Supplementary Information on Oil and Gas Operations—Unaudited

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.

At December 31, 2016 and 2015, unevaluated oil and gas properties totaled $9.0 million and $12.5 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2016 included $0.4 million of costs related to one development well in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2017 upon the completion of drilling. At December 31, 2015, unevaluated costs included $0.2 million related to 2 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2016. The Company capitalized $0.9 million, $4.7 million and $10.0 million of interest during 2016, 2015 and 2014, respectively. Of the total unevaluated oil and gas property costs of $9.0 million at December 31, 2016, $3.4 million, or 38%, was incurred in 2016, $1.1 million, or 12%, was incurred in 2015 and $4.5 million, or 50%, was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2016 will be evaluated within the next three years, including $1.8 million that the Company expects to be evaluated during 2017.

Oil and Gas Reserve Information

The Company’s net proved oil and gas reserves at December 31, 2016 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-month, first of month, average pricing assumption.

The estimates of proved oil and gas reserves constitute those quantities of oil, gas,and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

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

Year Ended December 31, 2016

During 2016, the Company’s estimated proved reserves decreased by 35%. The decline in reserves was primarily due to the divestiture of the Company's remaining Oklahoma assets and significant reductions in capital spending during 2016. Extensions, discoveries and other additions of 1.5 Bcfe were primarily due to the successful completion of the Company's final Oklahoma wells. Revisions of previous estimates included the reclassification of certain PUD reserves to probable reserves as a result of the Company's assessment of the timing of development. Overall, the Company had a 100% drilling success rate during 2016 on five gross wells drilled.

Year Ended December 31, 2015

During 2015, the Company’s estimated proved reserves decreased by 55% primarily due to the divestiture of the majority of the Company's Woodford Shale and Mississippian Lime assets. Extensions, discoveries and other additions of 63 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields. The Company added approximately 17 Bcfe of proved reserves in Oklahoma and 44 Bcfe in Texas. Overall, the Company had a 95% drilling success rate during 2015 on 56 gross wells drilled.

Year Ended December 31, 2014

During 2014, the Company's estimated proved reserves increased by 34%. Extensions, discoveries and other additions of 135 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields and its Thunder Bayou discovery. The Company added approximately 72 Bcfe of proved reserves in Oklahoma, 46 Bcfe in Texas and 15 Bcfe in the Gulf Coast. Overall, the Company had a 91% drilling success rate during 2014 on 58 gross wells drilled.

The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by ASC Topic 932. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate.

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

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

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