15. 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
	2012									2013
	Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Proved oil and gas properties	$	563,317		$	531,971		$	31,346		$	564,755		$	530,996		$	33,759
Unproved properties	2,089			—			2,089			—			—			—
Total	565,406			531,971			33,435			564,755			530,996			33,759
Accumulated depreciation, depletion, amortization and impairment	(383,469		)	(356,255		)	(27,214		)	(413,704		)	(381,283		)	(32,421		)
Net capitalized costs	$	181,937		$	175,716		$	6,221		$	151,051		$	149,713		$	1,338

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



	Years Ended December 31
	2011						2012						2013
	Total		U.S.		Canada		Total		U.S.		Canada		Total		U.S.		Canada
	(In thousands)
Development costs	$	46,735	$	32,471	$	14,264	$	56,318	$	48,283	$	8,035	$	93,878	$	91,325	$	2,553
Exploration costs	8,410		8,410		—		—		—		—		—		—		—
Property acquisition costs	—		—		—		7,200		7,200		—		—		—		—
Unproved	1,100		—		1,100		989		—		989		—		—		—
	$	56,245	$	40,881	$	15,364	$	64,507	$	55,483	$	9,024	$	93,878	$	91,325	$	2,553

The results of operations for oil and gas producing activities for the three years ended December 31, 2011, 2012 and 2013 are as follows:



	Years Ended December 31,
	2011									2012									2013
	Total			U.S.			Canada			Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Revenues	$	64,615		$	63,105		$	1,510		$	68,499		$	65,590		$	2,909		$	94,275		$	92,268		$	2,007
Production costs	(27,347		)	(26,552		)	(795		)	(31,419		)	(29,166		)	(2,253		)	(33,871		)	(31,642		)	(2,229		)
Depreciation, depletion, and amortization	(15,595		)	(14,914		)	(681		)	(22,767		)	(20,704		)	(2,063		)	(26,072		)	(25,028		)	(1,044		)
Proved property impairment	—			—			—			(19,774		)	—			(19,774		)	(6,025		)	—			(6,025		)
General and administrative	(2,352		)	(1,698		)	(654		)	(2,679		)	(1,980		)	(699		)	(3,350		)	(2,471		)	(879		)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	19,321		$	19,941		$	(620	)	$	(8,140	)	$	13,740		$	(21,880	)	$	24,957		$	33,127		$	(8,170	)
Depletion rate per barrel of oil equivalent	$	12.26		$	11.96		$	27.58		$	15.59		$	14.74		$	37.48		$	16.59		$	16.32		$	27.37

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, 2011, 2012, and 2013. 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, 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
Sales of minerals in place	—		—		—		—		—		—		—		—		—
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
Revisions of previous estimates	1,574		(7,470	)	328		1,774		(5,786	)	809		(200	)	(1,684	)	(481	)
Extensions and discoveries	5,809		6,983		6,973		5,809		6,983		6,973		—		—		—
Purchases of minerals in place	1		69		13		1		69		13		—		—		—
Sales of minerals in place	(850	)	(6,376	)	(1,913	)	(850	)	(6,376	)	(1,913	)	—		—		—
Production	(797	)	(4,097	)	(1,481	)	(763	)	(3,982	)	(1,427	)	(34	)	(115	)	(54	)
Balance at December 31, 2012	19,956		61,184		30,152		19,751		60,099		29,768		205		1,085		384
Revisions of previous estimates	999		(5,123	)	145		1,073		(4,804	)	270		(74	)	(319	)	(125	)
Extensions and discoveries	10,746		3,610		11,348		10,746		3,610		11,348		—		—		—
Purchases of minerals in place	—		—		—		—		—		—		—		—		—
Sales of minerals in place	(7,748	)	(8,141	)	(9,105	)	(7,748	)	(8,141	)	(9,105	)	—		—		—
Production	(1,000	)	(3,421	)	(1,570	)	(976	)	(3,343	)	(1,533	)	(24	)	(78	)	(37	)
Balance at December 31, 2013	22,953		48,109		30,970		22,846		47,421		30,748		107		688		222



	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, 2011	7,761	42,582	14,858	7,433	40,451	14,175	328	2,131	683
December 31, 2012	8,650	41,220	15,520	8,531	40,723	15,318	119	497	202
December 31, 2013	8,310	31,572	13,572	8,284	31,424	13,521	26	148	51
Proved Undeveloped Reserves:
December 31, 2011	6,460	29,493	11,376	6,348	28,740	11,138	112	753	238
December 31, 2012	11,306	19,964	14,634	11,220	19,376	14,450	86	588	184
December 31, 2013	14,640	16,537	17,397	14,560	15,996	17,226	80	541	171

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, 2011, 2012 and 2013. 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 FASB’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” 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 and net operating losses associated with the properties. Since prices used in the calculation are average prices for 2013, 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 DeGolyer and MacNaughton and assisted by the Engineering and Operations departments of Abraxas. Reserves are estimated by independent petroleum engineers. The report of DeGolyer and MacNaughton dated February 13, 2014, 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, 2011, 2012 and 2013 were based on studies performed by our independent petroleum engineers assisted by the Engineering and Operations departments of Abraxas. The Engineering department is directly responsible for Abraxas’ reserve evaluation process. The Vice President of Engineering is the manager of this department and is the primary technical person responsible for this process. The Vice President of Engineering holds a Bachelor of Science degree in Petroleum Engineering and has 35 years of experience in reserve evaluations. The Vice President of Engineering is a Registered Professional Engineer in the State of Texas. The operations department of Abraxas assisted in the process, and consists of four petroleum engineers with Bachelor degrees in Petroleum Engineering, 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, 2011, 2012 and 2013:



	Years Ended December 31,
	2011									2012									2013
	Total			U.S.			Canada			Total			U.S.			Canada			Total			U.S.			Canada
	(In thousands)
Future cash inflows	$	1,471,352		$	1,420,013		$	51,339		$	1,784,920		$	1,766,515		$	18,405		$	2,244,846		$	2,234,632		$	10,214
Future production costs	(544,970		)	(532,056		)	(12,914		)	(642,706		)	(634,903		)	(7,803		)	(754,722		)	(751,058		)	(3,664		)
Future development costs	(228,804		)	(224,254		)	(4,550		)	(328,554		)	(324,704		)	(3,850		)	(467,206		)	(463,456		)	(3,750		)
Future income tax expense	(106,839		)	(104,279		)	(2,560		)	(149,625		)	(149,625		)	—			(244,394		)	(244,394		)	—
Future net cash flows	590,739			559,424			31,315			664,035			657,283			6,752			778,524			775,724			2,800
Discount	(321,657		)	(310,516		)	(11,141		)	(385,890		)	(383,271		)	(2,619		)	(437,539		)	(436,077		)	(1,462		)
Standardized Measure of discounted future net cash relating to proved reserves	$	269,082		$	248,908		$	20,174		$	278,145		$	274,012		$	4,133		$	340,985		$	339,647		$	1,338

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,
	2011			2012			2013
	(In thousands)
Standardized Measure, beginning of year	$	196,993		$	269,082		$	278,145
Sales and transfers of oil and gas produced, net of production costs	(37,171		)	(37,080		)	(60,403		)
Net change in prices and development and production costs from prior year	92,886			60,710			169,969
Extensions, discoveries, and improved recovery, less related costs	47,765			73,236			156,456
Sales of minerals in place	—			(20,089		)	(125,533		)
Purchased of minerals in place	—			131			—
Revisions of previous quantity estimates	1,329			3,355			2,930
Change in timing and other	(23,501		)	(88,309		)	(62,861		)
Change in future income tax expense	(28,918		)	(9,799		)	(45,532		)
Accretion of discount	19,699			26,908			27,814
Standardized Measure, end of year	$	269,082		$	278,145		$	340,985

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,
	2011		2012		2013
Oil (per Bbl) (1)	$	96.19	$	95.14	$	97.33
Gas (per MMbtu) (2)	$	4.16	$	2.86	$	3.67
Oil (per Bbl) (3)	$	88.58	$	88.26	$	95.90
Gas (per MMBtu) (4)	$	3.73	$	2.61	$	3.65
NGL’s (per Bbl) (5)	$	50.21	$	36.76	$	31.98

_____________________


(1)	The quoted oil price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2011, 2012 and 2013.


(2)	The quoted gas price for the year ended December 31, 2011, 2012 and 2013 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2011, 2012 and 2013.


(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.