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, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL 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,
	2014			2013			2012
Oil and natural gas properties
Proved	$	11,707,147		$	10,972,816		$	12,262,921
Unproved	290,596			531,606			865,863
Total oil and natural gas properties	11,997,743			11,504,422			13,128,784
Less accumulated depreciation, depletion and impairment	(6,359,149		)	(5,762,969		)	(5,231,182		)
Net oil and natural gas properties capitalized costs	$	5,638,594		$	5,741,453		$	7,897,602

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,
	2014		2013		2012
Acquisitions of properties
Proved	$	73,370	$	21,130	$	1,761,556
Unproved	123,649		100,242		377,185
Exploration(1)	41,070		82,775		120,438
Development(2)	1,288,395		1,131,269		1,704,991
Total cost incurred	$	1,526,484	$	1,335,416	$	3,964,170

____________________


(1)	Includes seismic costs of $10.8 million, $6.7 million and $15.3 million for 2014, 2013 and 2012, respectively.


(2)	Includes the Company’s share of Century Plant construction costs of $50.0 million for 2012. See Note 7.

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 2014, 2013 and 2012 are shown in the following table (in thousands):



	Year Ended December 31,
	2014			2013			2012
Revenues	$	1,420,879		$	1,820,278		$	1,759,282
Expenses
Production costs	377,819			548,719			524,364
Depreciation and depletion	434,295			567,732			568,029
Accretion of asset retirement obligations	9,092			36,777			28,996
Total expenses	821,206			1,153,228			1,121,389
Income before income taxes	599,673			667,050			637,893
Benefit of income taxes(1)	(3,933		)	(7,471		)	(437,595		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	603,606		$	674,521		$	1,075,488

____________________


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

Oil, Natural Gas and NGL Reserve Quantities (Unaudited)

Proved oil, natural gas and NGL reserves are those quantities, 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, natural gas and NGLs 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, natural gas and NGLs; 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, natural gas and NGL 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 the substantial majority 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.

Cawley, Gillespie & Associates, Inc., (“CG&A”), Netherland, Sewell & Associates, Inc. (“Netherland Sewell”) and Lee Keeling and Associates, Inc. (“Lee Keeling”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2014, 2013 and 2012. CG&A, Netherland Sewell, 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. CG&A and Netherland Sewell prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2014. The remaining 13.9% 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.

2012 Activity. During 2012, excluding asset sales, the Company recognized an overall net increase in its proved oil and NGL reserves of approximately 67.9 MMBbls and 40.9 MMBbls, respectively, primarily due to additional reserves 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 to proved oil reserves were slightly offset by downward 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 downward 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 MMBoe 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 3 for additional information regarding the sale. The Company recognized an increase of 119.2 MMBoe in total reserves primarily attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent.

2014 Activity. During 2014, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 37.6 MMBbls, 27.5 MMBbls, and 467.2 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Revisions of previous estimates decreased oil reserves by 18.7 MMBbls, primarily comprised of (i) approximately 9 MMBbls from Permian Basin proved undeveloped reserves, largely due to removal of drilling locations not expected to be drilled within a five year period, (ii) approximately 8 MMBbls from well performance in the Mid-Continent and (iii) approximately 2 MMBbls from acreage losses or revisions to well interest ownerships. These negative revisions were offset by positive revisions to NGL and gas reserves of 11.1 MMBbls and 167.6 Bcf, respectively, primarily from well performance in the Mid-Continent area. Acquisitions of reserves added 3.5 MMBoe.

Sales of proved reserves during 2014 totaled 55.5 MMBoe from the sale of the Gulf Properties.

The summary below presents changes in the Company’s estimated reserves for 2012, 2013 and 2014.



	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2011	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(2)	262,045		67,994		1,415,042
Revisions of previous estimates	(13,969	)	3,717		(53,432	)
Acquisitions of new reserves	43		13		363
Extensions and discoveries	40,570		18,686		359,918
Sales of reserves in place	(131,769	)	(29,067	)	(228,229	)
Production	(14,279	)	(2,291	)	(103,233	)
As of December 31, 2013(2)	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2)	126,031		91,786		1,788,233
Proved developed reserves
As of December 31, 2011	101,578		17,150		670,382
As of December 31, 2012	136,605		33,785		896,701
As of December 31, 2013	83,893		35,807		951,609
As of December 31, 2014	79,022		56,823		1,203,447
Proved undeveloped reserves
As of December 31, 2011	112,872		13,185		684,674
As of December 31, 2012	125,440		34,209		518,341
As of December 31, 2013	58,748		23,245		438,820
As of December 31, 2014	47,009		34,963		584,786

____________________


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


(2)	Includes proved reserves attributable to noncontrolling interests at December 31, 2014, 2013 and 2012 as shown in the table below:



	December 31,
	2014	2013	2012
Oil (MBbl)	11,027	13,569	17,340
NGL (MBbl)	4,761	4,737	5,132
Natural gas (MMcf)	70,833	69,693	94,543

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 NGL reserves and projected future production volumes based upon economic conditions;


•	pricing is applied based upon 12-month average market prices at December 31, 2014, 2013 and 2012 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,
	2014		2013		2012
Oil (per barrel)	$	91.65	$	95.67	$	91.65
NGL (per barrel)	$	32.79	$	31.40	$	32.64
Natural gas (per Mcf)	$	3.61	$	3.65	$	2.29


•	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, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).



	At December 31,
	2014			2013			2012
Future cash inflows from production	$	21,022,320		$	19,937,484		$	29,482,544
Future production costs	(6,499,366		)	(6,843,713		)	(8,899,465		)
Future development costs(1)	(1,810,201		)	(2,546,680		)	(4,021,051		)
Future income tax expenses	(3,223,740		)	(2,283,541		)	(3,721,509		)
Undiscounted future net cash flows	9,489,013			8,263,550			12,840,519
10% annual discount	(5,401,261		)	(4,245,939		)	(7,000,151		)
Standardized measure of discounted future net cash flows(2)	$	4,087,752		$	4,017,611		$	5,840,368

____________________


(1)	Includes abandonment costs.


(2)	Includes approximately $643.3 million, $781.6 million and $952.7 million attributable to noncontrolling interests at December 31, 2014, 2013 and 2012 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, 2011	$	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
Changes during the year
Revenues less production and other costs	(1,271,559		)
Net changes in prices, production and other costs	271,566
Development costs incurred	474,275
Net changes in future development costs	(207,729		)
Extensions and discoveries	1,406,102
Revisions of previous quantity estimates	(296,418		)
Accretion of discount	711,385
Net change in income taxes	477,328
Purchases of reserves in-place	1,628
Sales of reserves in-place	(3,172,187		)
Timing differences and other(1)	(217,148		)
Net change for the year	(1,822,757		)
Present value as of December 31, 2013(2)	4,017,611
Changes during the year
Revenues less production and other costs	(1,043,060		)
Net changes in prices, production and other costs	331,694
Development costs incurred	364,262
Net changes in future development costs	(341,183		)
Extensions and discoveries	1,785,963
Revisions of previous quantity estimates	(77,688		)
Accretion of discount	477,458
Net change in income taxes	(256,371		)
Purchases of reserves in-place	50,958
Sales of reserves in-place	(1,058,330		)
Timing differences and other(1)	(163,562		)
Net change for the year	70,141
Present value as of December 31, 2014(2)	$	4,087,752

____________________


(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 $643.3 million, $781.6 million and $952.7 million attributable to noncontrolling interests at December 31, 2014, 2013, and 2012 respectively.