—Oil and Gas Reserve Information—Unaudited

The Company’s net proved oil and gas reserves at December 31, 2012 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-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.

During 2012, the Company’s estimated proved reserves decreased by 14%. This decrease was primarily due to production, the sale of the Company's non-operated Arkansas assets and the significant decrease in the historical 12-month average price per Mcf of natural gas used to calculate estimated proved reserves which was $2.20 per Mcf at December 31, 2012 as compared to $3.34 per Mcf at December 31, 2011. This decrease was partially offset by the success of our Oklahoma,Texas and Gulf Coast drilling programs. In total, the Company added approximately 27 Bcfe of proved reserves in Oklahoma, 9 Bcfe from the La Cantera discovery and 28 Bcfe in the Carthage Field from horizontal drilling in the Cotton Valley during 2012. Overall, the Company had a 98% drilling success rate during 2012 on 107 gross wells drilled.

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 the continental United States:



	Oil in MBbls		NGL in MMcfe		Natural Gas in MMcf		Total Reserves in MMcfe
Proved reserves as of December 31, 2009	1,931		10,508		156,853		178,947
Revisions of previous estimates	187		187		20,958		22,267
Extensions, discoveries and other additions	168		150		47,681		48,839
Purchase of producing properties	—		—		2,336		2,336
Sale of reserves in place	—		—		(28,761	)	(28,761	)
Production	(663	)	(2,472	)	(24,501	)	(30,951	)
Proved reserves as of December 31, 2010	1,623		8,373		174,566		192,677
Revisions of previous estimates	(294	)	308		8,418		6,962
Extensions, discoveries and other additions	595		8,627		82,113		94,310
Purchase of producing properties	43		91		1,292		1,641
Production	(572	)	(2,288	)	(24,463	)	(30,183	)
Proved reserves as of December 31, 2011	1,395		15,111		241,926		265,407
Revisions of previous estimates	215		(958	)	(52,076	)	(51,744	)
Extensions, discoveries and other additions	647		14,572		46,390		64,844
Sale of reserves in place	(81	)	—		(15,806	)	(16,292	)
Production	(521	)	(3,365	)	(27,466	)	(33,957	)
Proved reserves as of December 31, 2012	1,655		25,360		192,968		228,258

Proved developed reserves

As of December 31, 2010	1,474		6,078		110,599		125,521

As of December 31, 2011	1,160		11,071		143,441		161,472

As of December 31, 2012	1,225		20,608		140,307		168,265

Proved undeveloped reserves

As of December 31, 2010	149		2,295		63,967		67,156

As of December 31, 2011	235		4,040		98,485		103,935

As of December 31, 2012	430		4,752		52,661		59,993

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,
	2012			2011			2010
Future cash flows	$	748,914		$	1,080,392		$	810,131
Future production costs	(220,750		)	(264,219		)	(223,175		)
Future development costs	(121,346		)	(180,846		)	(144,451		)
Future income taxes	(10,205		)	(86,612		)	(41,156		)
Future net cash flows	396,613			548,715			401,349

10% annual discount	(164,218		)	(244,834		)	(164,974		)

Standardized measure of discounted future net cash flows	$	232,395		$	303,881		$	236,375

Changes in Standardized Measure



	Year Ended December 31,
	2012			2011			2010
Standardized measure at beginning of year	$	303,881		$	236,375		$	174,288

Sales and transfers of oil and gas produced, net of production costs	(92,562		)	(116,398		)	(117,572		)
Changes in price, net of future production costs	(138,842		)	(10,219		)	93,702
Extensions and discoveries, net of future production and development costs	104,066			178,901			42,028
Changes in estimated future development costs, net of development costs incurred during this period	69,499			915			5,803
Revisions of quantity estimates	(56,352		)	11,236			46,373
Accretion of discount	34,137			25,565			17,700
Net change in income taxes	30,617			(18,215		)	(16,568		)
Purchase of reserves in place	—			4,805			1,478
Sale of reserves in place	(8,186		)	—			(798		)
Changes in production rates (timing) and other	(13,863		)	(9,084		)	(10,059		)
Net increase (decrease) in standardized measure	(71,486		)	67,506			62,087
Standardized measure at end of year	$	232,395		$	303,881		$	236,375

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



	2012	2011	2010

Oil, $/Bbl	$102.81	$101.42	$79.72
Ngls, $/Mcfe	6.07	8.62	7.00
Natural Gas, $/Mcf	2.20	3.34	3.56