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,
	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.

At December 31, 2017 and 2016, unevaluated oil and gas properties totaled $21.9 million and $9.0 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2017 included $0.7 million related to two facilities in progress at year-end. At December 31, 2016, unevaluated costs included $0.4 million related to one development well in progress at year-end, which were transferred to evaluated oil and gas properties during 2017. The Company capitalized $1.6 million, $0.9 million and $4.7 million of interest during 2017, 2016 and 2015, respectively. Of the total unevaluated oil and gas property costs of $21.9 million at December 31, 2017, $14.6 million, or 67%, was incurred in 2017, $2.0 million, or 9%, was incurred in 2016 and $5.2 million, or 24%, was incurred in prior years. In connection with the sale of the Company's Gulf of Mexico assets, approximately $5.5 million, or 25% of the total unevaluated balance at December 31, 2017, was transferred to evaluated oil and gas properties in 2018. Of the remaining unevaluated balance at December 31, 2017, the Company expects the majority of the costs will be evaluated within the next three years, including $4.1 million expected to be evaluated during 2018.

Oil and Gas Reserve Information

The Company’s net proved oil and gas reserves at December 31, 2017 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, 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

Year Ended December 31, 2017

During 2017, the Company’s estimated proved reserves increased by 35%. The increase in reserves was the result of 73.9 Bcfe added due to the Company's drilling program in East Texas where it drilled eight gross wells during 2017. In response to low ethane prices, during 2017 the Company elected to bypass ethane processing on a portion of its East Texas production. As a result, the Company reduced its estimated proved ngl reserves to reflect the assumption that ethane would continue to not be recovered as natural gas liquids. Overall, the Company had a 100% drilling success rate during 2017.

Year Ended December 31, 2016

During 2016, the Company’s estimated proved reserves decreased by 35% 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 5 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.

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,
	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

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

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