Supplementary Information on Oil and Gas Operations—Unaudited (Tables)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Costs incurred in oil and gas property acquisition

The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore in the continental United States:

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

(amounts in thousands)

	For the Year-Ended December 31,
	2017			2016			2015
Acquisition costs:
Proved	$	1,330		$	3,346		$	2,287
Unproved (1)	12,762			2,197			2,550
Divestiture of proved leasehold	(4,795		)	(7,000		)	—
Exploration costs:
Proved	9,466			715			29,322
Unproved	(287		)	603			7,677
Development costs	32,622			1,522			9,888
Capitalized general and administrative and interest costs	8,269			7,558			12,881
Total costs incurred	$	59,367		$	8,941		$	64,605

	For the Year-Ended December 31,
	2017			2016			2015
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,243,286	)	$	(1,157,455	)	$	(1,648,060	)
Provision for DD&A	(31,667		)	(27,962		)	(62,138		)
Ceiling test writedown	—			(40,304		)	(266,562		)
Sale of proved properties and other (2) (3)	(10,707		)	(17,565		)	819,305
Balance, end of year	$	(1,285,660	)	$	(1,243,286	)	$	(1,157,455	)
DD&A per Mcfe	$	1.15		$	1.19		$	1.82

(1) During 2017, the Company acquired approximately 24,600 gross acres for approximately $9.3 million of cash and 2.0 million shares of common stock.

(2) During 2015, the Company sold its Woodford Shale and Mississippian Lime assets for an aggregate cash purchase price of $274.1 million (see Note 2).

(3) During 2017, the Company sold its East Lake Verret assets for net proceeds of approximately $2.2 million and its East Texas saltwater disposal assets for net proceeds of $8.5 million. During 2016, the Company sold its remaining Oklahoma producing assets for an aggregate purchase price of $17.6 million. During 2015, the Company sold its Fort Trinidad assets for net proceeds of approximately $0.5 million and its East Haynesville assets for net proceeds of approximately $0.1 million.

Schedule of proved developed reserve quantities

The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate), gas and natural gas liquid reserves, all located onshore and offshore in the continental United States:

	Oil in MBbls		NGL in MMcfe		Natural Gas in MMcf		Total Reserves in MMcfe
Proved reserves as of December 31, 2014	2,437		73,498		309,025		397,148
Revisions of previous estimates	(211	)	(3,571	)	(9,852	)	(14,698	)
Extensions, discoveries and other additions	163		16,078		45,645		62,702
Sale of reserves in place	(54	)	(45,692	)	(186,972	)	(232,988	)
Production	(529	)	(5,487	)	(25,502	)	(34,160	)
Proved reserves as of December 31, 2015	1,806		34,826		132,344		178,004
Revisions of previous estimates	247		(4,380	)	(11,854	)	(14,748	)
Extensions, discoveries and other additions	—		—		1,485		1,485
Sale of reserves in place	(154	)	—		(24,834	)	(25,759	)
Production	(502	)	(3,871	)	(16,617	)	(23,501	)
Proved reserves as of December 31, 2016	1,397		26,575		80,524		115,481
Revisions of previous estimates	308		(7,269	)	381		(5,040	)
Extensions, discoveries and other additions	777		4,565		64,704		73,931
Purchase of producing properties	48		—		473		761
Sale of reserves in place	(90	)	—		(1,033	)	(1,573	)
Production	(592	)	(4,450	)	(19,611	)	(27,613	)
Proved reserves as of December 31, 2017	1,848		19,421		125,438		155,947
Proved developed reserves
As of December 31, 2015	1,549		15,792		78,533		103,615
As of December 31, 2016	1,212		13,073		47,349		67,694
As of December 31, 2017	1,078		12,564		57,409		76,441
Proved undeveloped reserves
As of December 31, 2015	257		19,034		53,811		74,389
As of December 31, 2016	185		13,502		33,175		47,787
As of December 31, 2017	770		6,857		68,029		79,506

Standardized measure of discounted future cash flows

Standardized Measure

	December 31,
	2017			2016			2015
Future cash flows	$	539,244		$	299,035		$	487,834
Future production costs	(184,171		)	(117,283		)	(171,678		)
Future development costs	(128,447		)	(83,720		)	(116,591		)
Future income taxes	—			—			—
Future net cash flows	226,626			98,032			199,565
10% annual discount	(99,329		)	(30,763		)	(71,880		)
Standardized measure of discounted future net cash flows	$	127,297		$	67,269		$	127,685

Schedule of changes in standardized measure of discounted future net cash flows

Changes in Standardized Measure

	Year Ended December 31,
	2017			2016			2015
Standardized measure at beginning of year	$	67,269		$	127,685		$	548,562
Sales and transfers of oil and gas produced, net of production costs	(70,362		)	(35,993		)	(55,849		)
Changes in price, net of future production costs	53,516			(30,427		)	(267,710		)
Extensions and discoveries, net of future production and development costs	50,977			864			70,928
Changes in estimated future development costs, net of development costs incurred during this period	17,144			26,356			31,007
Revisions of quantity estimates	(7,482		)	(14,889		)	(14,427		)
Accretion of discount	6,727			12,769			60,071
Net change in income taxes	—			—			52,149
Purchase of reserves in place	549			—			—
Sale of reserves in place	(1,305		)	(16,701		)	(194,454		)
Changes in production rates (timing) and other	10,264			(2,395		)	(102,592		)
Net increase (decrease) in standardized measure	60,028			(60,416		)	(420,877		)
Standardized measure at end of year	$	127,297		$	67,269		$	127,685

Average sales price and average production costs

The historical twelve-month, first day of the month, average prices of oil, gas and natural gas liquids used in determining standardized measure were:

	2017	2016	2015
Oil, $/Bbl	$52.49	$40.85	$50.29
Ngls, $/Mcfe	3.23	2.40	2.24
Natural Gas, $/Mcf	3.03	1.82	2.41