Disclosures about oil and natural gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum and geological engineers, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2013 are as follows:



	Oil (MBbls)(1)		Natural Gas (MMcf)		Total (MBoe)
Proved developed and undeveloped reserves
Balance at January 1, 2011	93,412		335,220		149,282
Purchase of minerals in place	241		822		378
Sales of minerals in place	(2,355	)	(7,134	)	(3,544	)
Extensions and discoveries	6,362		40,896		13,178
Revisions	6,711		(12,882	)	4,564
Improved recoveries	1,057		—		1,057
Production	(5,048	)	(21,642	)	(8,655	)
Balance at December 31, 2011	100,380		335,280		156,260
Purchase of minerals in place	—		57		9
Sales of minerals in place	(2,694	)	(6,608	)	(3,795	)
Extensions and discoveries	7,117		37,256		13,326
Revisions	3,410		(89,036	)	(11,429	)
Improved recoveries	842		—		842
Production	(5,812	)	(19,834	)	(9,118	)
Balance at December 31, 2012	103,243		257,115		146,095
Proved developed reserves:
January 1, 2011	55,607		257,754		98,566
December 31, 2011	62,450		226,008		100,118
December 31, 2012	63,956		185,826		94,927
Proved undeveloped reserves:
January 1, 2011	37,805		77,466		50,716
December 31, 2011	37,930		109,272		56,142
December 31, 2012	39,287		71,289		51,169

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(1)	Includes natural gas liquids.



	Oil (MBbls)		Natural gas (MMcf)		Natural Gas Liquids (MBbls)		Total (MBoe)
Proved developed and undeveloped reserves
As of January 1, 2013	92,047		257,115		11,195		146,095
Purchase of minerals in place	3,283		3,618		1,059		4,945
Sales of minerals in place	(5,174	)	(9,708	)	(324	)	(7,116	)
Extensions and discoveries	11,556		62,412		3,127		25,085
Revisions(1)	(7,772	)	9,735		1,479		(4,671	)
Improved recoveries	3,879		—		—		3,879
Production	(5,006	)	(20,250	)	(1,361	)	(9,742	)
Balance at December 31, 2013	92,813		302,922		15,175		158,475
Proved developed reserves at December 31, 2013	56,360		196,920		11,484		100,664
Proved undeveloped reserves at December 31, 2013	36,453		106,002		3,691		57,811

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(1)	The downward revision in our oil reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and to negative technical revisions. These downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.

The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

We believe that, in reviewing the information that follows, the following factors should be taken into account:


•	future costs and sales prices will probably differ from those required to be used in these calculations;


•	actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;


•	a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and


•	future net revenues may be subject to different rates of income taxation.

Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 6—Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:



	For the year ended December 31,
	2013			2012			2011
Future cash flows	$	10,660,532		$	9,690,171		$	10,737,829
Future production costs	(3,841,723		)	(3,737,069		)	(4,061,713		)
Future development and abandonment costs	(1,506,585		)	(1,172,786		)	(1,202,438		)
Future income tax provisions	(1,328,925		)	(1,223,036		)	(1,653,666		)
Net future cash flows	3,983,299			3,557,280			3,820,012
Less effect of 10% discount factor	(2,239,527		)	(2,033,599		)	(2,222,100		)
Standardized measure of discounted future net cash flows	$	1,743,772		$	1,523,681		$	1,597,912

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:



	For the year ended December 31,
	2013			2012			2011
Beginning of year	$	1,523,681		$	1,597,912		$	1,236,026
Sale of oil and natural gas produced, net of production costs	(418,224		)	(346,627		)	(374,300		)
Net changes in prices and production costs	172,975			(206,640		)	538,466
Extensions and discoveries	514,743			224,903			224,027
Improved recoveries	79,589			14,204			17,969
Changes in future development costs	(236,121		)	(18,184		)	(238,881		)
Development costs incurred during the period that reduced future development costs	110,354			118,502			166,161
Revisions of previous quantity estimates	(95,855		)	(192,894		)	77,588
Purchases and sales of reserves in place, net	(20,021		)	(54,070		)	(40,662		)
Accretion of discount	152,830			214,794			169,679
Net change in income taxes	(60,981		)	166,238			(177,142		)
Changes in production rates and other	20,802			5,543			(1,019		)
End of year	$	1,743,772		$	1,523,681		$	1,597,912

The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.



	2013		2012		2011
Oil (per Bbl)	$	96.78	$	94.71	$	96.19
Natural gas (per Mcf)	$	3.67	$	2.76	$	4.11
Natural gas liquids (per Bbl) (1)	$	32.53	$	—	$	—

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(1)	The NGL price is provided only for 2013 to coincide with our separate presentation of NGL reserves in that year.