Supplemental Information on Oil and Natural Gas Producing Activities

The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and natural gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and natural gas reserves.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):



	December 31,
	2012			2011			2010
Oil and natural gas properties
Proved	$	12,262,921		$	8,969,296		$	8,159,924
Unproved	865,863			689,393			547,953
Total oil and natural gas properties	13,128,784			9,658,689			8,707,877
Less accumulated depreciation, depletion and impairment	(5,231,182		)	(4,791,534		)	(4,483,736		)
Net oil and natural gas properties capitalized costs	$	7,897,602		$	4,867,155		$	4,224,141

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):



	Year Ended December 31,
	2012		2011		2010
Acquisitions of properties
Proved	$	1,761,556	$	58,190	$	1,346,303
Unproved	377,185		320,361		352,648
Exploration(1)	120,438		98,849		31,717
Development(2)	1,704,991		1,296,903		1,006,232
Total cost incurred	$	3,964,170	$	1,774,303	$	2,736,900

____________________


(1)	Includes seismic costs of $15.3 million, $4.9 million and $4.1 million for 2012, 2011 and 2010, respectively.


(2)	Includes loss on the construction of the Century Plant of $50.0 million, $25.0 million and $105.0 million for 2012, 2011 and 2010, respectively. See Note 12.

Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)

The Company’s results of operations from oil and natural gas producing activities for each of the years 2012, 2011 and 2010 are shown in the following table (in thousands):



	Year Ended December 31,
	2012			2011			2010
Revenues	$	1,759,282		$	1,226,794		$	774,763
Expenses
Production costs	524,364			368,946			267,033
Depreciation and depletion	568,029			317,246			265,914
Accretion of asset retirement obligations	28,996			9,368			9,421
Total expenses	1,121,389			695,560			542,368
Income before income taxes	637,893			531,234			232,395
Benefit of income taxes(1)	(437,595		)	(20,134		)	(405,413		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	1,075,488		$	551,368		$	637,808

____________________


(1)	Reflects the Company’s effective tax rate, including the partial valuation allowance release.

Oil and Natural Gas Reserve Quantities (Unaudited)

Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/ or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:


•	the quality and quantity of available data and the engineering and geological interpretation of that data;


•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;


•	the accuracy of mandated economic assumptions such as the future prices of oil and natural gas; and


•	the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

The table below represents the Company’s estimate of proved oil and natural gas reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of substantially all of the Company’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Netherland Sewell, DeGolyer and MacNaughton and Lee Keeling, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil and natural gas attributable to substantially all of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2012, 2011 and 2010. Netherland Sewell, DeGolyer and MacNaughton and Lee Keeling are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. Netherland Sewell and Lee Keeling prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2012. The remaining 2.4% of estimates of proved reserves was based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

2010 Activity. During 2010, the Company recognized additional proved oil reserves of 154.2 MMBbls, which were primarily attributable to the acquisition of reserves in place from Arena and extensions and discoveries associated with successful drilling in the Permian Basin and Mid-Continent areas. The addition of 867.9 Bcf of natural gas reserves are primarily attributable to the increase in natural gas prices used in the estimation of reserves as of December 31, 2010 compared to prices used in the estimation of reserves in the previous periods, with other natural gas reserves being added in connection with the acquisition of reserves in place from Arena and extensions and discoveries associated with successful drilling in the Permian Basin and Mid-Continent areas.

2011 Activity. During 2011, excluding asset sales, the Company recognized an overall net increase in its proved oil reserves of approximately 36.0 MMBbls, primarily due to additional reserves of 55.6 MMBbls from extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent and the Central Basin Platform in the Permian Basin, offset by 11.8 MMBbls of production during 2011. Additionally, the Company recognized an overall net increase of 68.6 Bcf in its proved natural gas reserve quantities primarily due to 299.8 Bcf attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent and the Central Basin Platform in the Permian Basin, offset by revisions of 164.8 Bcf, primarily due to lower natural gas prices, and production of 69.3 Bcf. Continued low natural gas prices could result in additional negative revisions to the Company’s natural gas reserves.

Sales of proved reserves during 2011 totaled 43.3 MMBbls of oil from the divestitures of certain Permian Basin properties and 476.2 Bcf of natural gas from the divestiture of the east Texas properties.

2012 Activity. During 2012, excluding asset sales, the Company recognized an overall net increase in its proved oil and NGL reserves of approximately 108.8 MMBbls, primarily due to additional reserves of 116.9 MMBbls from extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent area and the Central Basin Platform in the Permian Basin. These increases were slightly offset by revisions of (22.3) MMBbls due to well performance in the Mid-Continent and Permian Basin during 2012. Additionally, the Company recognized an overall net increase of 60.5 Bcf in its proved natural gas reserve quantities primarily due to 489.3 Bcf attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent and the Central Basin Platform in the Permian Basin. These increases were partially offset by revisions of 538.2 Bcf, primarily due to lower natural gas prices, and, to a lesser extent, due to well performance in the Mid-Continent and Permian Basin during 2012 and production of 93.5 Bcf. Continued low natural gas prices could result in additional negative revisions to the Company’s natural gas reserves.

Sales of proved reserves during 2012 totaled 23.6 MMBbls of oil, including NGLs, and 0.5 Bcf of natural gas from the divestiture of the Company’s tertiary recovery properties.

2013 Activity. The Company sold its Permian Properties in February 2013. Proved reserves were 198.9 MMBoe, 55% of which were proved developed reserves, for the Permian Properties at December 31, 2012. Estimated standardized measure of discounted cash flows for the Permian Properties, determined by allocating the Company's standardized measure of discounted cash flows to the Permian Properties based on the present value of discounted cash flows attributable to the Permian Properties relative to the Company's total present value of discounted cash flows was $2.5 billion. See Note 22 for additional information regarding the sale.

The summary below presents changes in the Company’s estimated reserves for 2010, 2011 and 2012.



	Oil		Natural Gas
	(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2009	105,349		680,075
Revisions of previous estimates	12,999		867,931
Acquisitions of new reserves	71,640		79,942
Extensions and discoveries	69,512		211,150
Sales of reserves in place	—		(207	)
Production	(7,386	)	(76,226	)
As of December 31, 2010	252,114		1,762,665
Revisions of previous estimates	(9,278	)	(164,845	)
Acquisitions of new reserves	1,533		2,906
Extensions and discoveries	55,577		299,848
Sales of reserves in place	(43,331	)	(476,212	)
Production	(11,830	)	(69,306	)
As of December 31, 2011(3)	244,785		1,355,056
Proved developed reserves
As of December 31, 2009	38,327		592,777
As of December 31, 2010	91,965		784,292
As of December 31, 2011	118,728		670,382
Proved undeveloped reserves
As of December 31, 2009	67,022		87,298
As of December 31, 2010	160,149		978,373
As of December 31, 2011	126,057		684,674



	Oil		NGLs		Natural Gas
	(MBbls)		(MBbls)(2)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2011(3)	214,450		30,335		1,355,056
Revisions of previous estimates	(37,394	)	15,098		(538,214	)
Acquisitions of new reserves	31,470		683		202,995
Extensions and discoveries	89,656		27,259		489,302
Sales of reserves in place	(20,269	)	(3,287	)	(548	)
Production	(15,868	)	(2,094	)	(93,549	)
As of December 31, 2012(3)	262,045		67,994		1,415,042
Proved developed reserves of December 31, 2012	136,605		33,785		896,701
Proved undeveloped reserves of December 31, 2012	125,440		34,209		518,341

____________________


(1)	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.


(2)	Prior to 2012, NGLs did not comprise a significant portion of total proved reserves and were included with oil reserves, which affects the comparability of estimated reserves for 2012, 2011 and 2010.


(3)	Proved reserves at December 31, 2012 and 2011, respectively, include approximately 17,340 MBbls and 17,018 MBbls of oil, 5,132 MBbls and 1,782 MBbls of NGLs and 94,543 MMcf and 45,500 MMcf of natural gas attributable to noncontrolling interests.

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas (“ASC Topic 932”). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:


•	the standardized measure includes the Company’s estimate of proved oil, natural gas and natural gas liquids reserves and projected future production volumes based upon economic conditions;


•	pricing is applied based upon 12-month average market prices at December 31, 2012, 2011 and 2010 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:



	At December 31,
	2012		2011		2010
Oil (per barrel)	$	91.65	$	85.77	$	66.93
Natural gas (per Mcf)	$	2.29	$	4.06	$	3.80


•	future development and production costs are determined based upon actual cost at year-end;


•	the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and


•	a discount factor of 10% per year is applied annually to the future net cash flows.

The summary below presents the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure in ASC Topic 932 (in thousands).



	At December 31,
	2012			2011			2010
Future cash inflows from production	$	29,482,544		$	26,494,942		$	23,564,771
Future production costs	(8,899,465		)	(7,392,104		)	(8,218,860		)
Future development costs(1)	(4,021,051		)	(2,977,993		)	(3,779,761		)
Future income tax expenses	(3,721,509		)	(4,043,953		)	(2,392,464		)
Undiscounted future net cash flows	12,840,519			12,080,892			9,173,686
10% annual discount	(7,000,151		)	(6,864,555		)	(5,490,171		)
Standardized measure of discounted future net cash flows(2)	$	5,840,368		$	5,216,337		$	3,683,515

____________________


(1)	Includes abandonment costs.


(2)	Includes approximately $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2012 and 2011, respectively.

The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):



Present value as of December 31, 2009	$	1,560,978
Changes during the year
Revenues less production and other costs	(507,730		)
Net changes in prices, production and other costs	967,967
Development costs incurred	366,539
Net changes in future development costs	(910,934		)
Extensions and discoveries	955,540
Revisions of previous quantity estimates	773,132
Accretion of discount	159,971
Net change in income taxes	(825,668		)
Purchases of reserves in-place	1,133,413
Sales of reserves in-place	(258		)
Timing differences and other(1)	10,565
Net change for the year	2,122,537
Present value as of December 31, 2010	3,683,515
Changes during the year
Revenues less production and other costs	(857,848		)
Net changes in prices, production and other costs	1,264,736
Development costs incurred	575,546
Net changes in future development costs	87,080
Extensions and discoveries	1,812,167
Revisions of previous quantity estimates	(345,965		)
Accretion of discount	455,501
Net change in income taxes	(833,841		)
Purchases of reserves in-place	44,934
Sales of reserves in-place	(558,257		)
Timing differences and other(1)	(111,231		)
Net change for the year	1,532,822
Present value as of December 31, 2011(2)	5,216,337
Changes during the year
Revenues less production and other costs	(1,234,918		)
Net changes in prices, production and other costs	(2,555,391		)
Development costs incurred	766,943
Net changes in future development costs	(45,397		)
Extensions and discoveries	2,092,423
Revisions of previous quantity estimates	(530,755		)
Accretion of discount	678,200
Net change in income taxes	11,433
Purchases of reserves in-place	1,708,301
Sales of reserves in-place	(410,415		)
Timing differences and other(1)	143,607
Net change for the year	624,031
Present value as of December 31, 2012(2)	$	5,840,368

____________________


(1)	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.


(2)	Includes approximately $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2012 and 2011, respectively.