Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2014

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities

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

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

Results of Operations for Oil and Gas Producing Activities

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

Proved Developed and Undeveloped Reserves

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

Future Net Cash Inflows after Income Taxes Discounted At 10% Annual Discount Rate to Arrive At Standardized Measure

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

Analysis of Changes in Standardized Measure

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

Oil and Gas Prices Considered In Standardized Measure of Discounted Future Net Cash Flows

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.