DeGolyer and MacNaughton
  5001 Spring Valley Road
 Suite 800 East
 Dallas, Texas 75244


LETTER REPORT


as of


DECEMBER 31, 2009


on


CERTAIN PROPERTIES


owned by


ABRAXAS PETROLEUM CORPORATION


DeGolyer and MacNaughton
  5001 Spring Valley Road
 Suite 800 East
 Dallas, Texas 75244


February 19, 2010




Abraxas Petroleum Corporation


18803 Meisner Drive


San Antonio, Texas 78258




Ladies and Gentlemen:




Pursuant to your request, we have prepared estimates of the extent and value of the proved, probable, and possible crude oil, condensate, and natural gas reserves, as of December 31, 2009, of certain properties owned by Abraxas Petroleum Corporation (Abraxas). The properties appraised consist of working and royalty interests located in the states of Alabama, Arkansas, Colorado, Louisiana, Mississippi, Montana, North Dakota, Oklahoma, South Dakota, Texas, Utah, and Wyoming. The properties appraised represent 95 percent of Abraxas’ total proved reserves and 100 percent of the probable and possible reserves.





Information used in the preparation of this report was obtained from Abraxas, from records on file with the appropriate regulatory agencies, and from public sources. During this investigation, we consulted freely with officers and employees of Abraxas and were given access to such accounts, records, geological and engineering reports, and other data as were desired for examination. In the preparation of this report we have relied, without independent verification, upon information furnished by Abraxas with respect to property interests owned by Abraxas, production from such properties, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was not considered necessary to make a field examination of the physical condition and operation of the properties in which Abraxas owns interests.





Our reserves estimates are based on a detailed study of the properties and were prepared  in  accordance  with  standard  geological  and  engineering  methods


DeGolyer and MacNaughton


generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, consideration of the stage of development, and the quality and completeness of basic data.





Reserves estimated in this report are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2009. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Abraxas after deducting royalties and other interests held by others. Gas volumes shown herein are wet gas and sales gas volumes and are expressed at a temperature base of 60 degrees Fahrenheit and at the legal pressure base of the state in which the reserves are located. Wet gas is defined as the total gas to be produced before reductions for volume loss due to fuel consumption and flare and shrinkage due to liquids removal. Sales gas is defined as that portion of the wet gas to be delivered into a gas pipeline after separation, processing, fuel use, and flare. Gross gas reserves are reported as wet gas. The net gas reserves are reported as sales gas. Condensate reserves estimated herein are those to be recovered by conventional field separation.





Petroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:





Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.





(i) The area of the reservoir considered as proved includes:


(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.





(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.





(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.





(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:


(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.





(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.





The probable and possible reserves presented in this report have been prepared in accordance with the PRMS approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Probable and possible reserves are based on geoscience and/or engineering data similar to that used in estimates of proved reserves, but technical or other uncertainties preclude such reserves being classified as proved.





Probable Reserves – 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. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.





Possible Reserves – Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.


The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks to make them comparable to proved reserves.





The development status shown herein represents the status applicable on December 31, 2009. In the preparation of this study, data available from wells drilled on the appraised properties through December 31, 2009, were used in estimating gross ultimate recovery. When applicable, gross production estimated to December 31, 2009, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of December 31, 2009. Production data through November 2009 were available for most properties.





Estimated net proved reserves, as of December 31, 2009, from the properties appraised are summarized in thousands of barrels (Mbbl) or millions of cubic feet (MMcf) as follows:





Net ReservesProved

Probable*

Possible*Oil and

Condensate

(Mbbl)

Sales Gas

(MMcf)

Oil and

Condensate

(Mbbl)

Sales

Gas

(MMcf)

Oil and

Condensate

(Mbbl)

Sales

Gas

(MMcf)Developed Producing

5,063

38,427

0

0

0

0Developed Nonproducing

436

2,487

66

1,172

0

0Total Developed

5,499

40,914

66

1,172

0

0Undeveloped

2,938

45,718

2,020

30,569

2,010

18,546Total

8,437

86,632

2,086

31,741

2,010

18,546* Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.





Revenue values in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth of future net revenue. These values are based on the continuation of prices in effect on December 31, 2009.





Future gross revenue is defined as that revenue to be realized from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating, gathering, processing expenses, and capital costs from the future gross revenue. Present worth of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded monthly over the expected period of realization.





Revenue values in this report were estimated using the initial prices and expenses provided by Abraxas. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The prices used in this report are based on SEC guidelines. The assumptions used for estimating future prices and expenses are as follows:





Oil, Condensate, and Natural Gas Prices





Oil, condensate, and natural gas price differentials for each property were provided by Abraxas. The prices were calculated using these differentials to a NYMEX WTI price of $61.18 per barrel or a NYMEX gas price of $4.19 per MMBtu. The weighted average prices over the lives of the properties were $55.15 per barrel of oil and $3.42 per thousand cubic feet of gas.





Expenses





Operating expenses and capital costs were based on information provided by Abraxas and were used in estimating future expenditures required to operate the properties. The development schedule provided by Abraxas was used to schedule future production. No escalation has been applied to the expenditures.





The estimated future revenue and expenditures attributable to the production and sale of Abraxas’s net proved reserves of the properties appraised, as of December 31, 2009, is summarized in thousands of dollars (M$) as follows:

















ProvedDeveloped

Producing

Developed

Nonproducing

Undeveloped

TotalFuture Gross Revenue, M$

403,137

33,009

325,176

761,322Production Taxes, M$

28,737

1,758

24,108

54,603Ad Valorem Taxes, M$

9,235

918

5,048

15,201Operating Expenses, M$

173,799

6,071

53,546

233,416Capital Costs, M$

85

4,102

124,837

129,024Salvage and Abandonment Costs, M$

2,028

35

115

2,178Future Net Revenue, M$*

189,253

20,125

117,522

326,900Present Worth at 10 Percent, M$*

106,787

11,357

24,230

142,374* Future income tax expenses were not taken into account in the preparation of these estimates.





The estimated future revenue and expenditures attributable to the production and sale of Abraxas’ net probable reserves of the properties appraised, as of December 31, 2009, is summarized in thousands of dollars (M$) as follows:





Probable*Developed

Nonproducing

Undeveloped

TotalFuture Gross Revenue, M$

7,660

231,243

238,903Production Taxes, M$

406

17,300

17,706Ad Valorem Taxes, M$

218

4,586

4,804Operating Expenses, M$

1,281

37,469

38,750Capital Costs, M$

1,829

64,828

66,657Salvage and Abandonment Costs, M$

0

119

119Future Net Revenue, M$**

3,927

106,941

110,868Present Worth at 10 Percent, M$**

2,584

31,719

34,303** Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

** Future income tax expenses were not taken into account in the preparation of these estimates.





DeGolyer and MacNaughton


The estimated future revenue and expenditures attributable to the production and sale of Abraxas’ net possible reserves of the properties appraised as of December 31, 2009 is summarized in thousands of dollars (M$) as follows:





PossibleUndeveloped

TotalFuture Gross Revenue, M$

183,834

183,834Production Taxes, M$

13,997

13,997Ad Valorem Taxes, M$

3,590

3,590Operating Expenses, M$

25,791

25,791Capital Costs, M$

55,217

55,217Salvage and Abandonment Costs, M$

23

23Future Net Revenue, M$*

85,216

85,216Present Worth at 10 Percent, M$*

26,911

26,911** Values for possible reserves have not been risk adjusted to make them comparable to values for proved reserves.

** Future income tax expenses were not taken into account in the preparation of these estimates.





Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.





In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein.





While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover  its  oil  and


DeGolyer and MacNaughton


gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2009, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.





DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. DeGolyer and MacNaughton does not have any interest, including stock ownership, in Abraxas. DeGolyer and MacNaughton has used all procedures, data, and methods that it considers necessary to prepare this report.




Submitted,







DeGOLYER and MacNAUGHTON


Texas Registered Engineering Firm F-716




Paul J. Szatkowski, P.E.
 Senior Vice President
 DeGolyer and MacNaughton
 
 DeGolyer and MacNaughton


CERTIFICATE of QUALIFICATION





I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:





1.
That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Abraxas dated February 19, 2010, and that I, as Senior Vice President, was responsible for the preparation of this report.





2.
That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 35 years of experience in the oil and gas reservoir studies and reserves evaluations.







/s/Paul J. Szatkowski, P.E.
 Paul J. Szatkowski, P.E.
 Senior Vice President
 DeGolyer and MacNaughton