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,
	2012			2011			2010
Proved properties	$	240,217		$	277,987		$	293,486
Unproved properties	60,746			120,288			171,303
Wells, equipment and facilities	2,107,061			2,081,103			1,840,154
Support equipment	6,815			6,645			6,254
	2,414,839			2,486,023			2,311,197
Accumulated depreciation and depletion	(693,123		)	(710,948		)	(609,380		)
Net capitalized costs	$	1,721,716		$	1,775,075		$	1,701,817

ARO assets of $0.1 million, $0.2 million and $0.1 million were added to the cost basis of proved properties during the years ended December 31, 2012, 2011 and 2010, respectively.

Costs Incurred in Certain Oil and Gas Activities



	Year Ended December 31,
	2012		2011		2010
Proved property acquisition costs	$	—	$	—	$	5,671
Unproved property acquisition costs	27,775		47,877		133,185
Exploration costs	50,883		77,460		66,886
Development costs and other	305,693		320,263		244,092
Total costs incurred	$	384,351	$	445,600	$	449,834

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,
	2012			2011			2010
Revenues	$	310,484		$	300,046		$	251,336
Production expenses	56,096			65,835			63,854
Exploration expenses	34,092			78,943			49,641
Depreciation and depletion expense	204,849			160,293			130,816
Impairment of oil and gas properties	104,484			104,688			45,959
	(89,037		)	(109,713		)	(38,934		)
Income tax expense (benefit)	(34,724		)	(42,788		)	(15,184		)
Results of operations	$	(54,313	)	$	(66,925	)	$	(23,750	)

A combined total of depletion and accretion expense related to AROs of $0.5 million, $0.7 million and $0.7 million was recognized in DD&A expense during the years ended December 31, 2012, 2011 and 2010, respectively.

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, NGLs and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future prices for these commodities 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 reserve estimate by our independent third party engineers, Wright & Company, Inc. Our Manager of Engineering has over 27 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. Our 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 table on the following page sets forth our 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, NGL and natural gas reserves for the three years ended December 31, 2012 were estimated by Wright & Company, Inc. utilizing data compiled by us.



	Oil		NGLs		Natural Gas		Total Equivalents
Proved Developed and Undeveloped Reserves	(MBbl)		(MBbl)		(MMcf)		(MBOE)
December 31, 2009	11,517		14,870		776,665		155,831
Revisions of previous estimates ¹	(2,410	)	7,611		(71,421	)	(6,702	)
Extensions, discoveries and other additions ²	513		3,556		90,439		19,142
Production	(710	)	(671	)	(38,919	)	(7,867	)
Purchase of reserves	9		—		3,288		557
Sale of reserves in place	(837	)	(653	)	(15,070	)	(4,002	)
December 31, 2010	8,082		24,713		744,982		156,959
Revisions of previous estimates ³	(2,367	)	(3,047	)	(61,165	)	(15,608	)
Extensions, discoveries and other additions ⁴	9,669		732		56,345		19,792
Production	(1,283	)	(907	)	(33,410	)	(7,758	)
Purchase of reserves	20		—		1		20
Sale of reserves in place	(42	)	—		(36,840	)	(6,182	)
December 31, 2011	14,079		21,491		669,913		147,223
Revisions of previous estimates ⁵	(439	)	(2,495	)	(154,372	)	(28,662	)
Extensions, discoveries and other additions ⁶	13,444		2,578		13,405		18,255
Production	(2,252	)	(884	)	(20,261	)	(6,513	)
Purchase of reserves	39		1		6		41
Sale of reserves in place	(20	)	—		(101,172	)	(16,882	)
December 31, 2012	24,851		20,691		407,519		113,462
Proved Developed Reserves:
December 31, 2010	4,035		10,778		412,644		83,587
December 31, 2011	7,075		9,395		330,552		71,562
December 31, 2012	10,472		8,266		169,449		46,980
Proved Undeveloped Reserves:
December 31, 2010	4,047		13,935		332,338		73,372
December 31, 2011	7,004		12,096		339,361		75,661
December 31, 2012	14,379		12,425		238,070		66,482

We had downward revisions of 6.7 MMBOE primarily as a result of the following: 1) downward revisions of 7.5 MMBOE due to the removal of 200 proved undeveloped locations that would not be developed within five years, 2) upward revisions of 5.7 MMBOE as a result of processing the gas in the Mid-Continent Granite Wash for NGLs, 3) upward revisions of 2.0 MMBOE due to higher prices and 4) various downward revisions for 6.5 MMBOE across our assets as a result of well performance, lease expirations and interest changes.


²	We added 19.1 MMBOE due to the drilling of 16 wells on locations not classified as proved undeveloped locations in our 2010 year-end reserve report and the addition of 51 new proved undeveloped locations, primarily in East Texas, as a result of our 2011 drilling activities .

We had downward revisions of 15.6 MMBOE primarily as a result of the following: 1) downward revisions of 12.0 MMBOE 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 1.7 MMBOE due to lower condensate yield in the Granite Wash, 3) downward revisions of 1.5 MMBOE attributable to the elimination of proved undeveloped locations particularly in the Haynesville Shale in East Texas, 4) downward revisions of 0.8 MMBOE due to lower natural gas prices and 5) upward revisions of 0.5 MMBOE due to higher gas processing yields in the Haynesville Shale and Granite Wash .


⁴	We added 19.8 MMBOE due primarily to an increase of 9.0 MMBOE 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 10.8 MMBOE .

⁵

We had downward revisions of 28.7 MMBOE primarily as a result of the following: 1) downward revisions of 5.0 MMBOE due to well performance issues, interest changes and economic limits due to operating conditions, including lease operating expense and basis differentials, primarily in the Selma Chalk, the Granite Wash, the Cotton Valley, and the Haynesville and Marcellus Shales, 2) downward revisions of 15.0 MMBOE due to lower natural gas prices which significantly reduced the number of proved undeveloped locations in the Marcellus Shale and Selma Chalk and 3) downward revisions of 8.7 MMBOE due to the removal of 38 proved undeveloped locations that would not be developed within five years primarily in the Selma Chalk, the Cotton Valley and the Haynesville Shale.


⁶	We added 18.3 MMBOE due primarily to the drilling of 18 wells and the addition of 48 proved undeveloped locations in the Eagle Ford Shale.

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,
	2012			2011			2010
Future cash inflows	$	4,365,357		$	5,032,915		$	4,833,030
Future production costs	(1,206,478		)	(1,374,658		)	(1,388,857		)
Future development costs	(1,118,859		)	(1,091,100		)	(879,193		)
Future net cash flows before income tax	2,040,020			2,567,157			2,564,980
Future income tax expense	(548,132		)	(665,751		)	(687,928		)
Future net cash flows	1,491,888			1,901,406			1,877,052
10% annual discount for estimated timing of cash flows	(994,014		)	(1,246,910		)	(1,235,633		)
Standardized measure of discounted future net cash flows	$	497,874		$	654,496		$	641,419

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



	Year Ended December 31,
	2012			2011			2010
Sales of oil and gas, net of production costs	$	(254,388	)	$	(234,211	)	$	(180,568	)
Net changes in prices and production costs	(207,045		)	(25,398		)	180,316
Extensions, discoveries and other additions	355,495			361,284			59,729
Development costs incurred during the period	119,706			44,741			153,563
Revisions of previous quantity estimates	(196,152		)	(113,188		)	(50,471		)
Purchases of reserves-in-place	1,156			308			2,239
Sale of reserves-in-place	(116,151		)	(37,474		)	(47,740		)
Accretion of discount	87,441			87,815			68,817
Net change in income taxes	25,312			16,818			(73,332		)
Other changes	28,004			(87,618		)	4,095
Net increase (decrease)	(156,622		)	13,077			116,648
Beginning of year	654,496			641,419			524,771
End of year	$	497,874		$	654,496		$	641,419

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.