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

12 Months Ended

Dec. 31, 2016

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,
	2016			2015		2014
Acquisition costs:
Proved	$	3,346		$	2,287	$	3,064
Unproved (1)	2,197			2,550		39,164
Divestiture of proved leasehold	(7,000		)	—		—
Exploration costs:
Proved	715			29,322		67,297
Unproved	603			7,677		13,515
Development costs	1,522			9,888		55,722
Capitalized general and administrative and interest costs	7,558			12,881		22,121
Total costs incurred	$	8,941		$	64,605	$	200,883

	For the Year-Ended December 31,
	2016			2015			2014
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,157,455	)	$	(1,648,060	)	$	(1,553,044	)
Provision for DD&A	(27,962		)	(62,138		)	(86,406		)
Ceiling test writedown	(40,304		)	(266,562		)	—
Sale of proved properties and other (2) (3)	(17,565		)	819,305			(8,610		)
Balance, end of year	$	(1,243,286	)	$	(1,157,455	)	$	(1,648,060	)
DD&A per Mcfe	$	1.19		$	1.82		$	1.99

(1) During 2014, the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million for an approximate 30,000 acre leasehold position.

(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 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. During 2014, the Company sold its Eagle Ford assets for net proceeds of approximately $9.8 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, 2013	3,031		28,430		250,109		296,723
Revisions of previous estimates	(37	)	2,894		9,976		12,650
Extensions, discoveries and other additions	475		49,990		82,364		135,205
Sale of reserves in place	(229	)	(334	)	(2,396	)	(4,105	)
Production	(803	)	(7,482	)	(31,028	)	(43,325	)
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
Proved developed reserves
As of December 31, 2014	2,089		42,584		182,567		237,688
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
Proved undeveloped reserves
As of December 31, 2014	348		30,914		126,458		159,460
As of December 31, 2015	257		19,034		53,811		74,389
As of December 31, 2016	185		13,502		33,175		47,787

Standardized measure of discounted future cash flows

Standardized Measure

	December 31,
	2016			2015			2014
Future cash flows	$	299,035		$	487,834		$	1,711,404
Future production costs	(117,283		)	(171,678		)	(372,690		)
Future development costs	(83,720		)	(116,591		)	(244,784		)
Future income taxes	—			—			(121,192		)
Future net cash flows	98,032			199,565			972,738
10% annual discount	(30,763		)	(71,880		)	(424,176		)
Standardized measure of discounted future net cash flows	$	67,269		$	127,685		$	548,562

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

Changes in Standardized Measure

	Year Ended December 31,
	2016			2015			2014
Standardized measure at beginning of year	$	127,685		$	548,562		$	451,180
Sales and transfers of oil and gas produced, net of production costs	(35,993		)	(55,849		)	(173,540		)
Changes in price, net of future production costs	(30,427		)	(267,710		)	37,204
Extensions and discoveries, net of future production and development costs	864			70,928			237,290
Changes in estimated future development costs, net of development costs incurred during this period	26,356			31,007			11,094
Revisions of quantity estimates	(14,889		)	(14,427		)	25,591
Accretion of discount	12,769			60,071			47,130
Net change in income taxes	—			52,149			(32,034		)
Sale of reserves in place	(16,701		)	(194,454		)	(7,240		)
Changes in production rates (timing) and other	(2,395		)	(102,592		)	(48,113		)
Net increase (decrease) in standardized measure	(60,416		)	(420,877		)	97,382
Standardized measure at end of year	$	67,269		$	127,685		$	548,562

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:

	2016	2015	2014
Oil, $/Bbl	$40.85	$50.29	$96.45
Ngls, $/Mcfe	2.40	2.24	4.11
Natural Gas, $/Mcf	1.82	2.41	3.80