 million and current maturities of long-term debt of $8.1 million. 40 Capital Expenditures. Capital expenditures in 2007, 2008 and 2009 were $26.9 million, $174.6 million and $16.5 million, respectively. The table below sets forth the components of these capital expenditures for the three years ended December 31, 2009. Year Ended December 31, 2007 2008 2009 (dollars in thousands) Expenditure category: Exploration/Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Facilities and other $16,793 10,000 115 $ 40,564 127,671 6,351 $16,151 — 320 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $26,908 $174,586 $16,471 During 2007, capital expenditures were primarily for the development of existing properties and a deposit for the St. Mary property acquisition that closed in January 2008. During 2008 capital expenditures included $127.7 million for the acquisition of the St. Mary properties and other smaller acquisitions, as well as the development of our oil and gas properties. During 2009, capital expenditures were primarily for the development of existing properties. We anticipate making capital expenditures for 2010 of $30.0 million. These anticipated expenditures are subject to adequate cash flow from operations and availability under our credit facility. If these sources of funding do not prove to be sufficient, we may also issue additional shares of equity securities or sell debt securities, although we may not be able to complete any financings on terms acceptable to us, if at all. Our ability to make all of our budgeted capital expenditures will also be subject to availability of drilling rigs and other field equipment and services. Our capital expenditures could also include expenditures for the acquisition of producing properties if such opportunities arise. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. There has been a significant decline in oil and gas prices since the second quarter of 2008, while oil prices improved during the second half of 2009, gas prices remain fairly weak. Should the prices of oil and gas decline and if our costs of operations increase or if our production volumes decrease, our cash flows will decrease which may result in a reduction of the capital expenditures budget. If we decrease our capital expenditures budget, we may not be able to offset oil and gas production decreases caused by natural field declines and sales of producing properties. Sources of Capital. The net funds provided by and/or used in each of the operating, investing and financing activities are summarized in the following table and discussed in further detail below: Year Ended December 31, 2007 2008 2009 (dollars in thousands) Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash (used in) provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 18,332 (26,908) 27,469 $ 43,387 $ 44,136 (14,096) (30,103) (173,944) 113,545 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 18,893 $ (17,012) $ (63) Operating activities for the year ended December 31, 2009 provided $44.1 million in cash. Net income plus non-cash expense items and net changes in operating assets and liabilities and the monetization of our derivative contracts accounted for most of these funds. Financing activities used $30.1 million for the year ended December 31, 2009 which was predominately the reduction of long-term debt. Investing activities used $14.1 million in 2009 for the development of our oil and gas properties. Operating activities for the year ended December 31, 2008 provided $43.4 million in cash. Net income plus non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds, including the non–cash proved property impairment of $116.4 million. Financing activities provided $113.5 million for the year ended December 31, 2008, including proceeds of long-term borrowing in connection with the St. Mary acquisition. Investing activities used $173.9 million in 2008, including $127.7 million for the St. Mary acquisition as well as the development of our oil and gas properties. Operating activities for the year ended December 31, 2007 provided $18.3 million in cash. Net income plus non-cash expense items and net changes in operating assets and liabilities accounted for most of these funds. Financing activities provided $27.5 million for the year ended December 31, 2007, including proceeds from the issuance of common stock, 41 F o r m 1 0 - K proceeds from the sale of common units of the Partnership and proceeds from the Partnership’s and Abraxas’ credit facilities. Investing activities used $26.9 million during the year ended December 31, 2007, including $16.9 million for the development of our oil and gas properties and $10 million for the St. Mary property acquisition that was completed in January 2008. Future Capital Resources. Our principal sources of capital are cash flow from operations, borrowings under our credit facility, cash on hand, proceeds from the sale of properties, and if an opportunity presents itself, the sale of debt or equity securities, although we may not be able to complete financing on terms acceptable to us, if at all. Cash from operating activities is dependent upon commodity prices and production volumes. Oil and gas prices are volatile and declined significantly during the second half of 2008 and continued to decline during the first part of 2009. Oil prices have strengthened during the second half of 2009 and while gas prices have strengthened somewhat, they remain weak. The decline in commodity prices has significantly reduced our cash flow from operations. As the result of the global recession, commodity prices may stay depressed which could further reduce our cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Our cash flow from operations will also depend upon the volume of oil and gas that we produce. Unless we otherwise expand reserves, our production volumes may decline as reserves are produced. In the future we may continue to sell non-core producing properties, which could further reduce our production volumes. To offset the loss in production volumes resulting from natural field declines and sales of producing properties, we must conduct successful exploration and development activities, acquire additional producing properties or identify additional behind-pipe zones or secondary recovery reserves. We believe our numerous drilling opportunities will allow us to increase our production volumes; however, our drilling activities are subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be found. If our proved reserves decline in the future, our production will also decline and, consequently, our cash flow from operations and the amount that we are able to borrow under our credit facility will also decline. The risk of not finding commercially productive reservoirs will be compounded by the fact that 44% of our total estimated proved reserves at December 31, 2009 were classified as undeveloped. We could also seek capital through the sale of debt and equity securities. The current state of the equity and debt markets will have a significant impact on our ability to sell debt or equity securities on terms as favorable as those which existed prior to the current crisis. Contractual Obligations. We are committed to making cash payments in the future on the following types of agreements: • • Long-term debt Operating leases for office facilities Below is a schedule of the future payments that we are obligated to make based on agreements in place as of December 31, 2009. Contractual Obligations (in thousands) Payments due in twelve month periods ending: Total December 31, 2010 December 31, 2011-2012 December 31, 2013-2014 Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-Term Debt(1) Interest on long-term debt(2) . . . . . . . . . . . . . . . . . . . . . . . . . Lease obligations(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $151,733 24,102 112 $ 8,141 8,614 67 $138,817 14,752 45 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $175,947 $16,822 $153,614 $357 596 — $953 $4,418 140 — $4,558 (1) These amounts represent the balances outstanding under our credit facility. These repayments assume that we will not borrow additional funds. (2) (3) Lease on office space in Calgary, Alberta, which expires on August 31, 2011. Interest expense assumes the balances of long-term debt at the end of the period and current effective interest rates. We maintain a reserve for costs associated with the retirement of tangible long-lived assets. At December 31, 2009, our reserve for these obligations totaled $10.3 million for which no contractual commitments exist. For additional information relating to this obligation, see Note 1 of Notes to Consolidated Financial Statements. Off-Balance Sheet Arrangements. At December 31, 2009, we had no existing off-balance sheet arrangements, as defined under SEC regulations, that have or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. 42 Contingencies. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. At December 31, 2009 we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us. Other obligations. We make and will continue to make substantial capital expenditures for the acquisition, exploration, development and production of oil and gas. In the past, we have funded our operations and capital expenditures primarily through cash flow from operations, sales of properties, sales of production payments and borrowings under our credit facilities and other sources. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion. Long-Term Indebtedness Long-term debt consisted of the following: Partnership credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partnership subordinated credit agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Credit facility – Term portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Credit facility – Revolving portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Real estate lien note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $125,600 40,000 — — 5,369 $ — — 8,000 138,500 5,233 December 31, 2008 December 31, 2009 Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170,969 (40,134) 151,733 (8,141) $130,835 $143,592 Abraxas Senior Secured Credit Facility On June 27, 2007, Abraxas entered into a senior secured revolving credit facility, which was amended on February 4, 2009, May 13, 2009 and August 7, 2009. This credit facility was refinanced, amended and restated by the credit facility entered into on October 5, 2009. Amended and Restated Partnership Credit Facility On May 25, 2007, the Partnership entered into a senior secured revolving credit facility which was amended and restated on January 31, 2008 and further amended on January 16, 2009, April 30, 2009, May 7, 2009, June 30, 2009 and July 22, 2009, which we refer to as the Partnership Credit Facility. The Partnership Credit Facility was refinanced, amended and restated by the credit facility entered into on October 5, 2009. F o r m 1 0 - K Subordinated Credit Agreement On January 31, 2008, the Partnership entered into a subordinated credit agreement which was amended on January 16, 2009 and further amended on April 30, 2009, May 7, 2009, June 30, 2009, July 22, 2009, August 13, 2009 and August 31, 2009, which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement was refinanced, amended and restated by the credit facility entered into on October 5, 2009. Credit Facility On October 5, 2009, in connection with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. In connection with the Merger, we refinanced, amended and restated the Partnership Credit Facility, the Subordinated Credit Agreement and Abraxas’ previous credit facility and we borrowed $145.0 million under the credit facility, of which $135.0 million was borrowed under the revolving portion and $10.0 million was borrowed under the term loan portion of the credit facility. As of December 31, 2009, $138.5 million was outstanding under the revolving portion of the credit facility and $8.0 million was outstanding under the term loan portion of the facility. The revolving portion of the credit facility has a maximum commitment of $300.0 million and availability under the revolving portion of the credit facility will be subject to a borrowing base. The borrowing base under the revolving portion of 43 the credit facility is currently $145.0 million and will be determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base will be calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, will be able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we will be able to request one redetermination during any six-month period between scheduled redeterminations. The lenders will also be able to make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base of $145.0 million was determined based upon our reserve report dated June 1, 2009. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the revolving portion of the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization of the borrowing base. At December 31 2009, the interest rate on the revolving portion of the credit facility was 5.75%. We also borrowed $10.0 million under the term loan portion of the credit facility at the closing of the Merger. Outstanding amounts under the term loan portion of the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 4.75%, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 5.75%. At December 31, 2009, the interest rate on the term loan portion of the credit facility was 7.75%. The term loan portion of the credit facility is subject to amortization beginning on January 31, 2010. The first amortization installment of $1.0 million is due on January 31, 2010 and the second amortization installment of $3.0 million is due on March 31, 2010; thereafter, a quarterly amortization installment of $2.0 million is due at the end of each quarter until the term loan is repaid. It is anticipated that the term loan will be repaid on or before December 31, 2010, after which, it may not be redrawn. The term loan portion of the credit facility was paid down to $8.0 million at December 31, 2009 and on January 29, 2010 an additional $3.0 million was paid. The balance of the term portion of the credit facility was $5.0 million as of January 29, 2010. Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is October 5, 2012. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements. Each of our subsidiaries (other than Canadian Abraxas Petroleum Corporation) has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter of not less than 2.50 to 1.00. We are also required to maintain a total debt to EBITDAX ratio as of the last day of each quarter of not more than 4.50 to 1.00 for the quarter ending September 30, 2009 through the quarter ending September 30, 2010, and not more than 4.00 to 1.00 thereafter. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with or at the request of a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 (which relates to derivative instruments and hedging activities and was previously referred to as SFAS 133) and ASC 410-20 (which relates to asset retirement obligations previously referred to as SFAS 143) and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date after giving pro forma effect to the Merger. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718 (which relates to stock-based compensation and was previously referred to as SFAS 123R), ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts or upon the termination of any hedge contract minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of ASC 815 and ASC 44 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date after giving pro forma effect to the Merger. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, and obligations with respect to surety bonds and hedge arrangements. The credit facility also required that we enter into hedging arrangements for specified volumes, which equate to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2012 and 70% for 2013. We satisfied this requirement by assuming all of the Partnership’s derivative contracts in connection with the Merger. The following table sets forth our derivative contract position as of December 31, 2009: Contract Periods 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed Price Swap Oil Gas Daily Volume (Bbl) 1,158 1,035 946 705 Swap Price $73.28 76.61 70.89 80.79 Daily Volume (Mmbtu) 11,258 9,580 8,303 5,962 Swap Price $5.73 6.52 6.77 6.84 In addition to the foregoing and other customary covenants, the credit facility contains a number of covenants that, among other things, restrict our ability to: • • • • • • incur or guarantee additional indebtedness; transfer or sell assets; create liens on assets; engage in transactions with affiliates other than on an “arm’s-length” basis; make any change in the principal nature of our business; and permit a change of control. The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. We were in compliance with all covenants as of December 31, 2009. As of December 31, 2009, the current ratio was 1.29 to 1.00, the interest coverage ratio was 4.75 to 1.00 and the total debt to EBITDAX ratio was 2.32 to 1.00. Real Estate Lien Note On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to serve as its corporate headquarters. This note was refinanced in November 2008. The note bears interest at a fixed rate of 6.375%, and is payable in monthly installments of principal and interest of $39,754 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2009, $5.2 million was outstanding on the note. Hedging Activities Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments. Under the terms of the Partnership Credit Facility, the Partnership entered into derivative contracts, which we sometimes refer to as hedging arrangements for specified volumes, which equated to approximately 80% of the estimated oil and gas production through December 31, 2012 from its net proved developed producing reserves. On July 29, 2009, the derivative 45 F o r m 1 0 - K contracts for the periods 2009 through 2011 were monetized for $26.7 million and together with the July 2009 commodity swap settlement of $2.0 million, the Partnership repaid $28.7 million of indebtedness under the Partnership Credit Agreement on July 31, 2009. Simultaneously, the Partnership entered into new commodity swaps on approximately 85% of its estimated oil and gas production from its net proved developed producing reserves through December 31, 2012 and on 70% for the calendar year 2013. As a result of the Merger, all of the Partnership’s derivative contracts were assumed by Abraxas. The following table sets forth our derivative contract position as of December 31, 2009: Contract Period 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed-Price Swaps Oil Gas Daily Volume (Bbl) 1,158 1,035 946 705 Swap Price $73.28 76.61 70.89 80.79 Daily Volume (Mmbtu) 11,258 9,580 8,303 5,962 Swap Price $5.73 6.52 6.77 6.84 By removing a significant portion of price volatility on our future oil and gas production, we believe that we will mitigate, but not eliminate, the potential effects of changing commodity prices on our cash flow from operations. However, when prevailing market prices are higher than our contract prices, we will not realize increased cash flow on the portion of the production that has been hedged. We have sustained, and in the future will sustain, realized and unrealized losses on our derivative contracts if market prices are higher than our contract prices. Conversely, when prevailing market prices are lower than our contract prices, we will sustain realized and unrealized gains on our commodity derivative contracts. For example, in 2007, we sustained an unrealized loss of $6.3 million and a realized gain of $1.9 million and in 2008 we incurred a realized loss of $9.3 million and an unrealized gain of $40.5 million. For the year ended December 31, 2009, we incurred a realized gain of approximately $17.9 million and an unrealized loss of approximately $28.4 million on all of our commodity derivative contracts. If the disparity between our new contract prices and market prices continues, we will sustain realized and unrealized gains or losses on our derivative contracts. While unrealized gains and losses do not impact our cash flow from operations, realized gains and losses do impact our cash flow from operations. In addition, as our derivative contracts expire over time, we expect to enter into new derivative contracts at then-current market prices. If the prices at which we hedge future production are significantly lower than our existing derivative contracts, our future cash flow from operations would likely be materially lower. In addition, the borrowings under our new credit facility will bear interest at floating rates. If interest expense increases as a result of higher interest rates or increased borrowings, more cash flow from operations would be used to meet debt service requirements. As a result, we would need to increase our cash flow from operations in order to fund the development of our numerous drilling opportunities which, in turn, will be dependent upon the level of our production volumes and commodity prices. See “—Quantitative and Qualitative Disclosures about Market Risk—Hedging Sensitivity” for further information. Net Operating Loss Carryforwards At December 31, 2009, we had, subject to the limitation discussed below, $121.7 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire through 2028 if not utilized. Uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under ASC 740-10. Therefore, we have established a valuation allowance of $91.5 million for deferred tax assets at December 31, 2009. We account for uncertain tax positions under provisions of ASC 740-10. ASC 740-10 did not have any effect on the Company’s financial position or results of operations as of January 1, 2007 or for the year ended December 31, 2009. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2009, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2009 remain open to examination by the tax jurisdictions to which the Company is subject. Related Party Transactions Abraxas has adopted a policy that transactions between Abraxas and its officers, directors, principal stockholders, or affiliates of any of them, will be on terms no less favorable to Abraxas than can be obtained on an arm’s length basis in transactions with third parties and must be approved by the vote of at least a majority of the disinterested directors. 46 Environmental Regulations Various foreign, federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect our operations and costs as a result of their effect oil and gas exploration, development and production operations. These laws and regulations could cause us to incur remediation or other corrective action costs in connection with a release of regulated substances, including oil, into the environment. In addition, we have acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under our control, and under environmental laws and regulations, we could be required to remove or remediate wastes disposed of or released by prior owners or operators. We also could incur costs related to the clean-up of sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such sites. In addition, we could be responsible under environmental laws and regulations for oil and gas properties in which we own an interest but are not the operator. Moreover, we are subject to the United States Environmental Protection Agency’s (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG) emissions. Compliance with such laws and regulations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition, results of operations or competitive position. It is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to our total exploration and development expenditure program in order to comply with such laws and regulations, but, inasmuch as such laws and regulations are frequently changed, we are unable to predict the ultimate cost of compliance or the effect on our operations, financial condition, results of operations and competitive position. We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. In addition to the U.S. EPA’s rule requiring annual reporting of GHG emissions, we are also aware of legislation proposed by United States lawmakers to reduce GHG emissions. We are unable to predict the timing, scope and effect of any such proposed laws, regulations and treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations, financial condition and competitive position. We believe that our strategy to reduce GHG emissions throughout our operations is in the best interest of the environment and a generally good business practice. We will continue to review the risks to our business and operations associated with all environmental matters, including climate change. In addition, we will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. Critical Accounting Policies The preparation of financial statements in conformity with generally accepted accounting principles requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities in the financial statements. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Oil and Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in oil and gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities but do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our oil and gas properties. 47 F o r m 1 0 - K At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. We have experienced this situation several times over the years, most recently in 2008. Our oil and gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from impairment testing procedures associated with the full cost method of accounting as discussed below. Under full cost accounting rules, the net capitalized cost of oil and gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves on a pool by pool basis, discounted at 10%, plus the lower of cost or fair market value of unproved properties and the cost of properties not being amortized, less income taxes. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This charge does not impact cash flow from operating activities, but does reduce our stockholders’ equity and reported earnings. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are depressed. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. Estimates of Proved Oil and Gas Reserves. Estimates of our proved reserves included in this report are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and SEC guidelines. The accuracy of a reserve estimate is a function of: • • • • the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. Our proved reserve information included in this report was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. For the year ended December 31, 2009, oil and gas prices were based on the average 12-month first-day-of-the-month pricing as compared to end of period prices in prior years. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense. Accounting for Derivatives. We account for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contract are recognized in earnings during the current period. Our derivative contracts consist of commodity swaps 48 and interest rate swaps. Due to the volatility of oil and gas prices and, to a lesser extent, interest rates, our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2008 and 2009, the net market value of our oil and gas derivatives was a net asset of $39.2 million and a liability of $14.0 million, respectively. The market value of our interest rate derivative was a liability of $3.0 million and $2.3 million at December 31, 2008 and 2009, respectively. Share-Based Payments. We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Additional information about management’s assumptions can be found in footnote 6 to the consolidated financial statements. Options granted to employees and directors are valued at the date of grant and expense is recognized over the options vesting period. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. For the years ended December 31, 2007, 2008 and 2009, stock based compensation was approximately $996,000, $1.4 million and $1.2 million, respectively. Recent Accounting Pronouncements In December 2008, the Securities and Exchange Commission adopted rule changes to modernize its oil and gas reporting disclosures. The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago. New disclosure requirements include: • • • • • Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Enabling companies to additionally disclose their probable and possible reserves to investors. Allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves. Requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit. Requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period – rather than the year-end price – to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date. In December 2009, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules which were issued by the SEC. The use of 12-month average prices, as opposed to year end prices, in calculating the present value of our reserves, resulted in a reduction of the standardized measure of discounted future net cash flows of approximately $139.3 million and 1,973.8 MBOE at December 31, 2009. Additionally, the change resulted in a $335,000 increase in DD&A expense in the fourth quarter of 2009. In August 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-05, Fair Value Measurements and Disclosures (ASU 2009-05). ASU 2009-05 amends Subtopic 820-10, Fair Value Measurements and Disclosures, to provide guidance on the fair value measurement of liabilities. ASU 2009-05 provides clarification for circumstances in which a quoted price in an active market for the identical liability is not available. ASU 2009-05 is effective for interim and annual periods beginning after August 26, 2009. The Company adopted the provisions of ASU 2009-05 for the period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows. In June 2009, the FASB issued ASU No. 2009-01, Generally Accepted Accounting Principles (ASU 2009-01). ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009. The Company adopted the provisions of ASU 2009-01 for the period ended September 30, 2009. There was no impact on the Company’s operating results, financial position or cash flows. 49 F o r m 1 0 - K In May 2009, the FASB issued SFAS No. 165, Subsequent Events (ASC 855) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the provisions of ASC 855 for the period ended June 30, 2009. In February 2010, the FASB issued Accounting Standards Update No. 2010-09 (“ASC Update 2010-09”), an update to ASC Topic 855. Among other provisions, this update provides that an entity that is a SEC filer is not required to disclose the date through which subsequent events have been evaluated. We adopted the provisions of ASC Update 2010-09 on its effective date of February 24, 2010. There was no impact on the Company’s operating results, financial position or cash flows. In April 2009, the FASB issued FASB Staff Position (FSP) No. FAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments (ASC 825-10-65) to change the reporting requirements on certain fair value disclosures of financial instruments to include interim reporting periods. The Company adopted ASC 825-10-65 in the second quarter of 2009. There was no impact on the Company’s operating results, financial position or cash flows; however additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company’s fair value of financial instruments. See Note 13 “Financial Instruments” for more details. In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than- Temporary Impairments, (ASC 320-10-65), to expand other-than-temporary impairment guidance. There was no impact on the Company’s operating results, financial position or cash flows. In January 2010, the FASB issued authoritative guidance intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately in the reconciliation of fair value measurements using significant unobservable inputs (Level 3). Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurement using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). This guidance is effective for interim and annual periods beginning after December 15, 2010. This guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position. Item 7A. Quantitative and Qualitative Disclosures about Market Risk Commodity Price Risk As an independent oil and gas producer, our revenue, cash flow from operations, other income and profitability, reserve values, access to capital and future rate of growth are substantially dependent upon the prevailing prices of oil and gas. Declines in commodity prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower commodity prices may reduce the amount of oil and gas that we can produce economically. Prevailing prices for such commodities are subject to wide fluctuation in response to relatively minor changes in supply and demand and a variety of additional factors beyond our control, such as global political and economic conditions. Historically, prices received for oil and gas production have been volatile and unpredictable, and such volatility is expected to continue. Most of our production is sold at market prices. Generally, if the commodity indexes fall, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. Assuming the production levels we attained during the year ended December 31, 2009, a 10% decline in oil and gas, prices would have reduced our operating revenue and cash flow by approximately $5.2 million for the year, however, due to the derivative contracts that we have in place, it is unlikely that a 10% decline in commodity prices from their current levels would significantly impact our operating revenue, cash flow and net income. Derivative Instrument Sensitivity We account for our derivative instruments in accordance with ASC 815, all derivative instruments are recorded on the balance sheet at fair value. In 2003, we elected not to designate our derivative instruments as hedges. Accordingly the instruments are recorded on the balance sheet at fair value with changes in the market value of the derivatives being recorded in current derivative income (loss). On July 29, 2009, our commodity based derivative contracts for the periods 2009 through 2011 were monetized for $26.7 million. These funds, together with $2.0 million from the July 2009 commodity swap settlement, were used by the Partnership to repay $28.7 million of outstanding indebtedness under the Partnership Credit Facility. In connection with the monetization and repayment, the Partnership was required to enter into new commodity swaps. As a result of the Merger, all of the Partnership’s derivative contracts were assumed by us. 50 The following table sets forth our derivative contract position as of December 31, 2009: Contract Period 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed-Price Swaps Oil Gas Daily Volume (Bbl) 1,158 1,035 946 705 Swap Price $73.28 76.61 70.89 80.79 Daily Volume (Mmbtu) 11,258 9,580 8,303 5,962 Swap Price $5.73 6.52 6.77 6.84 In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% expires on August 12, 2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 1012. At December 31, 2009, the aggregate fair market value of our commodity derivative contracts was a liability of approximately $14.0 million and the aggregate fair market value of our interest rate swap was a liability of approximately $2.3 million. For the year ended December 31, 2009 we recognized a realized gain of $17.9 million and an unrealized loss of $28.4 million on our commodity derivative contracts and we recognized a realized loss of $2.6 million and an unrealized gain of $757,000 on our interest rate swap. Interest Rate Risk We are subject to interest rate risk associated with borrowings under our credit facility. As of December 31, 2009, we have $146.5 million of outstanding indebtedness under our credit facility. Outstanding amounts ($138.5 million) under the revolving portion of the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization of the borrowing base. At December 31, 2009, the interest rate on the revolving portion of the credit facility was 5.75%. Outstanding amounts ($8.0 million) under the term loan portion of the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 4.75%, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 5.75%. At December 31, 2009, the interest rate on the term loan portion of the credit facility was 7.75%. For every percentage point that the LIBOR rate rises, our interest expense would increase by approximately $1.5 million on an annual basis. In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR based debt. The two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% expires on August 12, 2010. The interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009 lowering our fixed rate to 2.55% and extending the term through August 12, 2012. F o r m 1 0 - K Item 8. Financial Statements and Supplementary Data For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None 51 Item 9A(T). Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures Under the supervision and with the participation of our management, including our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer), we evaluated the effectiveness of our disclosure controls and procedures (as defined under Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, our Chief Executive Officer and our Chief Financial Officer believe that the disclosure controls and procedures as of December 31, 2009 were effective to ensure that information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and are effective to ensure that information required to be disclosed by us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and implemented by the Company’s Board of Directors, management and other personnel, 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 and 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. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2009. This annual report does not include an attestation of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to audit by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management’s report. Changes in Internal Controls There were no changes in our internal control over financial reporting during the quarter ended December 31, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information A special meeting of stockholders was held on October 5, 2009. The stockholders voted on three proposals at the special meeting. These proposals are summarized below and are described more fully in our proxy statement dated September 8, 2009, as filed with the Securities and Exchange Commission. • • Proposal One: To approve the issuance of shares of Abraxas Petroleum common stock in connection with the transaction contemplated by the Amended and Restated Agreement and Plan of Merger dated as of July 17, 2009 by and among Abraxas Petroleum, Abraxas Energy and Merger Sub, as such agreement may be amended from time to time, Proposal Two: If Proposal One is approved, to approve an amendment to the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan (the “LTIP”) to increase the number of shares of Abraxas Petroleum common stock reserved for issuance under the LTIP; and 52 • Proposal Three: To approve the adjournment of the special meeting, if necessary or appropriate, to solicit additional proxies in the event that there are not sufficient votes at the time of the special meeting to approve the foregoing proposals. The approval of the proposals required the affirmative vote of a majority of the total votes cast. Stockholders approved all of the proposals by the requisite votes necessary, as indicated below. The number of votes cast for or against and the number of abstentions with respect to each proposal is set forth below. Broker non-votes were not included as votes cast. Proposal One . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proposal Two . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proposal Three . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,229,237 18,026,538 20,483,779 453,391 2,702,060 1,109,887 115,969 1,070,000 204,391 For Against Abstain F o r m 1 0 - K 53 PART III Item 10. Directors, Executive Officers and Corporate Governance There is incorporated in this Item 10 by reference that portion of our definitive proxy statement for the 2010 Annual Meeting of Stockholders which appears therein under the caption “Election of Directors – Board of Directors and Executive Officers,” “– Code of Ethics” and “– Committees of the Board of Directors.” Audit Committee and Audit Committee Financial Expert The Audit Committee of our board of directors consists of C. Scott Bartlett, Jr., Franklin A. Burke, Paul A. Powell and Brian L. Melton. The board of directors has determined that each of the members of the Audit Committee is independent as determined in accordance with the listing standards of the NASDAQ Stock Market and Item 407(a) of Regulation S-K. In addition, the board of directors has determined that C. Scott Bartlett, Jr., as defined by SEC rules, is an audit committee financial expert. Section 16(a) Compliance Section 16(a) of the Exchange Act requires Abraxas directors and executive officers and persons who own more than 10% of a registered class of Abraxas equity securities to file with the Securities and Exchange Commission and the NASDAQ initial reports of ownership and reports of changes in ownership of Abraxas common stock. Officers, directors and greater than 10% stockholders are required by SEC regulations to furnish us with copies of all such forms they file. Based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required. We believe that all our directors and executive officers complied on a timely basis with all applicable filing requirements under Section 16(a) of the Exchange Act during 2009. Item 11. Executive Compensation There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2010 Annual Meeting of Stockholders which appears therein under the captions “Election of Directors – Committees of the Board of Directors” and “Executive Compensation”, except the material under the caption “Compensation Committee Report on Executive Compensation.” Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters There is incorporated in this Item 12 by reference that portion of our definitive proxy statement for the 2010 Annual Meeting of Stockholders which appears therein under the caption “Securities Holdings of Principal Stockholders, Directors, Nominees and Officers.” Item 13. Certain Relationships and Related Transactions, and Director Independence There is incorporated in this Item 13 by reference that portion of our definitive proxy statement for the 2010 Annual Meeting of Stockholders which appears therein under the captions “Certain Transactions” and “Election of Directors – Board Independence.” Item 14. Principal Accountants Fees and Services There is incorporated in this Item 14 by reference that portion of our definitive proxy statement for the 2010 Annual Meeting of Stockholders which appears therein under the caption “Principal Auditor Fees and Services.” 54 Item 15. Exhibits, Financial Statement Schedules (a) 1. Consolidated Financial Statements PART IV Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements . . . . . . . . . . . . . . . . . Consolidated Balance Sheets at December 31, 2008 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . . . . . . . . . Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . . . . . . . . Consolidated Statements of Other Comprehensive Income (Loss) for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page F-2 F-3 F-5 F-6 F-7 F-8 F-9 (a) 2. Financial Statement Schedules All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto. (a) 3. Exhibits The following Exhibits have previously been filed by the Registrant or are included following the Index to Exhibits. Exhibit Number. Description 3.1 3.2 3.3 3.4 3.5 3.6 3.7 4.1 4.2 4.3 *10.1 *10.2 *10.3 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to our Registration Statement on Form S-4, No. 33-36565 (the “S-4 Registration Statement”)). Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration Statement). Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement). Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on Form S-3, No. 333-00398 (the “S-3 Registration Statement”)). Articles of Amendment to the Articles of Incorporation of Abraxas dated as of August 12, 2000. (Filed as Exhibit 3.5 to our Annual Report on Form 10-K (Filed April 2, 2001). F o r m 1 0 - K Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.1 to Abraxas’ Current Report on Form 8-K. on November 17, 2008). Certificate of Designation of Series 2010 Junior Participating Preferred Stock (Previously filed as Exhibity3.1 to Abraxas Current Report on Form 8-K (filed March 17, 2010. Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement). Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to our Annual Report on Form 10-K filed on March 31, 1995). Rights Agreement, dated March 17, 2010 by and between Abraxas and American Stock Transfer and Trust Company (filed as Exhibit 4.1 to Abraxas Registration Statement of Form 8-A filed on March 17, 2010. Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to Abraxas’ Registration Statement on Form S-4, No. 333-18673, (the “1996 Exchange Offer Registration Statement”)). Abraxas Petroleum Corporation Amended and Restated 1994 Long Term Incentive Plan. (Filed as Exhibit 10.4 to Abraxas’ Registration Statement on Form S-4 filed on January 12, 2005). Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.4 to our Annual Report on Form 10-K filed March 14, 2007). 55 Exhibit Number. *10.4 *10.5 *10.6 *10.7 *10.8 *10.9 *10.10 *10.11 *10.12 *10.13 10.14 10.15 10.16 10.17 10.18 14.1 18.1 21.1 23.1 23.2 31.1 31.2 32.1 32.2 Description Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.19 to the Registration Statement on Form S-1, No. 333-95281 (the “2000 S-1 Registration Statement”)). Employment Agreement between Abraxas and Chris E. Williford. (Filed as Exhibit 10.20 to the 2000 S-1 Registration Statement). Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the Registration Statement on Form S-3, No. 333-127480 (the “S-3 Registration Statement”)). Employment Agreement between Abraxas and William H. Wallace. (Filed as Exhibit 10.27 to the S-3 Registration Statement). Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as Exhibit 10.28 to the S-3 Registration Statement). Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as Exhibit 10.1 to Abraxas’ Current Report on Form 8-K filed June 6, 2005). Form of Stock Option Agreement under the Abraxas Petroleum Corporation 2005 Non-Employee Directors Long- Term Equity Incentive Plan. (Filed as Exhibit 10.2 to Abraxas’ Current Report on Form 8-K filed June 6, 2005). Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan 2006. (Filed as Exhibit 10.17 to Annual Report on Form 10-K filed March 23, 2006). Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan (Filed as Annex E to Abraxas’ Proxy Statement filed on September 8, 2009)). Form of Employee Stock Option Agreement under the Abraxas 2005 Employee Long-Term Equity Incentive Plan. (Previously filed as Exhibit 10.2 to Abraxas’ Current Report on Form 8-K filed August 26, 2006). Securities Purchase Agreement dated May 25, 2007 by and among Abraxas Petroleum Corporation and the purchasers named therein. (Filed as Exhibit 10.7 to Abraxas’ Current Report on Form 8-K filed May 31, 2007). Form of Common Stock Purchase Warrant. (Filed as Exhibit 10. 8 to Abraxas’ Current Report on Form 8-K filed May 31, 2007). Voting, Registration Rights and Lock-Up Agreement, dated as of June 30, 2009, by and among Abraxas Petroleum, Abraxas Energy and certain limited partners of Abraxas Energy (Filed as Exhibit 10.1 to Abraxas’ Current Report on Form 8-K filed on July 2, 2009). Form of Indemnification Agreement by and among Abraxas Energy Partners, L.P., Abraxas General Partner, LLC, and each of its officers and directors. (Filed as Exhibit 10.25 to Abraxas’ Annual Report on Form 10-K filed on March 17, 2008). Amended and Restated Credit Agreement dated as of October 5, 2009 among Abraxas Petroleum, as Borrower, the lenders party thereto and Société Générale as Administrative Agent and as Issuing Lender (Filed as Exhibit 10.1 to Abraxas’ Current Report on Form 8-K filed on October 7, 2009). Abraxas Petroleum Corporation Code of Business Conduct and Ethics. (Filed as Exhibit 14.1 to Abraxas Annual Report on Form 10-K filed March 22, 2006). Change in Accounting Principles. (Filed as Exhibit 18.1 to Abraxas Annual Report on Form 10-K/A Number 2 filed on August 20, 2008). Subsidiaries of Abraxas. (Filed herewith). Consent of BDO Seidman, LLP. (Filed herewith). Consent of DeGolyer and MacNaughton. (Filed herewith). Certification—Chief Executive Officer. (Filed herewith). Certification—Chief Financial Officer. (Filed herewith). Certification by Chief 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). Certification by Chief 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 Report of DeGolyer and MacNaughton (filed herewith). * Management Compensatory Plan or Agreement. 56 21.1 23.1 23.2 31.1 31.2 32.1 32.2 Exhibit Index Subsidiaries of Abraxas Petroleum Corporation (Filed herewith) Consent of BDO Seidman, LLP. (Filed herewith). Consent of DeGolyer & MacNaughton (Filed herewith). Certification—Chief Executive Officer. (Filed herewith). Certification—Chief Financial Officer. (Filed herewith). Certification by Chief 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). Certification by Chief 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 Report of DeGolyer and MacNaughton. (Filed herewith) F o r m 1 0 - K 57 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. SIGNATURES ABRAXAS PETROLEUM CORPORATION By: /s/ Robert L.G. Watson President and Principal Executive Officer DATED: March 17, 2010 By: /s/ Chris E. Williford Exec. Vice President and Principal Financial and Accounting 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 date indicated. Signature Name and Title Chairman of the Board, President (Principal Executive Officer) and Director Date March 17, 2010 /s/ Robert L.G. Watson Robert L.G. Watson /s/ Chris E. Williford Chris E. Williford /s/ Craig S. Bartlett, Jr. Craig S. Bartlett, Jr. /s/ Franklin A. Burke Franklin A. Burke /s/ Harold D. Carter Harold D. Carter /s/ Ralph F. Cox Ralph F. Cox /s/ Dennis E. Logue Dennis E. Logue /s/ Paul A. Powell Paul A. Powell /s/ Brian L. Melton Brian L. Melton /s/ Edward P. Russell Edward P. Russell Exec. Vice President and Treasurer (Principal Financial and Accounting Officer) March 17, 2010 March 17, 2010 March 17, 2010 March 17, 2010 March 17, 2010 March 17, 2010 March 17, 2010 March 17, 2010 March 17, 2010 Director Director Director Director Director Director Director Director 58 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Abraxas Petroleum Corporation and Subsidiaries Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements . . . . . . . . . . . . . . . . . Consolidated Balance Sheets at December 31, 2008 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . . . . . . . . . Consolidated Statements of Stockholders’ Equity (Deficit) for the years ended December 31, 2007, 2008 and 2009 . . . Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . . . . . . . . Consolidated Statements of Other Comprehensive Income (Loss) for the years ended December 31, 2007, 2008 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page F-2 F-3 F-5 F-6 F-7 F-8 F-9 All schedules are omitted because they are not required, are not applicable or the information required is included in the Consolidated Financial Statements or the notes thereto. F o r m 1 0 - K F-1 Report of Independent Registered Public Accounting Firm Board of Directors and Stockholders Abraxas Petroleum Corporation San Antonio, Texas We have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation (“Abraxas” or the “Company”) as of December 31, 2008 and 2009 and the related consolidated statements of operations, stockholders’ equity (deficit), cash flows, and other comprehensive income (loss) for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits 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 Abraxas Petroleum Corporation at December 31, 2008 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 1, the Company retrospectively adopted a new accounting pronouncement on January 1, 2009 related to the accounting for non-controlling interests in the consolidated financial statements. Also, as discussed in Note 1, during 2009 the Company changed its reserve estimates and related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements. /s/ BDO Seidman, LLP Dallas, Texas March 17, 2010 F-2 ABRAXAS PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS ASSETS December 31, 2008(1) 2009 (Dollars in thousands) Current assets: Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable: $ 1,924 $ 1,861 Joint owners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and gas production sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Derivative asset—current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property and equipment: Oil and gas properties, full cost method of accounting: Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unproved properties excluded from depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other property and equipment Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less accumulated depreciation, depletion, and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,740 6,168 58 7,966 22,832 572 33,294 865 7,873 31 8,769 325 514 11,469 440,712 — 10,986 451,698 291,390 454,142 — 11,259 465,401 309,245 Total property and equipment—net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160,308 156,156 Deferred financing fees, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Derivative asset—long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets including marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,443 16,394 400 5,804 2,253 554 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $211,839 $176,236 (1) As adjusted for “Noncontrolling Interest in Consolidated Financial Statements” in accordance with ASC 810. F o r m 1 0 - K See accompanying notes to consolidated financial statements F-3 ABRAXAS PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (CONTINUED) LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) Current liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Joint interest oil and gas production payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Derivative liability—current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt—less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Derivative liability—long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future site restoration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2008(1) 2009 (Dollars in thousands) $ 10,748 3,176 350 1,886 3,000 40,134 59,294 130,835 — 9,959 $ 8,773 3,606 563 770 7,047 8,141 28,900 143,592 11,781 10,326 Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200,088 194,599 Commitments and contingencies Stockholders’ Equity (Deficit): Abraxas Petroleum stockholders’ equity (deficit) Preferred stock, par value $.01, authorized 1,000,000 shares; -0- shares issued and outstanding. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — Common stock, par value $.01 per share—authorized 200,000,000 shares; issued 49,622,423 and 76,231,751 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additional paid-in capital Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Abraxas Petroleum stockholders’ equity (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-controlling interest equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 496 187,243 (183,194) 113 4,658 7,093 762 182,647 (201,974) 202 (18,363) — Total stockholders’ equity (deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,751 (18,363) Total liabilities, non-controlling interest and stockholders’ equity (deficit) . . . . . . . . . . . . . . . . . $ 211,839 $ 176,236 (2) As adjusted for “Noncontrolling Interest in Consolidated Financial Statements” in accordance with ASC 810. See accompanying notes to consolidated financial statements F-4 ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended December 31, 2007(1) 2008(1) 2009 (In thousands except per share data) Revenues: Oil and gas production revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 46,906 1,396 7 $ 99,084 $ 51,829 914 7 1,210 16 Operating costs and expenses: Lease operating and production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rig operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative (including stock-based compensation of $996; $1,404 ; 48,309 100,310 52,750 11,254 14,292 — 801 26,635 23,343 116,366 856 26,224 17,886 — 758 and $1,239, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,438 7,127 7,705 32,785 174,327 52,573 Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,524 (74,017) 177 Other (income) expense: Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss (gain) on derivative contracts (unrealized $6,288, $(37,860) and $27,650) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on debt extinguishment Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (408) 671 8,392 — 4,363 6,455 (59,439) 347 (187) 1,028 10,496 359 (28,333) — — 8,523 (15) 1,326 11,346 362 12,322 — — 2,071 Income (loss) from operations before income tax and non-controlling interest . . . . . . . . . . . Income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Net loss attributable to non-controlling interest (39,619) (8,114) 27,412 55,143 283 54,860 1,842 (65,903) — (65,903) 13,500 (27,235) 1,290 (28,525) 9,745 Net income (loss) attributable to Abraxas Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 56,702 $ (52,403) $(18,780) Net income (loss) attributable to Abraxas Petroleum common stockholders—per common share—basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) attributable to Abraxas Petroleum common stockholders—per common share—diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 1.22 $ (1.07) $ (0.34) 1.19 $ (1.07) $ (0.34) (1) As adjusted for “Noncontrolling Interest in Consolidated Financial Statements” in accordance with ASC 810. F o r m 1 0 - K See accompanying notes to consolidated financial statements F-5 ) 1 ( l a t o T ) 1 ( t s e r e t n I g n i l l o r t n o C - n o N d e t a l u m u c c A r e h t O e v i s n e h e r p m o C ) s s o L ( e m o c n I d e t a l u m u c c A t i c i f e D l a n o i t i d d A n i - d i a P l a t i p a C t n u o m A s e r a h S t n u o m A s e r a h S k c o t S y r u s a e r T k c o t S n o m m o C N O I T A R O P R O C M U E L O R T E P S A X A R B A ) T I C I F E D ( Y T I U Q E ’ S R E D L O H K C O T S F O S T N E M E T A T S D E T A D I L O S N O C ) s e r a h s f o r e b m u n t p e c x e s d n a s u o h t n I ( ) 3 9 4 , 7 8 1 ( $ 0 1 2 , 4 6 1 $ ) 5 8 4 ( $ 2 5 5 , 5 3 8 2 4 $ 6 6 4 , 2 6 7 , 2 4 ) 3 6 3 , 8 1 ( $ — $ 2 0 2 $ ) 4 7 9 , 1 0 2 ( $ 7 4 6 , 2 8 1 — $ ) 3 7 4 ( 0 6 8 , 4 5 2 9 3 , 9 2 ) 5 6 1 , 2 2 ( $ 6 9 9 1 9 1 2 1 4 8 5 , 0 2 — ) 3 5 0 , 4 ( ) 9 8 3 ( 2 6 1 , 1 4 4 3 , 9 7 ) 3 0 9 , 5 6 ( 0 6 7 6 1 2 3 9 2 — ) 7 9 9 , 9 ( 3 9 0 , 7 1 5 7 , 1 1 ) 5 2 5 , 8 2 ( ) 6 ( 5 9 4 1 2 , 1 ) 7 5 2 , 2 ( 6 5 2 5 8 3 , 1 8 7 3 0 2 ) 7 5 5 , 2 ( — ) 2 4 8 , 1 ( 2 9 3 , 9 2 — $ — — — — — — ) 3 5 0 , 4 ( 7 9 4 , 3 2 ) 0 0 5 , 3 1 ( — — — — — — — ) 7 9 9 , 9 ( 3 9 0 , 7 3 9 0 , 7 ) 5 4 7 , 9 ( — — 9 6 ) 7 5 2 , 2 ( 6 5 2 5 8 3 , 1 — — 9 9 1 , 3 — ) 3 7 4 ( — — 5 7 9 $ — — — — — — 2 0 5 — ) 9 8 3 ( — — — — — — — — ) 6 ( 5 9 3 1 1 — — — — — — — — — 2 0 7 , 6 5 — — — — — — — — ) 3 0 4 , 2 5 ( ) 1 9 7 , 0 3 1 ( — — — — — — — — — ) 0 8 7 , 8 1 ( ) 4 9 1 , 3 8 1 ( — — — — — — — — — — ) 4 9 ( 6 9 9 0 1 ) 1 ( 5 2 5 , 0 2 — — — — — — — — — — — — — — — — 5 8 2 ) 2 5 5 , 5 3 ( 0 6 5 6 2 6 1 , 1 — 0 2 0 9 2 — — — — 5 4 1 , 1 — — — 7 7 1 0 2 ) 5 ( ) 4 1 0 , 6 ( — — — 3 4 2 , 7 8 1 $ — — — — — — — — — — — — — — — — — — — — — — 6 4 6 , 5 8 1 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — — 2 9 5 1 — 0 9 4 — — — — 3 1 2 — — — — — — — 0 6 9 , 2 2 9 0 1 , 8 0 2 6 3 7 , 2 5 1 8 7 6 , 4 7 8 , 5 — 9 4 9 , 0 2 0 , 9 4 5 5 6 , 0 3 1 6 9 , 1 3 1 0 5 , 1 4 1 5 0 6 , 2 5 2 5 7 , 4 4 3 — — — — — 6 9 4 3 2 4 , 2 2 6 , 9 4 — — — — — — — 1 2 5 8 5 2 — — — — — — — 4 5 9 , 1 6 2 0 0 , 9 3 2 0 4 8 , 0 6 4 2 3 5 , 7 4 8 , 5 2 2 6 7 $ 1 5 7 , 1 3 2 , 6 7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s t n e m t s e v n i f o e u l a v r i a f ) s s o l ( n i a g d e z i l a e r n u n i e g n a h C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s t i n u p i h s r e n t r a p f o e c n a u s s I . . . . . . . . . . . . . . . e m o c n I t e N 6 0 0 2 , 1 3 r e b m e c e D t a e c n a l a B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . n o i t a s n e p m o c d e s a b - k c o t S n o i t a s n e p m o c r o f d e u s s i s e r a h S . . . . . . . d e s i c r e x e s n o i t p o k c o t S s t s o c g n i r e f f o f o t e n , e c n a u s s i y t i u q E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . e u s s i k c o t s d e t c i r t s e R s n o i t u b i r t s i d p i h s r e n t r a P . . . . . . . . . . . . . . s s o L t e N 7 0 0 2 , 1 3 r e b m e c e D t a e c n a l a B s t n e m t s e v n i f o e u l a v r i a f ) s s o l ( n i a g d e z i l a e r n u n i e g n a h C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . n o i t a s n e p m o c d e s a b - k c o t S n o i t a s n e p m o c r o f d e u s s i s e r a h S . . . . . . . . . . . . . . d e s i c r e x e s n o i t p o k c o t S . . . d e s i c r e x e s t n a r r a W p i h s r e n t r a P n i s t i n u f o n o i s r e v n o C s n o i t a l l e c n a c f o t e n , d e u s s i k c o t s d e t c i r t s e R . . . . . . . . . . . . . . . s n o i t u b i r t s i d p i h s r e n t r a P t n e m e e r g a s t h g i r e g n a h c x e r e d n u e l b a u s s i s e r a h s s a x a r b A s t n e m t s e v n i f o e u l a v r i a f ) s s o l ( n i a g d e z i l a e r n u n i e g n a h C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s s o L t e N 8 0 0 2 , 1 3 r e b m e c e D t a e c n a l a B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . t n e m t s u j d a n o i t a l s n a r t y c n e r r u c n g i e r o F . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . s n o i t u b i r t s i d p i h s r e n t r a P . d e u s s i s t i n u p i h s r e n t r a P n o i t a s n e p m o c d e s a b - k c o t S e s n e p x e o t d e r r e f s n a r t t s o c n o i t a r t s i g e r p i h s r e n t r a P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . d e s i c r e x e s n o i t p o k c o t S n o i t a s n e p m o c r o f d e u s s i s e r a h S m u e l o r t e P s a x a r b A o t n i p i h s r e n t r a p f o r e g r e M . . . . s n o i t a l l e c n a c f o t e n , d e u s s i k c o t s d e t c i r t s e R . . . . . . . . . . . . . . 9 0 0 2 , 1 3 r e b m e c e D t a e c n a l a B F-6 . 0 1 8 C S A h t i w e c n a d r o c c a n i ” s t n e m e t a t S l a i c n a n i F d e t a d i l o s n o C n i t s e r e t n I g n i l l o r t n o c n o N “ r o f d e t s u j d a s A ) 1 ( ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Operating Activities Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income (loss) to net cash provided by operating activities: Years Ended December 31, 2007(1) 2008(1) 2009 (In thousands) $ 54,860 $ (65,903) $(28,525) (Gain) loss on sale of partnership interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in derivative fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Monetization of derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of future site restoration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Registration fees previously capitalized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss on disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other non-cash transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in operating assets and liabilities: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (59,439) 6,235 — 14,292 — 127 671 996 191 — — 112 15 1,063 (791) — (42,304) — 23,343 116,366 570 1,028 1,404 — — 7,446 — 25,740 26,736 17,886 — 558 1,326 1,239 2,210 289 78 (1,838) (206) 4,082 (601) (803) (7) (1,545) (1,046) Net cash provided by operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,332 43,387 44,136 Investing Activities Capital expenditures, including purchases and development of properties . . . . . . . . . . . . Proceeds from the sale of oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,908) — (174,586) 642 (16,471) 2,375 Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,908) (173,944) (14,096) Financing Activities Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from issuance of partnership equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cost of common stock and partnership equity issuance . . . . . . . . . . . . . . . . . . . . . . . . . . . Transaction costs on exchange of partnership units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from long-term borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payments on long-term borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partnership distribution to non-controlling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred financing fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase (decrease) in cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,441 100,000 (9,098) — 46,690 (128,404) (3,163) (997) — 27,469 18,893 43 Cash at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 18,936 Supplemental disclosures of cash flow information: Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,494 88 — — — 135,084 (10,015) (9,997) (1,615) — 203 — — (2,557) 13,500 (32,736) (2,257) (5,687) (569) 113,545 (30,103) (17,012) 18,936 (63) 1,924 1,924 $ 1,861 9,817 $ 10,575 $ $ (1) As adjusted for “Noncontrolling Interest in Consolidated Financial Statements” in accordance with ASC 810. F o r m 1 0 - K See accompanying notes to consolidated financial statements F-7 ABRAXAS PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME (LOSS) Net income (loss) attributable to Abraxas Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Comprehensive income (loss): Change in unrealized value of investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment Other comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2007 2008 2009 (In thousands) $56,702 $(52,403) $(18,780) (473) — (473) (389) — (389) 95 (6) 89 Comprehensive income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $56,229 $(52,792) $(18,691) See accompanying notes to consolidated financial statements. F-8 ABRAXAS PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Significant Accounting Policies Nature of Operations Abraxas Petroleum Corporation (“Abraxas” or “Abraxas Petroleum”) is an independent energy company primarily engaged in the exploration of and the acquisition, development, and production of oil and gas principally in Texas, the Mid-Continent and the Rocky Mountains. The terms “Abraxas” and “Abraxas Petroleum” refers only to Abraxas Petroleum Corporation, the term “Partnership” refers only to Abraxas Energy Partners L.P. and the terms “we,” “us,” “our,” or the “Company,” refer to Abraxas Petroleum Corporation, together with its consolidated subsidiaries including Abraxas Energy Partners, L.P., unless the context otherwise requires. On June 30, 2009, Abraxas Petroleum and the Partnership signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which the Partnership agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum and the Partnership signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which the Partnership agreed to merge with and into Abraxas Merger Sub, LLC, which we refer to as Merger Sub, with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, which we refer to as the Effective Time, each common unit of the Partnership not owned by Abraxas Petroleum and its subsidiaries was converted into the right to receive 4.25 shares of Abraxas Petroleum common stock. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of the Partnership under the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan, or LTIP. The Company consolidates based on the guidance of Accounting Standards Codification (“ASC”) 810. ASC 810 establishes accounting and reporting standards for (1) ownership interests in subsidiaries held by others, (2) the amount of consolidated net income attributable to the controlling and non-controlling interests, (3) changes in the controlling ownership interest, (4) the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated and (5) disclosures that clearly identify and distinguish between the interests of the controlling and non-controlling owners. The adoption of ASC 810 resulted in changes to our presentation for non-controlling interests and did not have a material impact on the Company’s results of operations and financial condition. Certain prior period balances have been restated to recasted the changes required by ASC 810. In accordance with generally accepted accounting principles in effect prior to the adoption of ASC 810, which codifies Statement of Financial Accounting Standards (“SFAS”) 160, when cumulative losses applicable to the non-controlling interest exceed the non-controlling interest equity capital in the entity, such excess and any further losses applicable to the non-controlling interest were charged to the earnings of the controlling interest. Future earnings were recognized by the non-controlling interest and were credited to the controlling interest (Abraxas) to the extent of such losses previously absorbed. For the year ended December 31, 2008, primarily due to the ceiling test impairment of the Partnership’s oil and gas properties, losses applicable to the non-controlling interest exceeded the non-controlling equity capital by $9.3 million. As a result, $9.3 million of the non-controlling interest loss in excess of equity was charged to earnings attributable to Abraxas and was reflected on the income statement as a reduction of the loss applicable to the non-controlling interest. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and the operations of the Partnership which was formed on May 25, 2007. The operations of Abraxas Petroleum and the Partnership were consolidated for financial reporting purposes. The interest of the 51.8% owners of the Partnership was presented as non-controlling interest (through the date of its merger into Abraxas Petroleum). Abraxas owned the remaining 48.2% of Partnership interests. The Company determined that based on its control of the general partner of the Partnership, this 48.2% owned entity should be consolidated for financial reporting purposes. Liquidity The current global recession has had a significant impact on our operations. As a result of the global recession, gas prices are depressed and may stay depressed or reduce further, thereby causing a prolonged downturn, which could reduce F-9 F o r m 1 0 - K our future cash flows from operations. A significant decline in oil prices from current levels could also reduce our future cash flows from operations. This could cause us to alter our business plans, including reducing our exploration and development plans. Use of Estimates The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management believes that it is reasonably possible that estimates of future proved oil and gas revenues could significantly change in the future. Concentration of Credit Risk Financial instruments, which potentially expose the Company to credit risk consist principally of trade receivables and commodity derivative contracts. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers. The counterparties to our commodity derivative contracts are the same financial institutions from which we have outstanding debt, accordingly we believe our exposure to credit risk to these counterparties is currently mitigated in part by this, as well as the current overall financial condition of the counterparties. The Company maintains any cash and cash equivalents in excess of federally insured limits in prominent financial institutions considered by the Company to be of high credit quality. Cash and Equivalents Cash and cash equivalents include cash on hand, demand deposits and short-term investments with original maturities of three months or less. Accounts Receivable Accounts receivable are reported net of an allowance for doubtful accounts of approximately $33,000 and $33,000 at December 31, 2008 and 2009, respectively. The allowance for doubtful accounts is determined based on the Company’s historical losses, as well as a review of certain accounts. Accounts are charged off when collection efforts have failed and the account is deemed uncollectible. Oil and Gas Properties The Company follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of oil and gas properties, less related deferred taxes, are limited to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. The Company does not have any properties that are being excluded from amortization. Costs in excess of the present value of estimated future net revenues as discussed above are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of oil and gas properties, except in unusual circumstances. We apply the full cost ceiling test on a quarterly basis on the date of the latest balance sheet presented. For the year ended December 31, 2008, the Company incurred an impairment of $116.4 million, based on year end prices of $44.60 per barrel of oil and $5.62 per Mcf of gas. As of December 31, 2009, our net capitalized costs of oil and gas properties did not exceed the present value of our estimated proved reserves. Other Property and Equipment Other property and equipment are recorded on the basis of cost. Depreciation of other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and betterments are recorded as additions to the property and equipment accounts. Repairs that do not improve or extend the useful lives of assets are expensed. F-10 Estimates of Proved Oil and Gas Reserves Estimates of our proved reserves included in this report are prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and SEC guidelines. The accuracy of a reserve estimate is a function of: • • • • the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. Our proved reserve information included in this report was predominately based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. In accordance with SEC requirements, beginning December 31, 2009, we based the estimated discounted future net cash flows from proved reserves on the unweighted arithmetic average of the prior 12-month commodity prices as of the first day of each of the months constituting the period and costs on the date of the estimate. In prior years, such estimates had been based on year end prices and costs. Future prices and costs may be materially higher or lower than these prices and costs which would impact the estimated value of our reserves. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. The adoption of the new guidance in 2009 resulted in a downward adjustment of $139.9 million to the estimated discounted future cash flows from proved reserves and a reduction of 1,973.8 MBOE of proved reserves. Additionally, the change resulted in an increase of $335,000 in DD&A expense in the fourth quarter of 2009. Derivative Instruments and Hedging Activities The Company enters into agreements to hedge the risk of future oil and gas price fluctuations. Such agreements are primarily in the form of fixed price swaps, which limit the impact of price fluctuations with respect to the Company’s sale of oil and gas. The Company does not enter into speculative hedges. The Company accounts for derivative gains and losses based on realized and unrealized amounts. The realized derivative gains or losses are determined by actual derivative settlements during the period. Unrealized gains and losses are based on the periodic mark to market valuation of derivative contracts in place. Our derivative contract transactions do not qualify for hedge accounting as prescribed by ASC 815; therefore, fluctuations in the market value of the derivative contracts are recognized in earnings during the current period. F o r m 1 0 - K Fair Value of Financial Instruments The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the carrying value. The Company assumes the carrying value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments. Share-Based Payments The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees and directors. Options granted to employees and directors are valued at the date of grant and expense is recognized over the vesting period. Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. For the years ended December 31, 2007, 2008 and 2009, share based compensation was approximately $996,000, $1.4 million and $1.2 million respectively. For additional information regarding share-based payments please see Note 6 “Stock-based Compensation, Option Plans and Warrants.” F-11 Restoration, Removal and Environmental Liabilities The Company is subject to extensive Federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability or component are fixed or reliably determinable. The Company accounts for asset retirement obligations based on the guidance of ASC 410 (formerly FASB 143) which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the estimated useful life of the related asset. For all periods presented, we have included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortize these costs as a component of our depletion expense in the accompanying consolidated financial statements. The following table summarizes the Company’s asset retirement obligation transactions during the following years ended December 31: 2007 2008 2009 Beginning asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . New wells placed on production and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deletions related to property disposals and plugging costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (in thousands) $1,183 9,046 (840) 570 $ 9,959 91 (282) 558 $1,019 43 (6) 127 Ending asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,183 $9,959 $10,326 Revenue Recognition and Major Purchasers The Company recognizes oil and gas revenue from its interest in producing wells as oil and gas is sold from those wells, net of royalties. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, income is recorded based on the Company’s net revenue interest in production taken for delivery. The Company had no material gas imbalances at December 31, 2007, 2008 and 2009. Rig revenue is recognized as workover rig services are performed on our wells on behalf of third party working interest owners. During 2007, 2008 and 2009, two purchasers accounted for 25% and 23%; 14% and 15%; and 11% and 11% of oil and gas revenues, respectively. Deferred Financing Fees Deferred financing fees are being amortized on the effective yield basis over the term of the related debt arrangements. Income Taxes The Company records deferred income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. F-12 Other Comprehensive Income ASC 220 requires disclosure of comprehensive income, which includes reported net income as adjusted for other comprehensive income. Comprehensive income for the Company is the change in the market value of investments and foreign currency translation adjustments. Accounting for Uncertainty in Income Taxes ASC 740 provides guidance on accounting for uncertainty in income taxes. ASC 740 is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. Under ASC 740, evaluation of a tax position is a two-step process. The first step is to determine whether it is more- likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more- likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more- likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense. The adoption of this standard at January 1, 2007 did not have an impact on the Company’s financial position. New Accounting Pronouncements On December 29, 2008, the Securities and Exchange Commission adopted rule changes to modernize its oil and gas reporting disclosures “Modernization of Oil and Gas Reporting” (the Final Rule). The changes are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. The updated disclosure requirements are designed to align with current practices and changes in technology that have taken place in the oil and gas industry since the adoption of the original reporting requirements more than 25 years ago. New disclosure requirements include: • • • • • Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Enabling companies to additionally disclose their probable and possible reserves to investors. Allowing previously excluded resources, such as oil sands, to be classified as oil and gas reserves. Requiring companies to report on the independence and qualifications of a preparer or auditor and requiring companies to file reports when a third party is relied upon to prepare reserve estimates or conduct a reserves audit. Requiring companies to report oil and gas reserves using an average price based upon the prior 12-month period— rather than the year-end price—to maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date. In January 2010 the FASB issued ASU 2010-03, Extractive Activities—Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (“ASU 2010-03”) which aligns the oil and gas reserve estimation and disclosure requirements of ASC 932 with the requirements in the SEC’s Final Rule, discussed above. We adopted the Final Rule and ASU effective December 31, 2009. In December 2009, we adopted revised oil and gas reserve estimation and disclosure requirements which conforms the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC. The use of 12-month average prices, as opposed to year end prices, in calculating the present value of our reserves, resulted in a reduction of the standardized measure of discounted future net cash flows of approximately $139.3 million at December 31, 2009 as well as the standardized measure of discounted future cash flow relating to proved reserves presented in Note 15. The use of average prices affected our depletion calculation for the fourth quarter of 2009 resulting in an increase in DD&A expense of approximately $335,000. F-13 F o r m 1 0 - K In August 2009, the FASB issued Accounting Standards Update (ASU) No. 2009-05, Fair Value Measurements and Disclosures (ASU 2009-05). ASU 2009-05 amends Subtopic 820-10, Fair Value Measurements and Disclosures, to provide guidance on the fair value measurement of liabilities. ASU 2009-05 provides clarification for circumstances in which a quoted price in an active market for the identical liability is not available. ASU 2009-05 is effective for interim and annual periods beginning after August 26, 2009. The Company adopted the provisions of ASU 2009-05 for the period ended December 31, 2009. There was no impact on the Company’s operating results, financial position or cash flows. In June 2009, the FASB issued ASU No. 2009-01, Generally Accepted Accounting Principles (ASU 2009-01). ASU 2009-01 establishes “The FASB Accounting Standards Codification,” or Codification, which became the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. ASU 2009-01 is effective for interim and annual periods ending after September 15, 2009. The Company adopted the provisions of ASU 2009-01 for the period ended September 30, 2009. There was no impact on the Company’s operating results, financial position or cash flows. In May 2009, the FASB issued SFAS No. 165, Subsequent Events (ASC 855) to establish general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 is effective for interim and annual reporting periods ending after June 15, 2009. The Company adopted the provisions of ASC 855 for the period ended June 30, 2009. In February 2010, the FASB issued Accounting Standards Update No. 2010-09 (“ASC Update 2010-09”), an update to ASC Topic 855. Among other provisions, this update provides that an entity that is a SEC filer is not required to disclose the date through which subsequent events have been evaluated. We adopted the provisions of ASC Update 2010-09 on its effective date of February 24, 2010. There was no impact on the Company’s operating results, financial position or cash flows. In April 2009, the FASB issued FASB Staff Position (FSP) No. FAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments (ASC 825-10-65) to change the reporting requirements on certain fair value disclosures of financial instruments to include interim reporting periods. The Company adopted ASC 825-10-65 in the second quarter of 2009. There was no impact on the Company’s operating results, financial position or cash flows; however additional disclosures were added to the accompanying notes to the consolidated financial statements for the Company’s fair value of financial instruments. See Note 13 “Financial Instruments” for more details. In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than- Temporary Impairments, (ASC 320-10-65), to expand other-than-temporary impairment guidance. In January 2010, the FASB issued authoritative guidance intended to improve disclosures about fair value measurements. The guidance requires entities to disclose significant transfers in and out of fair value hierarchy levels and the reasons for the transfers and to present information about purchases, sales, issuances and settlements separately in the reconciliation of fair value measurements using significant unobservable inputs (Level 3). Additionally, the guidance clarifies that a reporting entity should provide fair value measurements for each class of assets and liabilities and disclose the inputs and valuation techniques used for fair value measurement using significant other observable inputs (Level 2) and significant unobservable inputs (Level 3). This guidance is effective for interim and annual periods beginning after December 15, 2010. This guidance provides only disclosure requirements, the adoption of this standard will not impact our results of operations, cash flows or financial position. Segment and Related Information Although we have a number of operating divisions, separate segment data has not been presented as they meet the criteria for aggregation as permitted by ASC 280 “Segment Reporting.” 2. Partnership Formation and Merger Formation On May 25, 2007, Abraxas entered into a contribution, conveyance and assumption agreement with the Partnership, Abraxas General Partner, LLC, a Delaware limited liability company and wholly-owned subsidiary of Abraxas which we refer to as the GP, Abraxas Energy Investments, LLC, a Texas limited liability company and wholly-owned subsidiary of Abraxas which we refer to as the LP, and Abraxas Operating, LLC, a Texas limited liability company and wholly-owned subsidiary of the Partnership which we refer to as the Operating Company. Among other things, the contribution agreement provided for the contribution by Abraxas to the Operating Company of certain assets located in South and West Texas in exchange for all of the equity interests of the Operating Company. F-14 In consideration for these assets, the Partnership and the Operating Company, jointly and severally, assumed all of Abraxas’ existing indebtedness under its Floating Rate Senior Secured Notes due 2009, which we refer to as the notes, and the obligation to pay certain preformation and transaction expenses and issued general partner units and common units to the GP and the LP, respectively, in exchange for their ownership interests in the Operating Company. On May 25, 2007, the Partnership sold 6,002,408 common units, representing an approximate 52.8% interest in the Partnership, for $16.66 per Common Unit, or approximately $100 million, pursuant to a purchase agreement dated May 25, 2007, to a group of accredited investors. After consummation of these transactions, the general partner units and the common units owned by the GP and the LP constituted a 47.2% ownership interest in the Partnership. As a result of these transactions, the Abraxas recognized a gain of $59.4 million in 2007. The gain was calculated in accordance with the requirements of SEC Staff Accounting Bulletin 51, (Topic 5H) based on the fact that the Abraxas elected gain treatment as a policy and the transaction met the following criteria: (1) there were no additional broad corporate reorganizations contemplated; (2) there was not a reason to believe that the gain would not be realized, since there is no additional capital raising transaction anticipated nor was there a significant concern about the new entity’s ability to continue in existence; (3) the share price of capital raised in the private placement was objectively determined; (4) no repurchases of the new subsidiary’s units are planned; and (5) Abraxas acknowledges that it will consistently apply the policy, and any future transactions that might result in a loss must be recorded as a loss in the statement of operations. Merger On June 30, 2009, Abraxas Petroleum and the Partnership signed an Agreement and Plan of Merger, which we refer to as the Original Merger Agreement, pursuant to which the Partnership agreed to merge with and into Abraxas Petroleum with Abraxas Petroleum surviving and on July 17, 2009, Abraxas Petroleum and the Partnership signed an Amended and Restated Agreement and Plan of Merger, which we refer to as the Merger Agreement, pursuant to which the Partnership agreed to merge with and into Merger Sub with Merger Sub surviving the merger as a wholly-owned subsidiary of Abraxas Petroleum. We refer to this merger as the Merger. Under the terms of the Merger Agreement, at the effective time of the Merger on October 5, 2009, which we refer to as the Effective Time, each common unit of the Partnership not owned by Abraxas Petroleum and its subsidiaries was converted into the right to receive 4.25 shares of Abraxas Petroleum common stock. We issued a total of 26,174,061 shares of our common stock in the Merger, including 420,552 shares of restricted common stock issued in exchange for restricted units and phantom units of the Partnership under the Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive Plan, or LTIP. Simultaneous with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility and we refinanced and amended and restated the Partnership Credit Facility, the Subordinated Credit Agreement and Abraxas’ previous credit facility and we borrowed approximately $145.0 million under the credit facility, of which $135.0 million was borrowed under the revolving portion of the credit facility and $10.0 million was borrowed under the term loan portion of the credit facility. See Note 4 Long-Term Debt. F o r m 1 0 - K Voting, Registration Rights & Lock-Up Agreement In connection with the Merger, Abraxas Petroleum agreed within 120 days of the Effective Time, to file a registration statement relating to the resale of the shares of Abraxas Petroleum common stock issued in the Merger, which we refer to as the Registration Statement, pursuant to the Securities Act of 1933, as amended, and to use commercially reasonable efforts to cause the Registration Statement to become effective and to keep the Registration Statement effective until the earlier of (A) January 3, 2013 and (B) the date that all shares of Abraxas Petroleum common stock covered by the prospectus have been sold or otherwise transferred pursuant to a registration statement or otherwise. As a result of Abraxas’ obligations in connection with the Merger, Abraxas filed a Registration Statement for the resale of a total of 25,234,467 shares of its common stock on October 19, 2009 and the Securities and Exchange Commission declared the Registration Statement effective on November 3, 2009. In connection with the Merger, the former limited partners of the Partnership who are party to the Voting, Registration Rights & Lock-Up Agreement (who beneficially own a total of 24,796,879 of the 26,174,061 shares of Abraxas Petroleum common stock issued in the Merger) agreed not to offer for sale, sell, pledge, or otherwise dispose of the Abraxas Petroleum common stock received in the Merger for the 90-day period immediately following the Effective Time, which we refer to as the Lock-Up Period. Upon the expiration of the Lock-Up Period, one-third of the Abraxas Petroleum common stock held by these former Partnership unitholders will be unrestricted and freely-tradable, subject to applicable securities laws. From and F-15 after the date which is 12 months after the end of the Lock-Up Period, an additional one-third (or a total of two-thirds) of the Abraxas Petroleum common stock held by these former Partnership unitholders will become unrestricted and freely-tradable and after the expiration of a total of 24 months following the end of the Lock-Up Period, all remaining shares of the Abraxas Petroleum common stock held by these former Partnership unitholders will become unrestricted and freely-tradable. 3. Acquisitions On January 31, 2008, Abraxas Operating, LLC, a then wholly-owned subsidiary of the Partnership, consummated the acquisition of certain oil and gas properties located in various states from St. Mary Land & Exploration Company (“St. Mary”) and certain other sellers for a purchase price of approximately $126.0 million. The properties are primarily located in the Rocky Mountains and Mid-Continent regions of the United States. Simultaneously, Abraxas Petroleum announced that it had completed the acquisition of certain oil and gas properties from St. Mary for a purchase price of approximately $5.6 million. Abraxas paid the purchase price from internal funds. The right to purchase these properties had been assigned to Abraxas by the Partnership. Substantially all amounts paid in the acquisition, including acquisition costs of approximately $1.1 million, were allocated to the oil and gas properties. The following unaudited supplemental information presents pro forma financial results assuming the acquisition had occurred on January 1 of 2008 and 2007. The unaudited pro forma financial results are not necessarily those that would have been attained had the acquisition occurred as of an earlier date, nor are they necessarily representative of the future results that may occur. Unaudited Pro Forma Financial Information Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) Earnings (loss) per share—basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $87,643 $58,242 1.26 $ $104,262 $ (50,281) (1.02) $ 4. Long-Term Debt The following is a description of the Company’s debt as of December 31, 2008 and 2009, respectively: Year ended December 31, 2007 2008 (in thousands) Partnership credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partnership subordinated credit agreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior secured credit facility—Term portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Senior secured credit facility—Revolving portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . Real estate lien note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2008 December 31, 2009 (in thousands) $125,600 40,000 — — 5,369 170,969 (40,134) $— — 8,000 138,500 5,233 151,733 (8,141) $130,835 $143,592 Maturities of long-term debt are as follows: Year ended December 31, (in thousands) 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter $ 8,141 152 138,665 173 184 4,418 $151,733 F-16 Abraxas Senior Secured Credit Facility On June 27, 2007, Abraxas entered into a senior secured revolving credit facility, which was amended on February 4, 2009, May 13, 2009 and August 7, 2009. This credit facility was refinanced, amended and restated by the credit facility entered into on October 5, 2009. Amended and Restated Partnership Credit Facility On May 25, 2007, the Partnership entered into a senior secured revolving credit facility which was amended and restated on January 31, 2008 and further amended on January 16, 2009, April 30, 2009, May 7, 2009, June 30, 2009 and July 22, 2009, which we refer to as the Partnership Credit Facility. The Partnership Credit Facility was refinanced, amended and restated by the credit facility entered into on October 5, 2009. Subordinated Credit Agreement On January 31, 2008, the Partnership entered into a subordinated credit agreement which was amended on January 16, 2009 and further amended on April 30, 2009, May 7, 2009, June 30, 2009, July 22, 2009, August 13, 2009 and August 31, 2009, which we refer to as the Subordinated Credit Agreement. The Subordinated Credit Agreement was refinanced, amended and restated by the credit facility entered into on October 5, 2009. Credit Facility On October 5, 2009, in connection with the closing of the Merger, we entered into an amended and restated senior secured credit facility with Société Générale, as administrative agent and issuing lender, and certain other lenders, which we refer to as the credit facility. In connection with the Merger, we refinanced and amended and restated the Partnership Credit Facility, the Subordinated Credit Agreement and Abraxas’ previous credit facility and we borrowed $145.0 million under the credit facility, of which $135.0 million was borrowed under the revolving portion of the credit facility and $10.0 million was borrowed under the term loan portion of the credit facility. As of December 31, 2009 $138.5 million was outstanding under the revolving portion of the credit facility and $8.0 million was outstanding under the term portion of the credit facility. The revolving portion of the credit facility has a maximum commitment of $300.0 million and availability under the revolving portion of the credit facility will be subject to a borrowing base. The borrowing base under the revolving portion of the credit facility is currently $145.0 million and will be determined semi-annually by the lenders based upon our reserve reports, one of which must be prepared by our independent petroleum engineers and one of which may be prepared internally. The amount of the borrowing base will be calculated by the lenders based upon their valuation of our proved reserves utilizing these reserve reports and their own internal decisions. In addition, the lenders, in their sole discretion, will be able to make one additional borrowing base redetermination during any six-month period between scheduled redeterminations and we will be able to request one redetermination during any six-month period between scheduled redeterminations. The lenders will also be able to make a redetermination in connection with any sales of producing properties with a market value of 5% or more of our then-current borrowing base and in connection with any hedge termination which could reduce the collateral value by 5% or more. Our borrowing base of $145.0 million was determined based upon our reserve report dated June 1, 2009. Our borrowing base can never exceed the $300.0 million maximum commitment amount. Outstanding amounts under the revolving portion of the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 1.5%—2.75%, depending on the utilization of the borrowing base, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 2.5%—3.75%, depending on the utilization of the borrowing base. At December 31, 2009, the interest rate on the revolving portion of the credit facility was 5.75%. We also borrowed $10.0 million under the term loan portion of the credit facility at the closing of the Merger. Outstanding amounts under the term loan portion of the credit facility bear interest at (a) the greater of (1) the reference rate announced from time to time by Société Générale, (2) the Federal Funds Rate plus 0.5%, and (3) a rate determined by Société Générale as the daily one-month LIBOR plus, in each case, (b) 4.75%, or, if we elect, at the greater of (1) 2.0% and (2) LIBOR plus, in each case, 5.75%. At December 31, 2009, the interest rate on the term loan portion of the credit facility was 7.75%. The term loan portion of the credit facility is subject to amortization beginning on January 31, 2010. The first amortization installment of $1.0 million is due on January 31, 2010 and the second amortization installment of $3.0 million is due on March 31, 2010; thereafter, a quarterly amortization installment of $2.0 million is due at the end of each quarter until the term loan is repaid. It is anticipated that the term loan will be repaid on or before December 31, 2010, after which, it may F-17 F o r m 1 0 - K not be redrawn. The term loan portion of the credit facility was paid down to $8.0 million at December 31, 2009 and on January 29, 2010 an additional $3.0 million was paid. The balance of the term portion of the credit facility was $5.0 million as of January 29, 2010. As of December 31, 2009 there was $6.5 million available under the credit facility. Subject to earlier termination rights and events of default, the stated maturity date of the credit facility is October 5, 2012. Interest is payable quarterly on reference rate advances and not less than quarterly on Eurodollar advances. We are permitted to terminate the credit facility and are able, from time to time, to permanently reduce the lenders’ aggregate commitment under the credit facility in compliance with certain notice and dollar increment requirements. Each of our subsidiaries (other than Canadian Abraxas Petroleum Corporation) has guaranteed our obligations under the credit facility on a senior secured basis. Obligations under the credit facility are secured by a first priority perfected security interest, subject to certain permitted encumbrances, in all of our and our subsidiary guarantors’ material property and assets. Under the credit facility, we are subject to customary covenants, including certain financial covenants and reporting requirements. We are required to maintain a current ratio as of the last day of each quarter of not less than 1.00 to 1.00 and an interest coverage ratio as of the last day of each quarter of not less than 2.50 to 1.00. We are also required to maintain a total debt to EBITDAX ratio as of the last day of each quarter of not more than 4.50 to 1.00 for the quarter ending September 30, 2009 through the quarter ending September 30, 2010, and not more than 4.00 to 1.00 thereafter. The current ratio is defined as the ratio of consolidated current assets to consolidated current liabilities. For the purposes of this calculation, current assets include the portion of the borrowing base which is undrawn but excludes any cash deposited with or at the request of a counter-party to a hedging arrangement and any assets representing a valuation account arising from the application of ASC 815 (which relates to derivative instruments and hedging activities and was formerly referred to as SFAS 133) and ASC 410-20 (which relates to asset retirement obligations and was formerly referred to as SFAS 143) and current liabilities exclude the current portion of long-term debt and any liabilities representing a valuation account arising from the application of ASC 815 and ASC 410-20. The interest coverage ratio is defined as the ratio of consolidated EBITDAX to consolidated interest expense for the four fiscal quarters ended on the calculation date after giving pro forma effect to the Merger. For the purposes of this calculation, EBITDAX is consolidated net income plus interest expense, oil and gas exploration expenses, taxes, depreciation, amortization, depletion and other non-cash charges including non-cash charges resulting from the application of ASC 718 (which relates to stock-based compensation and was formerly referred to as SFAS 123R), ASC 815 and ASC 410-20 plus all realized net cash proceeds arising from the settlement or monetization of any hedge contracts or upon the termination of any hedge contract minus all non-cash items of income which were included in determining consolidated net income, including all non-cash items resulting from the application of ASC 815 and ASC 410-20. Interest expense includes total interest, letter of credit fees and other fees and expenses incurred in connection with any debt. The total debt to EBITDAX ratio is defined as the ratio of total debt to consolidated EBITDAX for the four fiscal quarters ended on the calculation date after giving pro forma effect to the Merger. For the purposes of this calculation, total debt is the outstanding principal amount of debt, excluding debt associated with the office building, and obligations with respect to surety bonds and hedge arrangements. The credit facility also required that we enter into hedging arrangements for specified volumes, which equate to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2012 and 70% for 2013. We satisfied this requirement by assuming all of the Partnership’s derivative contracts in connection with the Merger. The following table sets forth our derivative contract position as of December 31, 2009: Contract Periods 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed Price Swap Oil Gas Daily Volume (Bbl) 1,158 1,035 946 705 Swap Price $73.28 76.61 70.89 80.79 Daily Volume (Mmbtu) 11,258 9,580 8,303 5,962 Swap Price $5.73 6.52 6.77 6.84 F-18 In addition to the foregoing and other customary covenants, the credit facility contains a number of covenants that, among other things, restrict our ability to: • • • • • • incur or guarantee additional indebtedness; transfer or sell assets; create liens on assets; engage in transactions with affiliates other than on an “arm’s-length” basis; make any change in the principal nature of our business; and permit a change of control. The credit facility also contains customary events of default, including nonpayment of principal or interest, violations of covenants, cross default and cross acceleration to certain other indebtedness, bankruptcy and material judgments and liabilities. We were in compliance with all covenants as of December 31, 2009. As of December 31, 2009, the current ratio was 1.29 to 1.00, the interest coverage ratio was 4.75 to 1.00 and the total debt to EBITDAX ratio was 2.32 to 1.00. Real Estate Lien Note On May 9, 2008, the Company entered into an advancing line of credit in the amount of $5.4 million for the purchase and finish out of a building to serve as its corporate headquarters. This note was refinanced in November 2008. The note bears interest at a fixed rate of 6.375%, and is payable in monthly installments of principal and interest of $39,754 based on a twenty year amortization. The note matures in May 2015 at which time the outstanding balance becomes due. The note is secured by a first lien deed of trust on the property and improvements. As of December 31, 2009, $5.2 million was outstanding on the note. 5. Property and Equipment The major components of property and equipment, at cost, are as follows: Oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equipment and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimated Useful Life Years — 3-39 December 31, 2008 2009 (In thousands) $440,712 10,986 $454,142 11,259 $451,698 $465,401 F o r m 1 0 - K 6. Stock-based Compensation, Option Plans and Warrants Stock-based Compensation The Company currently utilizes a standard option pricing model (i.e., Black-Scholes) to measure the fair value of stock options granted to employees. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 2007, 2008 and 2009, risk-free interest rates of 4.63% in 2007, 4.39% in 2008 and 2.48% in 2009; dividend yields of -0-%; volatility factors of the expected market price of the Company’s common stock of 55% in 2007, 52% in 2008 and 83% in 2009, determined by daily historical prices as well as other market indicators, and a weighted-average expected life of the option of 7.14 years in 2007, 7.86 years in 2008 and 6.13 in 2009. Stock Options The Company grants options to its officers, directors, and other employees under various stock option and incentive plans. The Company’s 2005 Directors Plan (as defined below), has authorized the grant of options to directors for up to 900,000 shares of the Company’s common stock. All options granted generally become fully exercisable over three to four years of continued service at 25% to 33% on each anniversary date or as specified by the Compensation Committee of the Board of Directors. F-19 The Company’s 2005 Employee Long-Term Equity Incentive Plan has authorized the grant of up to 5.2 million awards to management and employees, including options. Options have a term not to exceed 10 years. Options issued under this plan vest according to a vesting schedule as determined by the compensation committee. Vesting may occur upon (1) the attainment of one or more performance goals or targets established by the committee (2) the optionee’s continued employment or service for a specified period of time, (3) the occurrence of any event or the satisfaction of any other condition specified by the committee; or (4) a combination of any of the foregoing. A summary of the Company’s stock option activity for the three years ended December 31, 2009 follows: Options (000s) Weighted- Average Exercise Price Weighted Average Remaining Life Intrinsic value Per Share Options outstanding December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,457 $2.29 Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited/Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Options outstanding December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited/Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Options outstanding December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited/Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 383 (310) (4) 2,526 86 (183) (39) 2,390 2,175 (250) (225) Options outstanding December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,090 Exercisable at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,808 3.75 1.12 5.37 $2.65 4.37 1.37 2.55 $2.81 1.41 0.93 2.73 2.18 7.30 4.69 $1.59 $2.31 Other information pertaining to option activity was as follows during the years ended December 31: Weighted average grant-date fair value of stock options granted (per share) . . . . . . . . . . . . . . . . . . . . Total fair value of options vested (000’s) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total intrinsic value of options exercised (000’s) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.26 $ 888 $ 256 $ 2.47 $1,022 $ 149 $1.01 $ 801 $ 155 2007 2008 2009 As of December 31, 2009, the total compensation cost related to non-vested awards not yet recognized is approximately $2.2 million, which will be recognized in 2010 through 2013. The following table represents the range of option prices and the weighted average remaining life of outstanding options as of December 31, 2009: Options outstanding Exercisable $0.50 – 0.99 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1.00 – 1.99 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.00 – 2.99 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3.00 – 3.99 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4.00 – 4.99 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5.00 – 6.05 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted average remaining life Weighted average exercise price 6.46 9.14 5.04 7.59 5.91 6.07 $0.86 $1.67 $2.69 $3.60 $4.57 $6.05 Number exercisable 582,705 155,000 66,857 142,309 800,001 60,750 1,807,622 Weighted average remaining life Weighted average exercise price 2.24 4.26 5.04 7.58 5.91 6.07 $0.66 $1.16 $2.69 $3.60 $4.56 $6.05 Number outstanding 1,486,005 1,365,035 66,857 290,994 800,001 81,000 4,089,892 F-20 Restricted Stock Awards Restricted stock awards are awards of common stock that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such stock is determined using the market price on the grant date. Compensation expense is recorded over the applicable restricted stock vesting periods. A summary of the Company’s restricted stock activity for the year ended December 31, 2009 is presented in the following table: Unvested December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unvested December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unvested December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested/Released . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of Shares — 152,736 — (388) 152,348 55,952 (41,061) (2,959) 164,280 462,552 (74,648) (3,276) Unvested December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 548,908 Weighted average grant date fair value $ — 3.60 — — $3.60 2.85 3.60 3.51 $3.35 1.71 2.76 2.62 $2.05 Restricted Unit Awards Restricted unit awards are awards of Partnership units that are subject to restrictions on transfer and to a risk of forfeiture if the awardee terminates employment with the Company prior to the lapse of the restrictions. The value of such unit is determined using the implied market price on the grant date. The implied market price is determined by comparing the average trading yields of comparable publicly-traded master limited partnerships to the most recent quarterly distribution paid or declared by the Partnership. Compensation expense is recorded over the applicable restricted unit vesting periods. For the year ended December 31, 2009, the Partnership incurred equity-based compensation expense of $69,000, relating to restricted units. In connection with the closing of the Merger, restricted unit awards were converted into restricted stock awards of the Company. See Note 2. Recent Events F o r m 1 0 - K Phantom Units On January 31, 2008, in connection with the closing of the St. Mary acquisition, the Board of Directors of the general partner of the Partnership awarded phantom units with distribution equivalency rights under its long-term incentive plan to certain key employees of Abraxas Petroleum. The phantom units and associated distribution equivalency rights will vest over four years and their value is based on the price of common units, as determined by the Board of Directors of the general partner of the Partnership, quarterly cash distributions and the percentage increase in cash distributions over time. For the year ended December 31, 2008 and 2009, the Partnership incurred equity based compensation expense of $242,000 and $25,000 respectively, relating to phantom units. In connection with the closing of the Merger, outstanding phantom unit awards were converted into restricted stock awards of the Company. See Note 2. Director Stock Awards On June 1, 2005, the stockholders approved the 2005 Non-Employee Directors Long-Term Equity Incentive Plan (the “2005 Directors Plan”). The following is a summary of the 2005 Directors Plan. F-21 Purpose. The purpose of the 2005 Directors Plan is to attract and retain members of the Board of Directors and to promote the growth and success of Abraxas by aligning the long-term interests of the Board of Directors with those of Abraxas’ stockholders by providing an opportunity to acquire an interest in Abraxas and by providing both rewards for performance and long term incentives for future contributions to the success of Abraxas. Administration and Eligibility. The 2005 Directors Plan will be administered by the Compensation Committee (the “Committee”) of the Board of Directors and authorizes the Board to grant non-qualified stock options or issue restricted stock to those persons who are non-employee directors of Abraxas, including advisory directors of Abraxas, which currently amounts to a total of nine people. Shares Reserved and Awards. The 2005 Directors Plan reserves 900,000 shares of Abraxas common stock, subject to adjustment following certain events, as discussed below. The 2005 Directors Plan provides that each year, at the first regular meeting of the Board of Directors immediately following Abraxas’ annual stockholder’s meeting, each non-employee director shall be granted or issued awards of 10,000 shares of Abraxas common stock, for participation in Board and Committee meetings during the previous calendar year. The maximum annual award for any one person is 60,000 shares of Abraxas common stock or options for common stock. If options, as opposed to shares, are awarded, the exercise share price shall be no less than 100% of the fair market value on the date of the award while the option terms and vesting schedules are at the discretion of the Committee. In addition to the 10,000 shares or options, directors are compensated $20,000 per year, $12,000 of which is paid quarterly by issuance of common stock and the remaining $8,000 is paid quarterly in cash. During 2007, 2008, and 2009 there were 22,960; 30,655; and 61,954 shares, respectively, issued related to this compensation. The number of shares issued is determined based on the stock price on the date of issuance. At December 31, 2009, the Company had approximately 2.1 million shares reserved for future issuance for conversion of its stock options, warrants, and incentive plans for the Company’s directors, employees and consultants. Warrants On May 25, 2007, Abraxas entered into a Securities Purchase Agreement with certain accredited investors pursuant to which Abraxas issued warrants to purchase 1,174,938 shares of common stock, to the investors at a price of $3.83 per share. The warrants expire on May 25, 2012 and are exercisable at a price of $3.83 per share, subject to certain adjustments. During 2008, 182,768 warrants were exercised. No warrants were exercised in 2009. 7. Income Taxes Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax liabilities and assets are as follows: December 31, 2007 2008 2009 (In thousands) Deferred tax liabilities: Marketable securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partnership interest Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax assets: $ 169 26,356 26,525 U.S. full cost pool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depletion carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net operating loss (“NOL”) carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Suspended losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Alternative minimum tax credit Allocated minority loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hedge contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135 5,010 5,179 60,067 1,400 100 — — 1,805 $ 33 $ 18,349 18,382 418 — 5,189 68,034 — 78 3,267 — 2,159 67 — 67 37,360 — 4,421 42,583 — 503 — 3,798 2,890 Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Valuation allowance for deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73,696 (47,171) 26,525 79,145 (60,763) 18,382 91,555 (91,488) 67 Net deferred tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ — F-22 Significant components of the provision (benefit) for income taxes are as follows: Current: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred: Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years ended December 31, 2007 2008 2009 (in thousands) $ 100 183 — $ 283 $ — — $ — $— — — $— $— — — $ 425 865 — $1,290 $— — — At December 31, 2009, the Company had, subject to the limitation discussed below, $121.7 million of net operating loss carryforwards for U.S. tax purposes. These loss carryforwards will expire from 2022 through 2028 if not utilized. In addition to any Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under SFAS Statement No. 109. Therefore, the Company has established a valuation allowance of $60.8 million at December 31, 2008 and $91.5 million at December 31, 2009. The reconciliation of income tax computed at the U.S. federal statutory tax rates to income tax expense is: Years ended December 31, 2007 2008 2009 Tax (expense) benefit at U.S. statutory rates (35%) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Increase) Decrease in deferred tax asset valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . Expired capital loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Increase in asset basis for merger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (In thousands) $(19,945) $ 18,341 $ 6,121 (30,725) (13,592) (4,742) — 19,701 — (183) — (5) — 149 — (6) (1) (562) (4) 23,986 (106) $ (283) $ — $ (1,290) We account for uncertain tax positions under provisions of ASC 740-10. ASC 740-10 did not have any effect on the Company’s financial position or results of operations as of January 1, 2007 or for the year ended December 31, 2009. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2009, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 1999 through 2008 remain open to examination by the tax jurisdictions to which the Company is subject. 8. Commitments and Contingencies Operating Leases During the years ended December 31, 2007 and 2008 the Company incurred rent expense related to leasing office facilities of approximately $254,000 and $321,000. During 2008 the Company acquired a building for its corporate headquarters; accordingly there are no future minimum rental payments under such leases at December 31, 2009. In September 2009, the Company leased office space in Calgary, Alberta. During 2009, rent expense of $32,300CN was incurred related to this lease. Litigation and Contingencies From time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At December 31, 2009 the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company. F-23 F o r m 1 0 - K 9. Earnings per Share The following table sets forth the computation of basic and diluted earnings per share: Years ended December 31: 2007 2008 2009 (in thousands, except per share data) Numerator: Income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $56,702 $(52,403) $(18,780) Denominator: Denominator for basic earnings per share—weighted-average common shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of dilutive securities: Stock options, restricted shares and warrants . . . . . . . . . . . 46,337 1,257 49,005 — 55,499 — Dilutive potential common shares Denominator for diluted earnings per share— adjusted weighted-average shares and assumed exercise of options, restricted shares and warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per common share—Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per common share—Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47,593 49,005 55,499 $ $ 1.22 1.19 $ $ (1.07) $ (0.34) (1.07) $ (0.34) Basic earnings per share excludes any dilutive effects of options, warrants unvested restricted stock and convertible securities and is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share are computed similar to basic, however diluted earnings per share reflects the assumed conversion of all potentially dilutive securities. For the years ended December 31, 2008 and 2009, 334,656 and 310,692 potential shares relating to stock options, were excluded from the calculation of diluted earnings per share since their inclusion would have been anti-dilutive due to the loss incurred in the period. 10. Quarterly Results of Operations (Unaudited) Selected results of operations for each of the fiscal quarters during the years ended December 31, 2008 and 2009 are as follows: Year Ended December 31, 2008 Net revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss)(2) $ 34,423 $29,246 $22,170 $ 19,183 $13,925 $ 9,865 $ (8,991) $(57,688) $70,755 $ 14,471 $(116,990) $ (56,479) Net income (loss) per common share—basic . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per common share—diluted . . . . . . . . . . . . . . . . . . . . . . . $ (0.18) $ $ (0.18) $ (1.18) $ (1.18) $ 1.44 1.43 $ $ (1.15) (1.15) 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (In thousands, except per share data) Year Ended December 31, 2009 Net revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $10,850 $ (1,823) $ $ 4,450 $ 12,368 64 $ 16,123 $13,409 1,379 $ 557 $ $(10,032) $ (4,370) $ (8,828) Net income (loss) per common share—basic . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per common share—diluted . . . . . . . . . . . . . . . . . . . . . . . $ $ 0.09 0.09 $ $ (0.20) $ (0.09) $ (0.20) $ (0.09) $ (0.12) (0.12) (1) Fourth quarter includes proved property impairment of $116.4 million, $7.1 million of losses not applicable to the non-controlling interest, and a $0.3 million loss on conversion of Partnership units to Abraxas Petroleum common shares. (2) Third quarter includes gain on sale of interest in partnership of $59.4 million. 11. Benefit Plans The Company has a defined contribution plan (401(k)) covering all eligible employees of the Company. The Company matched 50% of employee contributions in 2007. The Company contribution to the plan for 2007 was $168,977. In 2008 and 2009, in accordance with the safe harbor provisions of the plan the Company contributed $144,954 and $157,436 to the plan. The employee contribution limitations are determined by formulas, which limit the upper one third of the plan members from F-24 contributing amounts that would cause the plan to be top-heavy. The employee contribution is limited to $15,500, $15,500 and $16,500 in 2007, 2008 and 2009 for employees under the age of 50, respectively. The contribution limit for 2007, 2008 and 2009 was $20,500, $20,500 and $22,000 for employees 50 years of age or older, respectively. 12. Hedging Program and Derivatives The derivative instruments we utilize are based on index prices that may and often do differ from the actual oil and gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivate instruments to qualify for hedge accounting rules as prescribed by ASC 815. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead record their fair value on the balance sheet with adjustments to the carrying value of the instruments being recognized as a gain or loss on derivative contracts in the current period. The terms of the credit facility required us to enter into hedging arrangements for specified volumes, which equate to approximately 85% of the estimated oil and gas production from our net proved developed producing reserves through December 31, 2012 and 70% for 2013. We satisfied this requirement by assuming all of the Partnership’s derivative contracts in connection with the Merger. The following table sets forth our derivative contract position as of December 31, 2009: Contract Periods 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fixed Price Swap Oil Gas Daily Volume (Bbl) 1,158 1,035 946 705 Swap Price $73.28 76.61 70.89 80.79 Daily Volume (Mmbtu) 11,258 9,580 8,303 5,962 Swap Price $5.73 6.52 6.77 6.84 In order to mitigate our interest rate exposure, we entered into an interest rate swap, effective August 12, 2008, to fix our floating LIBOR-based debt. The two-year interest rate swap arrangement for $100 million at a fixed rate of 3.367% expires on August 12, 2010. This interest rate swap was amended in February 2009 lowering our fixed rate to 2.95%. The interest rate swap was further amended in November 2009, lowering our fixed rate to 2.55% and extending the term through August 12, 2012. The following table illustrates the impact of derivative contracts on the Company’s balance sheet: December 31, 2008 December 31, 2009 Balance Sheet Location Fair Value (thousands) Balance Sheet Location Fair Value (thousands) NYMEX-based fixed price derivative contracts . . . . . . . . . . . . . . Derivative $22,832 asset—current NYMEX-based fixed price derivative contracts . . . . . . . . . . . . . . Derivative $16,394 asset—long- term NYMEX-based fixed price derivative contracts . . . . . . . . . . . . . . Derivative liability— current NYMEX-based fixed price derivative contracts . . . . . . . . . . . . . . Derivative liability— long-term Interest rate swap . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Derivative liability— current $ — $ — $ 3,000 Derivative asset—current Derivative asset—long- term Derivative liability— current Derivative liability— long-term Derivative liability— current $ 325 $ 2,253 4,791 11,780 $ 2,256 Gains and losses from derivative activities are reflected as “Loss (gain) on derivative contracts” in the accompanying Consolidated Statement of Operations. F-25 F o r m 1 0 - K 13. Financial Instruments Effective January 1, 2008, the Company adopted ASC 820-10 (formerly SFAS 157) which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate, which was not material. The primary impact from adoption was additional disclosures. Fair Value on a Non-Recurring Basis On January 1, 2009, the Company adopted the provisions of ASC 820-10 (formerly SFAS 157) for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to Abraxas, the adoption applies to certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value, impaired oil and gas property assessments; and the initial recognition of asset retirement obligations for which fair value is used. The adoption of ASC 820-10 did not have material impact on the Company’s consolidated financial statements or its disclosures with respect to the initial recognition of asset retirement obligations during the year ended December 31, 2009. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Abraxas has designated these liabilities as Level 3. Fair Value Hierarchy—ASC 820-10 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • • • Level 1—inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2—inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3—inputs to the valuation methodology are unobservable and significant to the fair value measurement. A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Company is further required to assess the creditworthiness of the counter-party to the derivative contract. The results of the assessment of non-performance risk, based on the counter-party’s credit risk, could result in an adjustment of the carrying value of the derivative instrument. The following tables presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2008 and 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value (in thousands): Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2008 Assets: Investment in common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NYMEX Fixed Price Derivative contracts . . . . . . . . . . . . . . . . . . . . . . Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities: NYMEX Fixed Price Derivative contracts . . . . . . . . . . . . . . . . . . . . . . Interest Rate Swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 113 — $ 113 $— — $— $ — 39,226 $39,226 $ — — $ — $ — — $ — $ — 3,000 $3,000 $ 113 39,226 $39,339 $ — 3,000 $ 3,000 F-26 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance as of December 31, 2009 Assets: Investment in common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NYMEX Fixed Price Derivative contracts . . . . . . . . . . . . . . . . . . . . . . Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities: NYMEX Fixed Price Derivative contracts . . . . . . . . . . . . . . . . . . . . . . Interest Rate Swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $208 — $208 $— — $— $— 2,578 $ 2,578 $16,571 — $16,571 $— — $— $— 2,256 $2,256 $ 208 2,578 $ 2,786 $16,571 2,256 $18,827 The Company has an investment in a former subsidiary consisting of shares of common stock. The stock is actively traded on the Toronto Stock Exchange. This investment is valued at its quoted price as of December 31, 2009 in US dollars. Accordingly this investment is characterized as Level 1. The Company’s derivative contracts consist of NYMEX-based fixed price commodity swaps and interest rate swaps, which are not traded on a public exchange. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity, and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2. In August 2008, the Company entered into a two year interest rate swap. The notional amount was $100.0 million for the first year and $50.0 million for the second year. The Company will pay interest at 3.367% and be paid on a floating LIBOR rate. The interest rate swap was amended in February 2009 and increased the notional amount in the second year to $100.00 million and reduced the overall interest rate to 2.95%. The interest rate swap was further amended in November 2009 reducing the interest rate to 2.55% and extending the term through August 12, 2012. As there is no actively traded market for this type of swap and no observable market parameters, these derivative contracts are classified as Level 3. Additional information for the Company’s recurring fair value measurements using significant unobservable inputs (Level 3 inputs) for the year ended December 31, 2009 is as follows (in thousands): Balance December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total realized and unrealized losses included in change in net liability . . . . . . . . . . . . . . . . . . . . . . . . Settlements during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total realized and unrealized losses included in change in net liability . . . . . . . . . . . . . . . . . . . . . . . . Settlements during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $— (2,832) (168) (3,000) (1,816) 2,560 Balance December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(2,256) Derivative Assets and (Liabilities) - net 14. Non-controlling interest in (income) loss of Partnership The non-controlling interest in the (income) loss of the Partnership represents the third parties 51.8% interest in the Partnership’s net income/ loss, through the date of the Merger. In accordance with generally accepted accounting principles in effect prior to the adoption of ASC 810, which codifies SFAS 160, when cumulative losses applicable to the non-controlling interest exceed the non-controlling interest equity capital in the entity, such excess and any further losses applicable to the non-controlling interest were charged to the earnings of the controlling interest. Future earnings were recognized by the non-controlling interest and were credited to the controlling interest (Abraxas) to the extent of such losses F-27 F o r m 1 0 - K previously absorbed. For the year ended December 31, 2008, primarily as a result of the ceiling test impairment of the Partnership’s oil and gas properties, losses applicable to the non-controlling interest exceeded the non-controlling equity capital by $9.3 million. As a result, $9.3 million of the non-controlling interest loss in excess of equity was charged to earnings attributable to Abraxas and was reflected as a reduction of the loss applicable to the non-controlling interest. 15. Subsequent Events Non-Core Divestitures We have initiated a divestiture program, principally aimed at non-operated, non-core assets, to generate cash for debt repayment and to accelerate our drilling program. During the fourth quarter of 2009 and the first quarter of 2010, we have sold certain non-core assets for combined net proceeds of approximately $11.2 million ($2.4 million in 2009 and $8.8 million in 2010). In total, these properties produced approximately 142 Boepd (approximately 3% of our daily net production) and had approximately 606 MBoe of proved reserves (approximately 2% of our net proved reserves), which equates to $78,385 per producing Boepd and $18.41 per proved Boe. The first $10 million of net proceeds will be used to repay the term loan portion of our credit facility after which, any net proceeds will be allocated approximately 50% for further debt reduction and 50% to accelerate our capital program. We have identified an additional $20 to $30 million of similar non-core assets that we will attempt to divest on similar terms over the next several months. Tax Benefits Preservation Plan On March 16, 2010, our board of directors adopted a Tax Benefits Preservation Plan (the “Tax Benefits Preservation Plan”) and declared a dividend of one preferred share purchase right for each outstanding share of Abraxas common stock. The dividend is payable to our stockholders of record as of March 16, 2010. The terms of the rights and the Tax Benefits Preservation Plan are set forth in a Rights Agreement, by and between us and American Stock Transfer & Trust Company, as Rights Agent, dated as of March 16, 2010. This summary of rights provides only a general description of the Tax Benefits Preservation Plan. We adopted the Tax Benefits Preservation Plan in an effort to protect stockholder value by attempting to protect against a possible limitation on our ability to use our net operating loss carryforwards, or NOL’s, to reduce potential future federal income tax obligations. We have experienced and continue to experience substantial operating losses, and under the Internal Revenue Code and rules promulgated by the Internal Revenue Service, we may “carry forward” these losses in certain circumstances to offset any current and future earnings and thus reduce our federal income tax liability, subject to certain requirements and restrictions. To the extent that the NOLs do not otherwise become limited, we believe that we will be able to carry forward a significant amount of NOLs, and therefore these NOLs could be a substantial asset to us. However, if we experience an “Ownership Change,” as defined in Section 382 of the Internal Revenue Code, our ability to use the NOLs will be substantially limited, and the timing of the usage of the NOLs could be substantially delayed, which could therefore significantly impair the value of that asset. As of December 31, 2009, we had net operating loss carryforwards of $121.7 million. The Tax Benefits Preservation Plan is intended to act as a deterrent to any person or group acquiring 4.9% or more of our outstanding common stock, or an Acquiring Person, without our approval. Stockholders who own 4.9% or more of our outstanding common stock as of the close of business on March 16, 2010 will not trigger the Tax Benefits Preservation Plan so long as they do not (i) acquire any additional shares of common stock or (ii) fall under 4.9% ownership of common stock and then re–acquire 4.9% or more of the common stock. The Tax Benefits Preservation Plan does not exempt any future acquisitions of common stock by such persons. Any rights held by an Acquiring Person are null and void and may not be exercised. We may, in our sole discretion, exempt any person or group from being deemed an Acquiring Person for purposes of the Tax Benefits Preservation Plan. The Rights. We authorized the issuance of one right per each outstanding share of our common stock payable to our stockholders of record as of March 16, 2010. Subject to the terms, provisions and conditions of the Tax Benefits Preservation Plan, if the rights become exercisable, each right would initially represent the right to purchase from us one one–thousandth of a share of our Series 2010 Junior Participating Preferred Stock (“Series 2010 Preferred Stock”) for a purchase price of $7.00 (the “Purchase Price”) . If issued, each fractional share of Series 2010 Junior Preferred Stock would give the stockholder approximately the same dividend, voting and liquidation rights as does one share of our common stock. However, prior to exercise, a right does not give its holder any rights as a stockholder of the Company, including without limitation any dividend, voting or liquidation rights. F-28 Series 2010 Preferred Stock Provisions. Each one one-thousandth of a share of Series 2010 Preferred Stock, if issued: (1) will not be redeemable; (2) will entitle holders to quarterly dividend payments of $0.01 per one one-thousandth of a share of Series 2010 Preferred Stock, or an amount equal to the dividend paid on one share of common stock, whichever is greater, if, as and when declared by our board of directors out of funds legally available therefor; (3) will entitle holders upon liquidation either to receive $1.00 per one one-thousandth of a share of Series 2010 Preferred Stock or an amount equal to the payment made on one share of common stock, whichever is greater; (4) will have the same voting power as one share of common stock; and (5) if shares of our common stock are exchanged via merger, consolidation, or a similar transaction, will entitle holders to a per share payment equal to the payment made on one share of common stock. The value of one one-thousandth interest in a Preferred Share should approximate the value of one share of common stock. Exercisability. The rights will not be exercisable until the earlier of (i) 10 business days after a public announcement by us that a person or group has become an Acquiring Person or (ii) 10 business days after the commencement of a tender or exchange offer by a person or group for 4.9% of the common stock. We refer to the date that the rights become exercisable as the “Distribution Date.” Until the Distribution Date, our common stock certificates will evidence the rights and will contain a notation to that effect. Any transfer of shares of common stock prior to the Distribution Date will constitute a transfer of the associated rights. After the Distribution Date, the rights may be transferred other than in connection with the transfer of the underlying shares of common stock. After the Distribution Date, each holder of a right, other than rights beneficially owned by the Acquiring Person (which will thereupon become void), will thereafter have the right to receive upon exercise of a right and payment of the Purchase Price, that number of shares of common stock having a market value at the time of exercise of two times the Purchase Price. Exchange. After the Distribution Date, we may exchange the rights (other than rights owned by an Acquiring Person, which will have become void), in whole or in part, at an exchange ratio of one share of common stock, or a fractional share of Series 2010 Preferred Stock (or of a share of a similar class or series of the Company’s preferred stock having similar rights, preferences and privileges) of equivalent value, per right (subject to adjustment). Expiration. The rights and the Tax Benefits Preservation Plan will expire on the earliest of (i) March 16 2015, (ii) the time at which the rights are redeemed pursuant to the Rights Agreement, (iii) the time at which the rights are exchanged pursuant to the Rights Agreement, (iv) the repeal of Section 382 of the Code or any successor statute if we determine that the Rights Agreement is no longer necessary for the preservation of NOLs and (v) the beginning of a taxable year of the Company of which we determine that no NOLs may be carried forward. Redemption. At any time prior to the time an Acquiring Person becomes such, we may redeem the rights in whole, but not in part, at a price of $0.01 per right (the “Redemption Price”). The redemption of the rights may be made effective at such time, on such basis and with such conditions as we in our sole discretion may establish. Immediately upon any redemption of the rights, the right to exercise the rights will terminate and the only right of the holders of rights will be to receive the Redemption Price. Anti-Dilution Provisions. We may adjust the purchase price of the shares of Series 2010 Preferred Stock, the number of shares Series 2010 Preferred Stock issuable and the number of outstanding rights to prevent dilution that may occur as a result of certain events, including among others, a stock dividend, a stock split or a reclassification of the shares of Series 2010 Preferred Stock or our common stock. No adjustments to the purchase price of less than 1% will be made. Amendments. Before the Distribution Date, we may amend or supplement the Tax Benefits Preservation Plan without the consent of the holders of the rights. After the Distribution Date, we may amend or supplement the Tax Benefits Preservation Plan only to cure an ambiguity, to alter time period provisions, to correct inconsistent provisions, or to make any additional changes to the Tax Benefits Preservation Plan, but only to the extent that those changes do not impair or adversely affect any rights holder. The rights have certain anti-takeover effects. The rights will cause substantial dilution to a person or group who attempts to acquire the Company on terms not approved by us. The rights should not interfere with any merger or other business combination approved by us since we may redeem the rights at $0.01 per right at any time until the date on which a person or group has become an Acquiring Person. F-29 F o r m 1 0 - K 16. Supplemental Oil and Gas Disclosures (Unaudited) The accompanying table presents information concerning the Company’s oil and gas producing activities as required by ASC 932-235, “Disclosures about Oil and Gas Producing Activities.” Capitalized costs relating to oil and gas producing activities are as follows: Proved oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 440,712 — $ 454,142 — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated depreciation, depletion, and amortization, and impairment 440,712 (287,993) 454,142 (305,354) Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 152,719 $ 148,788 December 31, 2008 2009 (In thousands) Cost incurred in oil and gas property acquisitions and development activities are as follows: Development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $16,793 — 10,000 (In thousands) $ 38,644 1,920 127,671 $15,356 795 — $26,793 $168,235 $16,151 Years Ended December 31, 2007 2008 2009 The results of operations for oil and gas producing activities for the three years ended December 31, 2007, 2008 and 2009, respectively are as follows: Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved property impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Years Ended December 31, 2007 2008 2009 $ 46,906 (11,254) (14,147) — (1,361) (In thousands) $ 99,084 $ 51,829 (26,224) (17,361) (26,635) (23,077) (116,366) — (1,431) (1,617) Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 20,144 $ (68,425) $ 6,627 Depletion rate per barrel of oil equivalent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 12.58 $ 14.42 $ 10.63 Estimated Quantities of Proved Oil and Gas Reserves The following table presents the Company’s estimate of its net proved oil and gas reserves as of December 31, 2007, 2008, and 2009. The Company’s management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been predominately prepared by independent petroleum reserve engineers. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States. F-30 Proved reserves were estimated in accordance with guidelines established by the United States Securities and Exchange Commission and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements; therefore, the average prior 12-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows as of December 31, 2009. However, period end prices and costs were used in estimating reserve volumes and future net cash flows as of December 31, 2008 and 2007. Proved developed and undeveloped reserves: Balance at December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of previous estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of previous estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchases of minerals in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales of minerals in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of previous estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved developed reserves: December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liquid Hydrocarbons (Barrels) Gas (Mcf) (In thousands) 2,756 541 31 (197) 3,131 (1,651) 458 5,684 (27) (550) 7,045 193 2,173 (579) 8,832 70,333 8,652 14,586 (5,568) 88,003 (6,160) 5,862 27,110 (56) (6,343) 108,416 (14,652) 9,090 (6,329) 96,525 Liquid Hydrocarbons (Barrels) Gas (Mcf) (In thousands) 2,184 5,563 5,891 33,908 48,209 47,861 F o r m 1 0 - K Reserve extensions and discoveries which increased significantly during 2007 were primarily attributable to the Yoakum (Edwards) field in the Gulf Coast region. Other operators in neighboring fields have been successful with closer spacing and new completion techniques which resulted in the booking of additional proved undeveloped reserves in our field. Revisions of previous estimates which increased appreciably during 2007 were primarily attributable to higher commodity prices at December 31, 2007 over the prior year-end which extends the economic life of many wells and thus, increases reserves estimates. Purchases of minerals in place increased significantly during 2008 which was attributable to the acquisition of oil and gas properties from St. Mary in January 2008. Revisions of previous estimates which decreased appreciably during 2008 was primarily attributable to lower commodity prices at December 31, 2008 over the prior year-end which shortens the economic life of many wells and thus, decreases reserve estimates. Reserve extensions and discoveries which increased significantly during 2009 were primarily attributable to our leasehold in the Williston Basin that we acquired from St. Mary in January 2008 and the robust activity of a number of operators in the Bakken/Three Forks oil shale play in which we have offsetting leasehold. Revisions of previous estimates which increased appreciably during 2009 were primarily due to the re-classification of proved undeveloped reserves to the probable and possible categories as a result of the reserves having been on our reserve report for more than five years. F-31 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The Company’s proved oil and gas reserves have been estimated by the Company with the assistance of an independent petroleum engineering firm (DeGolyer & MacNaughton) as of December 31, 2007, 2008 and 2009. The following information has been prepared in accordance with the Securities and Exchange Commission rules and accounting standards based on year end prices and costs for December 31, 2007 and 2008, and based on the 12-month un-weighted first-day-of-the-month average prices for December 31, 2009 and in accordance with provisions of the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows as of December 31, 2009, to be based on the average, first-day-of-the-month price beginning with the year ended December 31, 2009. The previous rules required reserve estimates be calculated using last day of the year pricing. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future net cash flows have not been adjusted for commodity derivative contracts outstanding at the end of each year. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis of the properties. Operating loss carryforwards, tax credits, and permanent differences to the extent estimated to be available in the future were also considered in the future income tax calculations, thereby reducing the expected tax expense. Because prices used in the calculation are average prices for 2009, the standardized measure could vary significantly from year to year based on the market conditions that occurred. The technical personnel responsible for preparing the reserve estimates at DeGolyer and MacNaughton meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. DeGolyer and MacNaughton is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis. DeGolyer and MacNaughton’s opinions indicate that the estimates of proved reserves prepared by us for the properties reviewed by DeGolyer and MacNaughton, when compared in total do not differ materially from the estimates prepared by DeGolyer and MacNaughton. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by Abraxas. The report of DeGolyer and MacNaughton dated February 26, 2010, which contains further discussions of the reserve estimates and evaluations prepared by DeGolyer and MacNaughton as well as the qualifications of DeGolyer and MacNaughton’s technical personnel responsible for overseeing such estimates and evaluations is attached as Exhibit 99.1 to this report. Estimates of proved reserves at December 31, 2009, 2008 and 2007 were based on studies performed by the operations department of Abraxas. The operations department is directly responsible for Abraxas’ reserve evaluation process. The Vice President of Operations is the manager of this department and is the primary technical person responsible for this process. The Vice President of Operations holds a Bachelor of Science degree in Petroleum Engineering, and has 25 years of experience in reserve evaluations. The operations department consists of four petroleum engineers with Bachelor degrees in Petroleum Engineering, one of whom is a Registered Professional Engineer in the State of Texas, and various other technical professionals. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted to represent the fair market value of the Company’s proved oil and gas reserves. An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. Set forth below is the Standardized Measure relating to our proved oil and gas reserves for the three years ended December 31, 2007, 2008 and 2009. For comparison purposes, our proved reserves under the previous rules would have been approximately, 26,893.6 MBoe compared to 24,919.8 MMBoe under the new rules and standards. F-32 Years Ended December 31, 2007 2008 2009 Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future development costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Future income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 830,193 (235,146) (111,221) — (In thousands) $ 811,644 (312,756) (134,073) — $ 816,436 (332,283) (138,354) — Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 483,826 (268,140) 364,815 (212,823) 345,799 (195,270) Standardized Measure of discounted future net cash relating to proved reserves . . . . . . $ 215,686 $ 151,992 $ 150,529 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following is an analysis of the changes in the Standardized Measure: Standardized Measure—beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales and transfers of oil and gas produced, net of production costs . . . . . . . . . . . . . . . . . . Net change in prices and development and production costs from prior year . . . . . . . . . . . Extensions, discoveries, and improved recovery, less related costs . . . . . . . . . . . . . . . . . . . Purchases of minerals in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sales of minerals in place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions of previous quantity estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in timing and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of discount Year Ended December 31, 2007 2008 2009 $156,844 (35,652) 44,791 29,834 — — 24,033 (19,847) 15,683 (In thousands) $215,686 (72,449) (69,094) 8,694 61,761 (366) (16,222) 2,414 21,568 $151,992 (25,605) (4,883) 22,267 — — (13,578) 5,137 15,199 Standardized Measure, end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $215,686 $151,992 $150,529 The standardized measure is based on the following oil and gas prices over the life of the properties as of the following dates: Year Ended December 31, 2007 2008 2009 Oil (per barrel)(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas (per MMBtu)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil (per barrel)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gas (per MMBtu)(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $95.98 7.48 87.30 6.33 $44.60 5.62 41.74 4.77 $61.18 4.19 55.05 3.42 (1) The quoted oil price is the NYMEX near month future price as of December 31 of the applicable year for the years ended December 31, 2007 and 2008. The quoted oil price for the year ended December 31, 2009 in the 12-month un-weighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2009. (2) The quoted gas price is the NYMEX near month price as of December 31 of the applicable year for 2007 and 2008. The quoted gas price for the year ended December 31, 2009 is the 12-month un-weighted average first-day-of-the-month Henry Hub spot price for each month of 2009. (3) The oil price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied. (4) The gas price is the realized price at the wellhead as of December 31 of each year after the appropriate differentials have been applied. F o r m 1 0 - K F-33 CORPORATE INFORMATION DIRECTORS Corporate Office 18803 Meisner Drive San Antonio, Texas 78258 Phone: 210.490.4788 Legal Counsel Jackson Walker L.L.P. San Antonio, Texas Cox Smith Matthews Incorporated San Antonio, Texas Independent Public Accountants BDO Seidman, LLP Dallas, Texas Independent Reservoir Engineers DeGolyer and MacNaughton Dallas, Texas Stock Exchange Listing The NASDAQ Stock Market Ticker Symbol: AXAS Transfer Agent American Stock Transfer & Trust Company 59 Maiden Lane New York, New York 10038 Phone: 800.937.5449 Annual Shareholders Meeting May 19, 2010 at 10:30 a.m. CT Petroleum Club San Antonio, Texas OFFICERS Robert L.G. Watson President / Chief Executive Officer Chris E. Williford Executive Vice President / Chief Financial Officer Lee T. Billingsley, Ph.D. Vice President—Exploration William H. Wallace Vice President—Operations Stephen T. Wendel Vice President—Land and Marketing Robert L.G. Watson Chairman of the Board / President / Chief Executive Officer, Abraxas Petroleum Corporation San Antonio, Texas C. Scott Bartlett, Jr.1 Executive Vice President (retired), Bank of America Richmond Hill, Georgia Franklin A. Burke1 President, Venture Securities Corporation; President / Chief Executive Officer, Burke, Lawton, Brewer & Burke Ambler, Pennsylvania Harold D. Carter2 Former President / Chief Operating Officer, Sabine Corporation Dallas, Texas Ralph F. Cox2,3 President, Rabar Enterprises Fort Worth, Texas Dennis E. Logue2,3 Chairman of the Board, Ledyard National Bank Hanover, New Hampshire Brian L. Melton1 Vice President—Corporate Strategy, Inergy, L.P. Kansas City, Missouri Paul A. Powell, Jr.1,3 Vice President / Director, Mechanical Development Co., Roanoke, Virginia Edward P. Russell President, Tortoise Capital Resources Corp. Leawood, Kansas 1 Audit Committee 2 Compensation Committee 3 Nominating & Governance Committee Barbara M. Stuckey Vice President—Corporate Finance Web Address www.abraxaspetroleum.com Abraxas Petroleum Corporation 18803 Meisner Drive San Antonio, Texas 78258 Phone: 210.490.4788 www.abraxaspetroleum.com