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, 2011 are as follows:



	Oil (MBbls)(1)		Natural Gas (MMcf)		Total (MBoe)
Balance at January 1, 2009	51,283		372,366		113,344
Purchase of minerals in place	595		336		651
Sales of minerals in place	(33	)	(18	)	(36	)
Extensions and discoveries	6,671		49,446		14,912
Revisions (2)	32,328		(87,990	)	17,663
Improved recoveries	2,499		2,874		2,978
Production	(3,874	)	(22,584	)	(7,638	)
Balance at December 31, 2009	89,469		314,430		141,874
Purchase of minerals in place	1,352		17,166		4,213
Sales of minerals in place	—		(6	)	(1	)
Extensions and discoveries	4,767		37,914		11,086
Revisions	(2,694	)	(10,542	)	(4,451	)
Improved recoveries	4,611		—		4,611
Production	(4,093	)	(23,742	)	(8,050	)
Balance at December 31, 2010	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

Proved developed reserves:
January 1, 2009	40,382		263,331		84,271
December 31, 2009	55,861		228,006		93,862
December 31, 2010	55,607		257,754		98,566
December 31, 2011	62,450		226,008		100,118
Proved undeveloped reserves:
January 1, 2009	10,901		109,035		29,073
December 31, 2009	33,608		86,424		48,012
December 31, 2010	37,805		77,466		50,716
December 31, 2011	37,930		109,272		56,142

________________


(1)	Includes natural gas liquids.


(2)	The upward revision in our oil reserves during 2009 was primarily due to an increase in price from $44.60 as of December 31, 2008 to $61.18 as of December 31, 2009. The downward revision in our natural gas reserves during 2009 was primarily due to a decrease in price from $5.62 as of December 31, 2008 to $3.87 as of December 31, 2009.

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.

For 2011, 2010, and 2009, future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil and natural gas, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows for 2008 were estimated by applying the year-end price for oil and natural gas, 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 hedge positions (see Note 5, “Derivative activities and fair value measurements”). 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,
	2011			2010			2009
Future cash flows	$	10,737,829		$	8,614,519		$	6,376,198
Future production costs	(4,061,713		)	(3,448,904		)	(2,561,177		)
Future development and abandonment costs	(1,202,438		)	(1,054,771		)	(734,611		)
Future income tax provisions	(1,653,666		)	(1,211,143		)	(792,160		)
Net future cash flows	3,820,012			2,899,701			2,288,250
Less effect of 10% discount factor	(2,222,100		)	(1,663,675		)	(1,316,886		)
Standardized measure of discounted future net cash flows	$	1,597,912		$	1,236,026		$	971,364

Future cash flows as shown above were reported without consideration for the effects of cash flow hedges outstanding at each period end. Based on SEC prices used in determining future net revenues, if the effects of cash flow hedges were included in the computation, then future cash flows would have increased by $28,156 in 2009. We discontinued the use of hedge accounting effective April 1, 2010.

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,
	2011			2010			2009
Beginning of year	$	1,236,026		$	971,364		$	755,013
Sale of oil and natural gas produced, net of production costs	(374,300		)	(275,939		)	(177,891		)
Net changes in prices and production costs	538,466			512,006			369,851
Extensions and discoveries	224,027			166,330			126,235
Improved recoveries	17,969			69,181			25,212
Changes in future development costs	(238,881		)	(236,031		)	(253,459		)
Development costs incurred during the period that reduced future development costs	166,161			84,327			62,960
Revisions of previous quantity estimates	77,588			(66,781		)	149,494
Purchases and sales of reserves in place, net	(40,662		)	63,205			4,956
Accretion of discount	169,679			124,480			88,440
Net change in income taxes	(177,142		)	(181,858		)	(174,544		)
Changes in production rates and other	(1,019		)	5,742			(4,903		)
End of year	$	1,597,912		$	1,236,026		$	971,364

The following prices before field differentials were used in determining future net revenues related to the standardized measure calculation:



	2011		2010		2009
Oil (per Bbl)	$	96.19	$	79.43	$	61.18
Natural gas (per Mcf)	$	4.11	$	4.38	$	3.87