Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following supplemental information regarding the oil and gas producing activities is presented in accordance with the requirements of the current oil and gas accounting standards.

Capitalized Costs Relating to Oil and Gas Producing Activities

	As of December 31,
	2011			2010			2009
Proved properties	$	277,987		$	293,486		$	353,386
Unproved properties		120,288			171,303			73,067
Wells, equipment and facilities		2,081,103			1,840,154			1,527,749
Support equipment		6,645			6,254			5,938
		2,486,023			2,311,197			1,960,140
Accumulated depreciation and depletion		(710,948	)		(609,380	)		(487,106	)
Net capitalized costs	$	1,775,075		$	1,701,817		$	1,473,034

ARO assets of $0.2 million, $0.1 million and $0.4 million were added to the cost basis of proved properties during the years ended December 31, 2011, 2010 and 2009, respectively.

Costs Incurred in Certain Oil and Gas Activities

	Year Ended December 31,
	2011		2010		2009
Proved property acquisition costs	$	-	$	5,671	$	-
Unproved property acquisition costs		47,877		133,185		14,996
Exploration costs		77,460		66,886		7,179
Development costs and other		320,263		244,092		149,625
Total costs incurred	$	445,600	$	449,834	$	171,800

Results of Operations for Oil and Gas Producing Activities

The following table includes results solely from the production and sale of oil and gas and non-cash charges for property impairments. It excludes corporate-related general and administrative expenses and gains or losses on property dispositions. Income tax expense (benefit) is calculated by applying statutory tax rates to revenues after deducting costs and giving effect to oil and gas-related permanent differences and tax credits.

	Year Ended December 31,
	2011			2010			2009
Revenues	$	300,046		$	251,336		$	228,659
Production expenses		65,835			63,854			72,255
Exploration expenses		78,943			49,641			57,754
Depreciation and depletion expense		160,293			130,816			150,429
Impairment of oil and gas properties		104,688			45,959			106,415
		(109,713	)		(38,934	)		(158,194	)
Income tax expense (benefit)		(42,788	)		(15,184	)		(61,221	)
Results of operations	$	(66,925	)	$	(23,750	)	$	(96,973	)

A combined total of depletion and accretion expense related to AROs of $0.7 million was recognized in DD&A expense during each of the years ended December 31, 2011, 2010 and 2009.

Oil and Gas Reserves

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available.

Our Manager of Engineering is primarily responsible for overseeing the preparation of the Company’s reserve estimate by our independent third party engineers, Wright & Company, Inc. The Manager of Engineering has over 26 years of industry experience in the estimation and evaluation of reserve information, holds a B.S. degree in Petroleum Engineering from Texas A&M University and is licensed by the state of Texas as a Professional Engineer. The Company’s internal controls over reserve estimates include reconciliation and review controls, including an independent internal review of assumptions used in the estimation.

The technical person primarily responsible for review of our reserve estimates at Wright & Company, Inc., meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Wright & Company, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

The following table sets forth the Company’s net quantities of proved reserves, including changes therein and proved developed and proved undeveloped reserves for the periods presented. This information includes our royalty and net working interest share of the reserves in oil and gas properties. All reserves are located in the United States. Net proved oil and gas reserves for the three years ended December 31, 2011 were estimated by Wright & Company, Inc., utilizing data compiled by us.

	Natural			Oil and			Total
	Gas			Condensate			Equivalents
Proved Developed and Undeveloped Reserves	(MMcf)			(MBbl)			(MMcfe)
December 31, 2008		754,132			26,974			915,975
Revisions of previous estimates ¹		(110,349	)		(8,442	)		(160,995	)
Extensions, discoveries and other additions ²		180,448			9,203			235,666
Production		(43,337	)		(1,277	)		(51,000	)
Purchase of reserves		-			-			-
Sale of reserves in place		(4,229	)		(71	)		(4,659	)
December 31, 2009		776,665			26,387			934,987
Revisions of previous estimates ³		(71,421	)		5,202			(40,210	)
Extensions, discoveries and other additions ⁴		90,439			4,069			114,851
Production		(38,919	)		(1,380	)		(47,201	)
Purchase of reserves		3,288			9			3,342
Sale of reserves in place		(15,070	)		(1,490	)		(24,014	)
December 31, 2010		744,982			32,797			941,755
Revisions of previous estimates ⁵		(61,165	)		(5,414	)		(93,649	)
Extensions, discoveries and other additions ⁶		56,345			10,399			118,746
Production		(33,410	)		(2,190	)		(46,553	)
Purchase of reserves		1			20			124
Sale of reserves in place		(36,840	)		(42	)		(37,092	)
December 31, 2011		669,913			35,570			883,331

Proved Developed Reserves:
December 31, 2009		388,382			8,357			438,524
December 31, 2010		412,644			14,813			501,521
December 31, 2011		330,552			16,470			429,370

Proved Undeveloped Reserves:
December 31, 2009		388,283			18,030			496,463
December 31, 2010		332,338			17,984			440,234
December 31, 2011		339,361			19,100			453,961

We had downward revisions of 161 Bcfe which were primarily the result of the following: 1) downward revisions of 63.1 Bcfe due to price, 2) a downward revision of 27.1 Bcfe in Appalachia for the removal of proved undeveloped reserves, which resulted from wells that no longer met the reasonable certainty threshold, 3) downward revisions of 20.1 Bcfe for NGLs that we received in East Texas as a result of lower plant yields and 4) various downward revisions amounting to 50.7 Bcfe across our assets as a result of well performance and the application of the revised oil and gas reserve calculation methodology required by the SEC in 2009.

We added 235.7 Bcfe due to the drilling of 13 wells on locations that were not classified as proved undeveloped locations in our 2008 year-end reserve report and the addition of 105 new proved undeveloped locations, primarily in the Gulf Coast and Mid-Continent regions, as a result of our 2009 drilling activities.

We had downward revisions of 40.2 Bcfe primarily as a result of the following: 1) downward revisions of 45 Bcfe due to the removal of 200 proved undeveloped locations that would not be developed within five years, 2) upward revisions of 34 Bcfe as a result of processing the gas in the Mid-Continent Granite Wash for NGLs, 3) upward revisions of 12 Bcfe due to higher prices and 4) various downward revisions for 39 Bcfe across our assets as a result of well performance, lease expirations and interest changes.

⁴

We added 114.9 Bcfe due to the drilling of 16 wells on locations not classified as proved undeveloped locations in our 2009 year-end reserve report and the addition of 51 new proved undeveloped locations, primarily in East Texas, as a result of our 2010 drilling activities.

⁵

We had downward revisions of 93.6 Bcfe primarily as a result of the following: 1) downward revisions of 72 Bcfe due to well performance issues, interest changes and economic limits attributable to operating conditions particularly in the Granite Wash, Cotton Valley and Selma Chalk, 2) downward revisions of 10 Bcfe due to lower condensate yield in the Granite Wash, 3) downward revisions of 9 Bcfe attributable to the elimination of proved undeveloped locations particularly in the Haynesville Shale in East Texas, 4) downward revisions of 5 Bcfe due to lower natural gas prices and 5) upward revisions of 3 Bcfe due to higher gas processing yields in the Haynesville Shale and Granite Wash.

⁶

We added 118.7 Bcfe due primarily to an increase of 54 Bcfe due to the drilling of three Marcellus Shale wells and two Granite Wash wells as well as the addition of 25 proved undeveloped locations in the Marcellus Shale and Selma Chalk. We also drilled 28 Eagle Ford Shale wells and added 26 proved undeveloped locations which resulted in an increase of 65 Bcfe.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows were computed by applying the average prices of oil and gas during the 12-month period prior to the period end determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period and estimated costs as of that fiscal year end to the estimated future production of proved reserves. Natural gas prices were escalated only where existing contracts contained fixed and determinable escalation clauses. Contractually provided natural gas prices in excess of estimated market clearing prices were used in computing the future cash inflows only if we expect to continue to receive higher prices under legally enforceable contract terms. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

	Year Ended December 31,
	2011			2010			2009
Future cash inflows	$	5,032,915		$	4,833,030		$	4,178,449
Future production costs		(1,374,658	)		(1,388,857	)		(1,300,235	)
Future development costs		(1,091,100	)		(879,193	)		(888,493	)
Future net cash flows before income tax		2,567,157			2,564,980			1,989,721
Future income tax expense		(665,751	)		(687,928	)		(491,832	)
Future net cash flows		1,901,406			1,877,052			1,497,889
10% annual discount for estimated timing of cash flows		(1,246,910	)		(1,235,633	)		(973,118	)
Standardized measure of discounted future net cash flows	$	654,496		$	641,419		$	524,771

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

	Year Ended December 31,
	2011			2010			2009
Sales of oil and gas, net of production costs	$	(234,211	)	$	(180,568	)	$	(157,891	)
Net changes in prices and production costs		(25,398	)		180,316			(314,209	)
Extensions, discoveries and other additions		361,284			59,729			138,482
Development costs incurred during the period		44,741			153,563			65,043
Revisions of previous quantity estimates		(113,188	)		(50,471	)		(158,844	)
Purchases of reserves-in-place		308			2,239			-
Sale of reserves-in-place		(37,474	)		(47,740	)		-
Accretion of discount		87,815			68,817			90,796
Net change in income taxes		16,818			(73,332	)		15,168
Other changes		(87,618	)		4,095			116,825
Net increase (decrease)		13,077			116,648			(204,630	)
Beginning of year		641,419			524,771			729,401
End of year	$	654,496		$	641,419		$	524,771

The standardized measure of discounted future net cash flows is not intended, and should not be interpreted, to represent the fair value of our oil and gas reserves. An estimate of the fair value would also consider, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and cost, and a discount factor more representative of economic conditions and risks inherent in reserve estimates. Accordingly, the changes in standardized measure reflected above do not necessarily represent the economic reality of such transactions. See “Costs Incurred in Certain Oil and Gas Activities” earlier in this Note and our Consolidated Statements of Cash Flows.