Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

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 “Disclosures about Oil and Gas Producing Activities.”  Capitalized costs relating to oil and gas producing activities are as follows:

	Years Ended December 31
	2015			2016
	(In thousands)
Proved oil and gas properties	$	787,683		$	794,634
Unproved properties	—			—
Total	787,683			794,634
Accumulated depreciation, depletion, amortization and impairment	(590,432		)	(680,861		)
Net capitalized costs	$	197,251		$	113,773

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
	2014		2015		2016
	(In thousands)
Development costs	$	189,322	$	68,631	$	18,262
Exploration costs	—		—		12,529
Property acquisition costs	—		—		—
Unproved	—		—		—
	$	189,322	$	68,631	$	30,791

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, 2014, 2015 and 2016 are as follows:

	Years Ended December 31,
	2014			2015			2016
	(In thousands)
Revenues	$	133,701		$	67,002		$	56,493
Production costs	(37,337		)	(29,753		)	(23,659		)
Depreciation, depletion, and amortization	(42,945		)	(38,040		)	(22,803		)
Proved property impairment	—			(128,573		)	(67,626		)
Results of operations from oil and gas producing activities (excluding corporate overhead and interest costs)	$	53,419		$	(129,364	)	$	(57,595	)
Depletion rate per barrel of oil equivalent	$	20.39		$	17.44		$	10.08

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 unweighted 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.

The following is a summary of the changes to the Company’s proved reserves that occurred during 2016:

Revisions to prior estimates:

An increase of 5,005 MBoe of reserves was attributed to the Company’s Bakken and Three Forks proved undeveloped locations in McKenzie County, ND, due to continuing improvement in its producing well production results. Well results improved as a result of the application of optimized completion methods. Similarly, reserves for the Company’s Bakken and Three Forks producing wells increased by 1,360 MBoe of net producing reserves due to improved performance. On the other hand, projections for the Hedgehog State 16-2H producing well and its two related proved undeveloped locations in the Porcupine Field, Campbell County, WY, decreased by 670 MBoe of net reserves due to the under-performance of the Hedgehog State 16-2H. There was also a reduction in this category of 2,271 MBoe attributable to shortened economic life calculations at the lower commodity pricing.

Extensions, discoveries and other additions:

The Company added the Caprito 99 302H as a new Wolfcamp producing well in Ward County, TX, accounting for 449 MBoe of net producing reserves. It also added five new proved undeveloped Wolfcamp locations offsetting this new producer accounting for 805 MBoe of net undeveloped reserves. The Company also developed a new Austin Chalk producer in Atascosa County, TX, which accounted for 265 MBoe of net producing reserves. Further, the Company added eight new proved undeveloped Bakken/Three Forks locations on non-operated units in McKenzie County, ND, accounting for 18 MBoe of net undeveloped reserves. These locations were added in response to operator well proposals.

Sales:

The Company sold all its holdings in the Portilla Field in San Patricio County, TX, and in the Brooks Draw Field in Converse County, WY, during 2016. These sales accounted for 1,232 MBoe of net proved reserves.

Production:

The Company produced 2,262 MBoe of net reserves during 2016.

The following is a summary of the changes to the Company’s proved reserves that occurred during 2015:

Revisions of prior estimates:

A total of 48 proved locations accounting for approximately 7.9 net MMBoe of reserves were dropped from the report in 2015 due to lack of economic viability at the lower commodity pricing applied of which 42 were in the undeveloped category. Most significant of these were 38 South Texas Eagle Ford locations representing approximately 7,717 MBoe of net reserves. There was also a reduction of 614 net MBoe attributable to shortened economic life calculations at lower commodity pricing which were partially offset by an increase of 600 net MBoe in the Company’s Bakken/Three Forks undeveloped locations due to better-than-anticipated production. There were also reduction in this category of 1.8 MMBoe of net reserves attributable to shortened economic life calculations at the lower commodity pricing and 1.6 MMBoe of net reserves attributable to lower than anticipated production performance in various wells.

Extensions, discoveries and other additions:

The Company added 28 new proved undeveloped Bakken locations during 2015 on the Company’s prospect acreage in McKenzie County, North Dakota, accounting for approximately 6.5 MMBoe of net reserves, 20 of which accounting for 4.9 net MMBoe, were for the Three Forks (2^nd Bench) which were proved by local development activity in that reservoir during the year. There were also 8 other cases in the Bakken/Three Forks, accounting for 1.6 net MMBoe, which were added because the Company gained operational control of the Yellowstone Unit resulting in the Company developing the properties in accordance with its normal well spacing pattern.

The Company also gained proved undeveloped reserves of approximately 1.3 net MMBOE, due to the change in classification of 21 probable and possible undeveloped Bakken cases into the proved category. This change was warranted by local well development in the specific local areas during 2015.

The Company also added 6 new Montoya proved undeveloped locations on the Company’s prospect acreage in Ward County, Texas, accounting for 6.5 MMBOE of net reserves. These locations were added based on the performance of existing Montoya producers on the subject acreage.

Sales:

During 2015, the Company sold properties accounting for 43 net MBoe of reserves.

Production:

During 2015, the Company produced 2,181 of net MBoe of reserves

	Oil		NGL		Gas		Oil Equivalents
	(MBbl)		(MBbl)		(MMcf)		(MBoe)
Proved developed and undeveloped reserves:			(in thousands)
Balance at December 31, 2013	20,915		2,038		48,109		30,970
Revisions of previous estimates	2,697		1,021		7,383		4,950
Extensions and discoveries	7,780		868		6,893		9,797
Sales of minerals in place	(608	)	(12	)	(3,614	)	(1,223	)
Production	(1,394	)	(207	)	(2,918	)	(2,088	)
Balance at December 31, 2014	29,390		3,708		55,853		42,406
Revisions of previous estimates	(9,485	)	(505	)	(8,002	)	(11,324	)
Extensions and discoveries	5,679		3,591		30,372		14,332
Sales of minerals in place	(13	)	—		(181	)	(43	)
Production	(1,440	)	(238	)	(3,015	)	(2,181	)
Balance at December 31, 2015	24,131		6,556		75,027		43,190
Revisions of previous estimates	1,379		2,300		(1,537	)	3,424
Extensions and discoveries	1,183		157		1,179		1,537
Sales of minerals in place	(1,112	)	(6	)	(680	)	(1,232	)
Production	(1,372	)	(363	)	(3,160	)	(2,262	)
Balance at December 31, 2016	24,209		8,644		70,829		44,657

	Total
	Oil	NGL	Gas	Oil Equivalents
	(MBbl)	(MBbl)	(MMcf)	(MBoe)
	(In thousands)
Proved Developed Reserves:
December 31, 2014	10,162	2,006	34,677	17,948
December 31, 2015	10,022	1,956	31,298	17,194
December 31, 2016	7,818	2,568	27,792	15,018
Proved Undeveloped Reserves:
December 31, 2014	19,228	1,702	21,176	24,459
December 31, 2015	14,109	4,599	43,729	25,996
December 31, 2016	16,391	6,076	43,037	29,639

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, 2014, 2015 and 2016:

	Years Ended December 31,
	2014			2015			2016
	(In thousands)
Future cash inflows	$	2,988,464		$	1,241,334		$	999,716
Future production costs	(921,977		)	(438,784		)	(357,917		)
Future development costs	(557,782		)	(338,316		)	(267,836		)
Future income tax expense	(373,095		)	—			—
Future net cash flows	1,135,610			464,234			373,963
Discount	(623,053		)	(266,983		)	(213,363		)
Standardized Measure of discounted future net cash relating to proved reserves	$	512,557		$	197,251		$	160,600

Analysis of Changes in Standardized Measure

The following is an analysis of the changes in the Standardized Measure:

	Year Ended December 31,
	2014			2015			2016
	(In thousands)
Standardized Measure, beginning of year	$	340,985		$	512,557		$	197,251
Sales and transfers of oil and gas produced, net of production costs	(96,364		)	(37,249		)	(32,834		)
Net change in prices and development and production costs from prior year	150,504			(488,160		)	(58,425		)
Extensions, discoveries, and improved recovery, less related costs	147,275			63,341			5,531
Sales of minerals in place	(15,042		)	(197		)	(4,433		)
Revisions of previous quantity estimates	74,390			(49,602		)	12,317
Change in timing and other	(82,653		)	20,419			21,468
Change in future income tax expense	(40,636		)	124,886			—
Accretion of discount	34,098			51,256			19,725
Standardized Measure, end of year	$	512,557		$	197,251		$	160,600

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,
	2014		2015		2016
Oil (per Bbl) (1)	$	95.28	$	50.12	$	42.74
Gas (per MMbtu) (2)	$	4.35	$	2.63	$	2.50
Oil (per Bbl) (3)	$	87.11	$	41.25	$	35.54
Gas (per MMBtu) (4)	$	5.15	$	2.36	$	1.41
NGL’s (per Bbl) (5)	$	37.92	$	10.52	$	5.17

_____________________

(1) The quoted oil price for the year ended December 31 of each year, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month West Texas Intermediate spot price for each month of 2014, 2015 and 2016.

(2) The quoted gas price for the year ended December 31, 2014, 2015 and 2016 is the 12-month unweighted average first-day-of-the-month Henry Hub spot price for each month of 2014, 2015 and 2016.

(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.