reportofdm.htm

Pursuant to your request, we have prepared estimates of the extent and value of the net proved, probable, and possible crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of December 31, 2011, of certain selected properties owned by Abraxas Petroleum Corporation (Abraxas). This evaluation was completed on February 21, 2011. Abraxas has represented that these properties account for 98 percent on a net equivalent barrel basis of Abraxas’ net proved reserves as of December 31, 2011. The properties appraised are located in the states of Louisiana, Montana, North Dakota, Oklahoma, South Dakota, Texas, Utah, Wyoming, and in the province of Alberta in Canada. The net proved, probable, and possible reserves estimates prepared by us have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. All values are shown in United States (U.S.) dollars.

Reserves included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2011. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Abraxas after deducting all interests owned by others.

Data used in this evaluation were obtained from reviews with Abraxas personnel, Abraxas files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Abraxas with respect to property interests, production from such properties, current costs of

operation and development, 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. A field examination of the properties was not considered necessary for the purposes of this report.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. Most of the undeveloped reserves were estimated by analogy to similar wells or offset wells.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Petroleum reserves estimated by us included in this report are classified as proved, probable, and possible. Reserves classifications used by us 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.

(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.

(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.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

The extent to which probable and possible reserves ultimately may be reclassified 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 and therefore are not comparable with proved reserves.

The development status shown herein represents the status applicable on December 31, 2011. In the preparation of this report, data available from wells drilled on the appraised properties through December 31, 2011, were used in estimating gross ultimate recovery. When applicable, gross production estimated to December 31, 2011, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of December 31, 2011. Production data through November 2011 were available for most properties.

Our estimates of Abraxas’s net proved, probable and possible reserves attributable to the reviewed U.S. properties are based on the definitions of reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Net Reserves as of December 31, 2011
	Oil and Condensate (Mbbl)		NGL (Mbbl)		Sales Gas (MMcf)

Proved
Developed Producing		5,912		1,009		36,110
Developed Nonproducing		309		28		2,237
Undeveloped		5,854		490		28,665

Total Proved		12,075		1,527		67,012

Possible
Developed Producing	0	0	0
Developed Nonproducing	0	0	0
Undeveloped	11,461	545	19,603

Total Possible	11,461	545	19,603

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

Our estimates of Abraxas’s net proved and probable reserves attributable to the reviewed Canadian properties are based on the definitions of reserves of the SEC and are as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Net Reserves as of December 31, 2011
	Oil and Condensate (Mbbl)		NGL (Mbbl)		Sales Gas (MMcf)

Proved
Developed Producing		77		5		365
Developed Nonproducing		223		23		1,766
Undeveloped		101		10		753

Total Proved		401		38		2,884

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 consistent with SEC guidelines in effect on December 31, 2011.

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 and condensate price differentials for each property were provided by Abraxas. Oil and condensate prices were calculated using these differentials to a West Texas Intermediate (WTI) price of $96.04 per barrel and held constant thereafter. The WTI price of $96.04 is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The weighted average price of the proved reserves over the lives of the properties was $88.59 per barrel.

NGL prices were calculated for each property using the differentials to a WTI price of $96.04 per barrel and were held constant for the lives of the properties. The weighted average price of the proved reserves over the lives of the properties was $50.21 per barrel.

Gas price differentials for each property were provided by Abraxas. Gas prices were calculated using these differentials to a Henry Hub price of $4.14 per million British thermal units (MMBtu) and held constant thereafter. The Henry Hub price of $4.14 is the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The weighted average price of the proved reserves over the lives of the properties was $3.73 per thousand cubic feet.

Operating expenses and capital costs were based on information provided by Abraxas and were used in estimating future expenditures required to operate the properties. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from price inflation has been applied. Capital costs were estimated using estimated 2012 values and were not adjusted for inflation.

The estimated future revenue and expenditures attributable to the production and sale of Abraxas’s net proved, probable and possible reserves of the U.S. properties appraised, as of December 31, 2011, is summarized in thousands of dollars (M$) as follows:

	Proved
	Developed Producing	Developed Nonproducing	Undeveloped	Total Proved

Future Gross Revenue, M$	714,193	37,965	644,330	1,396,488
Production and Ad Valorem Taxes, M$	67,916	3,222	66,706	137,844
Operating Expenses, M$	266,886	4,703	108,138	379,727
Capital Costs, M$	83	3,455	218,539	222,077
Abandonment Costs, M$	1,464	9	107	1,580
Future Net Revenue, M$	377,844	26,576	250,840	655,260
Present Worth at 10 Percent, M$	196,511	13,321	63,015	272,847

Note: Future income taxes have not been taken into account in the preparation of these estimates.

	Probable
	Developed Producing	Developed Nonproducing	Undeveloped	Total Probable

Future Gross Revenue, M$	0	10,372	971,334	981,706
Production and Ad Valorem Taxes, M$	0	894	105,951	106,845
Operating Expenses, M$	0	1,319	143,104	144,423
Capital Costs, M$	0	1,829	320,598	322,427
Abandonment Costs, M$	0	0	146	146
Future Net Revenue, M$	0	6,330	401,535	407,865
Present Worth at 10 Percent, M$	0	3,601	104,257	107,858

Notes: 1. Future income taxes have not been taken into account in the preparation of these estimates. 2. Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

	Possible
	Developed Producing	Developed Nonproducing	Undeveloped	Total Possible

Future Gross Revenue, M$	0	0	1,142,253	1,142,253
Production and Ad Valorem Taxes, M$	0	0	110,387	110,387
Operating Expenses, M$	0	0	219,303	219,303
Capital Costs, M$	0	0	478,113	478,113
Abandonment Costs, M$	0	0	0	0
Future Net Revenue, M$	0	0	334,450	334,450
Present Worth at 10 Percent, M$	0	0	64,489	64,489

Notes: 1. Future income taxes have not been taken into account in the preparation of these estimates. 2. Values for possible reserves have not been risk adjusted to make them comparable to values for proved reserves.

The estimated future revenue and expenditures attributable to the production and sale Abraxas’s net proved and probable reserves of the Canadian properties appraised, as of December 31, 2011, is summarized in thousands of dollars (M$) as follows:

	Proved
	Developed Producing	Developed Nonproducing	Undeveloped	Total Proved

Future Gross Revenue, M$	10,961	37,053	15,663	63,677
Production and Ad Valorem Taxes, M$	0	0	0	0
Operating Expenses, M$	2,622	6,987	2,955	12,564
Capital Costs, M$	0	1,050	3,500	4,550
Abandonment Costs, M$	150	150	50	350
Future Net Revenue, M$	6,117	21,434	6,324	33,875
Present Worth at 10 Percent, M$	4,175	14,831	2,817	21,823

Note: Future income taxes have not been taken into account in the preparation of these estimates.

	Probable
	Developed Producing	Developed Nonproducing	Undeveloped	Total Probable

Future Gross Revenue, M$	18,874	0	34,814	53,688
Production and Ad Valorem Taxes, M$	0	0	0	0
Operating Expenses, M$	4,198	0	6,172	10,370
Capital Costs, M$	2,000	0	10,500	12,500
Abandonment Costs, M$	0	0	150	150
Future Net Revenue, M$	10,700	0	12,032	22,732
Present Worth at 10 Percent, M$	7,155	0	5,784	12,939

Notes: 1. Future income taxes have not been taken into account in the preparation of these estimates. 2. Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

Estimates of oil, condensate, and natural 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.

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 gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2011, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved, probable, and possible reserves, and present worth of estimated future net revenue from proved, probable, and possible reserves of oil, condensate, natural gas liquids, 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, (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Abraxas. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of Abraxas. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

1.	That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Abraxas dated February 21, 2012, and that I, as Senior Vice President, was responsible for the preparation of this report.

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 37 years of experience in oil and gas reservoir studies and reserves evaluations.

Probable
Developed Producing	0	0	0
Developed Nonproducing	66	0	1,169
Undeveloped	7,375	1,941	54,192

Total Probable	7,441	1,941	55,361

Possible	0	0	0

Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.