15. Supplemental Oil and Gas Disclosures (Unaudited)

Information in the following tables is inclusive of Canadian operations that are presented in the basic financial statements as discontinued operations.

The accompanying table presents information concerning the Company’s oil and gas producing activities inclusive of discontinued operations, 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
	2013			2014
	(In thousands)
Proved oil and gas properties	$	564,755		$	716,922
Unproved properties	—			—
Total	564,755			716,922
Accumulated depreciation, depletion, amortization and impairment	(413,704		)	(423,819		)
Net capitalized costs	$	151,051		$	293,103

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



	Years Ended December 31
	2012		2013		2014
	(In thousands)
Development costs	$	56,318	$	93,878	$	189,332
Exploration costs	—		—		—
Property acquisition costs	7,200		—		—
Unproved	989		—		—
	$	64,507	$	93,878	$	189,332

The results of operations for oil and gas producing activities, inclusive of discontinued operations, for the three years ended December 31, 2012, 2013 and 2014 are as follows:




	Years Ended December 31,
	2012			2013			2014
	(In thousands)
Revenues	$	68,499		$	94,275		$	134,883
Production costs	(31,419		)	(33,871		)	(38,146		)
Depreciation, depletion, and amortization	(22,767		)	(26,072		)	(42,945		)
Proved property impairment	(19,774		)	(6,025		)	—
General and administrative	(2,679		)	(3,350		)	(2,796		)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	(8,140	)	$	24,957		$	50,996
Depletion rate per barrel of oil equivalent	$	15.59		$	16.59		$	20.39

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, 2012, 2013, and 2014. 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.

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.

For the period ending December 31, 2014, proved producing reserves were increased by approximately 4.4 MMBoe, net, due primarily to the completion of 20 new wells during 2014. Ten of these new wells were located on the Company’s North Fork prospect acreage in McKenzie County, North Dakota, and ten were located on various acreage tracts in the Eagle Ford play of Atascosa and McMullen Counties, Texas. The Company also added 28 new Bakken proved undeveloped down-spaced locations on the Company’s North Fork and Pershing prospect acreage in McKenzie County, North Dakota. These locations were added based on the Company’s successful test of down-spacing from 1320 feet between wells in the same zone to 660 feet. Reserves attributable to these new down-spaced locations amounted to approximately 7.7 MMBoe, net. The Company also gained approximately 1.1 MMBoe of net proved undeveloped reserves in the Bakken due to upward revisions in its Bakken type curve, which curve is used to forecast results on undeveloped locations. These upward revisions were attributable to better-than-anticipated results in the Company’s existing Bakken producing wells. The Company also gained proved undeveloped reserves of approximately 2.3 MMBbls of oil, net, due to the change in classification of ten probable undeveloped Bakken cases into the proved category. These locations achieved proved status by virtue of offsetting development activity during 2014. An equivalent volume of reserves was removed from the probable undeveloped category as a result of this change in classification.



	Oil/NGL		Gas		Oil Equivalents
	(MBbl)		(MMcf)		(MBoe)
	(In thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 2011	14,219		72,075		26,232
Revisions of previous estimates	1,574		(7,470	)	328
Extensions and discoveries	5,809		6,983		6,973
Purchase of minerals in place	1		69		13
Sales of minerals in place	(850	)	(6,376	)	(1,913	)
Production	(797	)	(4,097	)	(1,481	)
Balance at December 31, 2012	19,956		61,184		30,152
Revisions of previous estimates	999		(5,123	)	145
Extensions and discoveries	10,746		3,610		11,348
Sales of minerals in place	(7,748	)	(8,141	)	(9,105	)
Production	(1,000	)	(3,421	)	(1,570	)
Balance at December 31, 2013	22,953		48,109		30,970
Revisions of previous estimates	3,718		7,383		4,950
Extensions and discoveries	8,648		6,893		9,797
Sales of minerals in place	(620	)	(3,614	)	(1,223	)
Production	(1,601	)	(2,918	)	(2,088	)
Balance at December 31, 2014	33,098		55,853		42,406



	Total
	Oil/NGL	Gas	Oil Equivalents
	(MBbl)	(MMcf)	(MBoe)
	(In thousands)
Proved Developed Reserves:
December 31, 2012	8,650	41,220	15,520
December 31, 2013	8,310	31,572	13,572
December 31, 2014	12,168	34,677	17,948



Proved Undeveloped Reserves:
December 31, 2012	11,306	19,964	14,634
December 31, 2013	14,640	16,537	17,397
December 31, 2014	20,930	21,176	24,459

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, 2012, 2013 and 2014. 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 2014, 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 11, 2015, 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, 2012, 2013 and 2014 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 36 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.

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, 2012, 2013 and 2014:




Years Ended December 31,
2012	2013	2014



	(In thousands)
Future cash inflows	$	1,784,920		$	2,244,846		$	2,988,464
Future production costs	(642,706		)	(754,722		)	(921,977		)
Future development costs	(328,554		)	(467,206		)	(557,782		)
Future income tax expense	(149,625		)	(244,394		)	(373,095		)
Future net cash flows	664,035			778,524			1,135,610
Discount	(385,890		)	(437,539		)	(623,053		)
Standardized Measure of discounted future net cash relating to proved reserves	$	278,145		$	340,985		$	512,557

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,
	2012			2013			2014
	(In thousands)
Standardized Measure, beginning of year	$	269,082		$	278,145		$	340,985
Sales and transfers of oil and gas produced, net of production costs	(37,080		)	(60,403		)	(96,364		)
Net change in prices and development and production costs from prior year	60,710			169,969			150,504
Extensions, discoveries, and improved recovery, less related costs	73,236			156,456			147,275
Sales of minerals in place	(20,089		)	(125,533		)	(15,042		)
Purchased of minerals in place	131			—			—
Revisions of previous quantity estimates	3,355			2,930			74,390
Change in timing and other	(88,309		)	(62,861		)	(82,653		)
Change in future income tax expense	(9,799		)	(45,532		)	(40,636		)
Accretion of discount	26,908			27,814			34,098
Standardized Measure, end of year	$	278,145		$	340,985		$	512,557

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,
	2012		2013		2014
Oil (per Bbl) (1)	$	95.14	$	97.33	$	95.28
Gas (per MMbtu) (2)	$	2.86	$	3.67	$	4.35
Oil (per Bbl) (3)	$	88.26	$	95.90	$	87.11
Gas (per MMBtu) (4)	$	2.61	$	3.65	$	5.15
NGL’s (per Bbl) (5)	$	36.76	$	31.98	$	37.91

_____________________


(1)	The quoted oil price for the year ended December 31 of each year, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month West Texas Intermediate spot price for each month of 2012, 2013 and 2014.


(2)	The quoted gas price for the year ended December 31, 2012, 2013 and 2014 is the 12-month average first-day-of-the-month Henry Hub spot price for each month of 2012, 2013 and 2014.


(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.