17. 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:

	Years Ended December 31
	2010									2011
	Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Proved oil and gas properties	$	434,858		$	427,337		$	7,521		$	490,908		$	468,218		$	22,690
Unproved properties		1,085			-			1,085			1,100			-			1,100
Total		435,943			427,337			8,606			492,008			468,218			23,790
Accumulated depreciation, depletion, amortization and impairment		(325,793	)		(320,957	)		(4,836	)		(341,264	)		(335,871	)		(5,393	)
Net capitalized costs	$	110,150		$	106,380		$	3,770		$	150,744		$	132,347		$	18,397

Cost incurred in oil and gas property acquisition and development activities are as follows:

	Years Ended December 31
	2009						2010						2011
	Total		U.S.		Canada		Total		U.S.		Canada		Total		U.S.		Canada
	(In thousands)
Development costs	$	15,356	$	15,356	$	-	$	31,278	$	23,757	$	7,521	$	46,735	$	32,471	$	14,264
Exploration costs		795		795		-		3,809		3,809		-		8,410		8,410		-
Property acquisition costs:
Unproved		-		-		-		1,085		-		1,085		1,100		-		1,100
	$	16,151	$	16,151	$	-	$	36,172	$	27,566	$	8,606	$	56,245	$	40,881	$	15,364

The results of operations for oil and gas producing activities for the three years ended December 31, 2009, 2010 and 2011 are as follows:

	Years Ended December 31,
	2009								2010									2011
	Total			U.S.			Canada		Total			U.S.			Canada				Total			U.S.			Canada
	(In thousands)
Revenues	$	51,829		$	51,829		$	-	$	58,050		$	57,990		$	60			$	64,615		$	63,105		$	1,510
Production costs		(26,224	)		(26,224	)		-		(25,790	)		(25,774	)		(16	)			(27,347	)		(26,552	)		(795	)
Depreciation, depletion, and amortization		(17,361	)		(17,361	)		-		(15,653	)		(15,603	)		(50	)			(15,595	)		(14,914	)		(681	)
Proved property impairment		-			-			-		(4,787	)		-			(4,787	)			-			-			-
General and administrative		(1,617	)		(1,617	)		-		(2,323	)		(1,635	)		(688	)			(2,352	)		(1,698	)		(654	)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	6,627		$	6,627		$	-	$	9,497		$	14,978		$	(5,481	)		$	19,321		$	19,941		$	(620	)
Depletion rate per barrel of oil equivalent	$	10.63		$	10.63		$	-	$	11.00		$	10.98		$	59.97			$	12.26		$	11.96		$	27.58

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, 2009, 2010, and 2011. 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 and Canada.

Proved reserves were estimated in accordance with guidelines established by the SEC 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-first-day-of-the-month commodity prices and year-end costs were used in estimating reserve volumes and future net cash flows for the periods presented.

	Total						United States						Canada
	Oil/NGL		Gas		Oil Equivalents		Oil/NGL		Gas		Oil Equivalents		Oil/NGL		Gas		Oil Equivalents
	(MBbl)		(MMcf)		(MBoe)		(MBbl)		(MMcf)		(MBoe)		(MBbl)		(MMcf)		(MBoe)
	(In thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 2008	7,045		108,416		25,114		7,045		108,416		25,114		-		-		-
Revisions of previous estimates	193		(14,652	)	(2,249	)	193		(14,652	)	(2,249	)	-		-		-
Extensions and discoveries	2,173		9,090		3,688		2,173		9,090		3,688		-		-		-
Production	(579	)	(6,329	)	(1,634	)	(579	)	(6,329	)	(1,634	)	-		-		-
Balance at December 31, 2009	8,832		96,525		24,919		8,832		96,525		24,919		-		-		-
Revisions of previous estimates	1,067		729		1,189		1,067		729		1,189		-		-		-
Extensions and discoveries	1,329		1,456		1,572		1,252		1,066		1,430		77		390		142
Sales of minerals in place	(925	)	(8,318	)	(2,311	)	(925	)	(8,318	)	(2,311	)	-		-		-
Production	(509	)	(5,479	)	(1,422	)	(508	)	(5,479	)	(1,421	)	(1	)	-		(1	)
Balance at December 31, 2010	9,794		84,913		23,947		9,718		84,523		23,806		76		390		141
Revisions of previous estimates	2,290		(13,009	)	122		2,290		(13,009	)	122		-		-		-
Extensions and discoveries	2,703		4,393		3,435		2,326		1,837		2,632		377		2,556		803
Production	(568	)	(4,222	)	(1,272	)	(554	)	(4,160	)	(1,247	)	(14	)	(62	)	(25	)
Balance at December 31, 2011	14,219		72,075		26,232		13,780		69,191		25,313		439		2,884		919

	Total			United States			Canada
	Oil/NGL	Gas	Oil Equivalents	Oil/NGL	Gas	Oil Equivalents	Oil/NGL	Gas	Oil Equivalents
	(MBbl)	(MMcf)	(MBoe)	(MBbl)	(MMcf)	(MBoe)	(MBbl)	(MMcf)	(MBoe)
	(In thousands)
Proved Developed Reserves:
December 31, 2009	5,891	47,861	13,868	5,891	47,861	13,868	-	-	-

December 31, 2010	5,862	42,750	12,987	5,786	42,360	12,846	76	390	141

December 31, 2011	7,761	42,582	14,858	7,433	40,451	14,175	328	2,131	683

Proved Undeveloped Reserves:
December 31, 2009	2,941	48,665	11,052	2,941	48,665	11,052	-	-	-

December 31, 2010	3,932	42,163	10,959	3,932	42,163	10,959	-	-	-

December 31, 2011	6,460	29,493	11,376	6,348	28,740	11,138	112	753	238

Reserve extensions and discoveries which increased significantly during 2009 and 2011 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 play in which we have offsetting leasehold together with our own activity in the basin. Revisions of previous estimates which decreased appreciably during 2009 and 2011 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.

Sales of minerals in place increased significantly during 2010, which were attributable to the sale of certain properties, principally non-operated, non-core assets, to generate cash for debt repayment and to accelerate our drilling program.

The following table contains information relating to proved reserves attributable to Abraxas' equity interest in Blue Eagle as of December 31, 2010 and 2011. All of Blue Eagle's reserves are in the United States.

	Total
	Oil/NGL			Gas			Oil Equivalents
	(MBbl)			(MMcf)			(MBoe)
	(in thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 2009		-			-			-
Extensions and discoveries		1,239			8,301			2,623
Balance at December 31, 2010		1,239			8,301			2,623
Decrease in equity interest		(373	)		(2,501	)		(772	)
Revisions of previous estimates		9			854			151
Extensions and discoveries		473			2,688			921
Production		(55	)		(353	)		(132	)
Balance at December 31, 2011		1,293			8,989			2,791

Proved Developed Reserves:
December 31, 2010		-			-			-

December 31, 2011		202			1,339			425

Proved Undeveloped Reserves:
December 31, 2010		1,239			8,301			2,623

December 31, 2011		1,091			7,648			2,366

At formation and through June 29, 2011, we owned a non-controlling 50.0% interest in the joint venture. On June 29, 2011, Rock Oil contributed $11.0 million to Blue Eagle which reduced our equity interest to 41.0%. On October 19, 2011 and December 9, 2011, Rock Oil contributed an additional $3.0 million and $8.0 million, respectively, to Blue Eagle which reduced our equity interest to 34.7%. As of December 31, 2011, we owned a non-controlling 34.7% interest in the joint venture.

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, 2009, 2010 and 2011. The following information has been prepared in accordance with SEC rules and accounting standards based on the 12-month first-day-of-the-month average prices 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 to be based on the twelve month average, first-day-of-the-month price beginning with the year ended December 31, 2009. 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. Since prices used in the calculation are average prices for 2011, the standardized measure could vary significantly from year to year based on the market conditions that occurred during a given year.

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. All reports by DeGolyer and MacNaughton were developed utilizing studies performed by the operations department of Abraxas and estimated by independent petroleum engineers. The report of DeGolyer and MacNaughton dated February 21, 2012, 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, 2010 and 2011 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 26 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. The table below sets forth the Standardized Measure of our proved oil and gas reserves for the three years ended December 31, 2009, 2010 and 2011:

	Years Ended December 31,
	2009								2010									2011
	Total			U.S.			Canada		Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Future cash inflows	$	816,436		$	816,436		$	-	$	1,020,286		$	1,012,829		$	7,457		$	1,471,352		$	1,420,013		$	51,339
Future production costs		(332,283	)		(332,283	)		-		(391,396	)		(389,395	)		(2,001	)		(544,970	)		(532,056	)		(12,914	)
Future development costs		(138,354	)		(138,354	)		-		(164,135	)		(163,085	)		(1,050	)		(228,804	)		(224,254	)		(4,550	)
Future income tax expense		-			-			-		-			-			-			(106,839	)		(104,279	)		(2,560	)
Future net cash flows		345,799			345,799			-		464,755			460,349			4,406			590,739			559,4248			31,315
Discount		(195,270	)		(195,270	)		-		(267,762	)		(266,041	)		(1,721	)		(321,657	)		(310,516	)		(11,141	)
Standardized Measure of discounted future net cash relating to proved reserves	$	150,529		$	150,529		$	-	$	196,993		$	194,308		$	2,685		$	269,082		$	248,908		$	20,174

Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure. The table below sets forth the Standardized Measure of our proved oil and gas reserves attributable to Abraxas' equity interest in Blue Eagle for the two years ended December 31, 2010 and 2011:

	Years Ended December 31,
	2010			2011
	(In thousands)
Future cash inflows	$	95,378		$	120,913
Future production costs		(13,750	)		(19,630	)
Future development costs		(26,706	)		(29,472	)
Future income tax expense		(15,862	)		(17,996	)
Future net cash flows		39,060			53,815
Discount		(23,114	)		(32,524	)
Standardized Measure of discounted future net cash relating to proved reserves	$	15,946		$	21,291

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:

	Year Ended December 31,
	2009			2010			2011
	(In thousands)
Standardized Measure, beginning of year	$	151,992		$	150,529		$	196,993
Sales and transfers of oil and gas produced, net of production costs		(25,605	)		(32,261	)		(37,171	)
Net change in prices and development and production costs from prior year		(4,883	)		70,311			92,886
Extensions, discoveries, and improved recovery, less related costs		22,267			14,508			47,765
Sales of minerals in place		-			(18,868	)		-
Revisions of previous quantity estimates		(13,578	)		9,694			1,329
Change in timing and other		5,137			(11,973	)		(23,501	)
Change in future income tax expense		-			-			(28,918	)
Accretion of discount		15,199			15,053			19,699
Standardized Measure, end of year	$	150,529		$	196,993		$	269,082

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,
	2009		2010		2011
Oil (per Bbl) (1)	$	61.18	$	79.43	$	96.19
Gas (per MMbtu) (2)		4.19		4.45		4.16
Oil (per Bbl) (3)		55.05		70.72		88.58
Gas (per MMBtu) (4)		3.42		3.91		3.73
NGL's (per Bbl) (5)		-		55.60		50.21

_____________________

(1)

The quoted oil price for the year ended December 31, 2009, 2010 and 2011 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2009, 2010 and 2011.

(2)

The quoted gas price for the year ended December 31, 2009, 2010 and 2011 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 200920, 2010 and 2011.

(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.

(5)

The NGL price is the realized price as of December 31 of each year after the appropriate differentials have been applied.

The following is an analysis of the changes in the Standardized Measure as it relates to Abraxas' equity interest in Blue Eagle as of December 31, 2010 and 2011. All of Blue Eagle's reserves are in the United States.

	2010			2011
	(In thousands)
Standardized Measure, beginning of year	$	-		$	15,946
Sales and transfers of oil and gas produced, net of production costs		-			(4,387	)
Net change in prices and development and production costs from prior year		-			6,667
Extensions, discoveries, and improved recovery, less related costs		22,421			6,701
Revisions of previous quantity estimates		-			1,332
Change in equity interest		-			(6,491	)
Change in future income tax expense		(6,475	)		(646	)
Change in timing and other		-			613
Accretion of discount		-			1,556
Standardized Measure, end of year	$	15,946		$	21,291