Oil and Gas Reserve Information - Unaudited

12 Months Ended

Dec. 31, 2011

Investment in Oil and Gas Properties/Oil and Gas Reserve Information - Unaudited [Abstract]

Oil and Gas Reserve Information - Unaudited

Note 15—Oil and Gas Reserve Information—Unaudited

The Company’s net proved oil and gas reserves at December 31, 2011 have been estimated by independent petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission.

The estimates of proved oil and gas reserves constitute those quantities of oil and gas, 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.

On December 29, 2008, the SEC issued a revision to Staff Accounting Bulletin 113 (“SAB 113”) which established guidelines related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize a historical 12-month average price based on beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves rather than year-end prices. In addition, the 12-month average is used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules are effective for reserve estimates beginning December 31, 2009.

During 2011, the Company’s estimated proved reserves increased by 38%. This increase was primarily due to a successful drilling program in Oklahoma in the Woodford Shale. Additionally, reserves increased due to positive performance revisions from the Company’s Oklahoma assets. In total, the Company added approximately 70 Bcfe of proved reserves in Oklahoma, 8 Bcfe from the La Cantera discovery and 9 Bcfe in the Carthage Field from horizontal drilling in the Cotton Valley during 2011. Overall, the Company had a 99% drilling success rate during 2011 on 118 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) and gas reserves, all located onshore and offshore the continental United States:

		September 30,			September 30,			September 30,			September 30,
	Oil			NGL			Natural Gas			Total
	in			in			in			Reserves
	MBbls			MMcfe			MMcf			in MMcfe
Proved reserves as of December 31, 2008		2,201			13,405			158,781			185,392
Revisions of previous estimates		321			(664	)		(9,953	)		(8,691	)
Extensions, discoveries and other additions		9			300			39,003			39,357
Sale of reserves in place		—			—			(2,913	)		(2,913	)
Production		(600	)		(2,533	)		(28,065	)		(34,198	)
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
Sale of reserves in place		—			—			—			—
Production		(572	)		(2,288	)		(24,463	)		(30,183	)
Proved reserves as of December 31, 2011		1,395			15,111			241,926			265,407
Proved developed reserves
As of December 31, 2009		1,775			7,134			93,294			111,078
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
Proved undeveloped reserves
As of December 31, 2009		156			3,372			63,559			67,867
As of December 31, 2010		149			2,295			63,967			67,156
As of December 31, 2011		235			4,040			98,485			103,935

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 the FASB. 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

		September 30,			September 30,			September 30,
	December 31,
	2011			2010			2009
Future cash flows	$	1,080,392		$	810,131		$	614,293
Future production costs		(264,219	)		(223,175	)		(193,427	)
Future development costs		(180,846	)		(144,451	)		(148,595	)
Future income taxes		(86,612	)		(41,156	)		(3,166	)
Future net cash flows		548,715			401,349			269,105
10% annual discount		(244,834	)		(164,974	)		(94,817	)
Standardized measure of discounted future net cash flows	$	303,881		$	236,375		$	174,288

Changes in Standardized Measure

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Standarized measure at beginning of year	$	236,375		$	174,288		$	314,787
Sales and transfers of oil and gas produced, net of production costs		(116,398	)		(117,572	)		(95,555	)
Changes in price, net of future production costs		(10,219	)		93,702			(100,150	)
Extensions and discoveries, net of future production and development costs		178,901			42,028			2,790
Changes in estimated future development costs, net of development costs incurred during this period		915			5,803			38,407
Revisions of quantity estimates		11,236			46,373			(15,045	)
Accretion of discount		25,565			17,700			32,719
Net change in income taxes		(18,215	)		(16,568	)		9,698
Purchase of reserves in place		4,805			1,478			—
Sale of reserves in place		—			(798	)		(2,138	)
Changes in production rates (timing) and other		(9,084	)		(10,059	)		(11,225	)
Standardized measure at end of year	$	303,881		$	236,375		$	174,288

The weighted average prices of oil, ngls and gas used for the above tables at December 31, 2011, 2010 and 2009 were $101.42, $79.72 and $60.57 per barrel of oil, respectively, $8.62, $7.00 and $4.89 per Mcfe of natural gas liquids, respectively, and $3.34, $3.56 and $2.84 per Mcf of natural gas, respectively.