Note 14. Supplemental Oil and Natural Gas Disclosures (Unaudited)

Costs Incurred

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserve costs, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas, and the cost of improved recovery systems.

We capitalize interest on unevaluated oil and natural gas properties that have ongoing development activities. Included in costs incurred in the table below is capitalized interest of $36.5 million in 2012, $44.9 million in 2011 and $32.6 million in 2010. Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table below were $38.8 million in 2012, $24.2 million in 2011 and $45.1 million in 2010. See Note 3, Asset Retirement Obligations, for additional information.

Costs incurred in oil and natural gas activities were as follows:



	Year Ended December 31,
In thousands	2012		2011		2010
Property acquisitions:
Proved	$	491,041	$	86,465	$	3,373,450
Unevaluated	115,270		17,858		1,297,695
Exploration	12,019		31,483		8,728
Development	1,111,314		1,144,243		658,758
Total costs incurred ⁽¹⁾	$	1,729,644	$	1,280,049	$	5,338,631


(1)	Capitalized general and administrative costs that directly relate to exploration and development activities were $49.2 million, $35.0 million and $20.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:



	Year Ended December 31,
In thousands, except per BOE data	2012			2011			2010
Oil, natural gas, and related product sales	$	2,409,867		$	2,269,151		$	1,793,292
Lease operating costs	532,359			507,397			470,364
Marketing expenses	52,836			26,047			31,036
Taxes other than income	149,919			138,419			114,569
Depletion, depreciation and amortization	448,424			369,075			391,782
CO₂ properties and pipelines depletion and depreciation ⁽¹⁾	42,064			24,460			29,206
Commodity derivatives expense (income)	(4,834		)	(52,497		)	(21,414		)
Net operating income	1,189,099			1,256,250			777,749
Income tax provision	457,803			477,375			295,545
Results of operations from oil and natural gas producing activities	$	731,296		$	778,875		$	482,204

Depletion, depreciation and amortization per BOE	$	18.69		$	16.42		$	15.82


(1)	Represents an allocation of the depletion, depreciation and amortization of our CO₂ properties and pipelines associated with our tertiary oil producing activities.

Oil and Natural Gas Reserves

Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. See Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the effect of the different prices on reserve quantities and values. Operating costs, production and ad valorem taxes, and future development costs were based on current costs.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the applicable fiscal 12-month period. All of our reserves are located in the United States.

Estimated Quantities of Proved Reserves



	Year Ended December 31,
	2012						2011						2010
	Oil (MBbl)		Gas (MMcf)		Total (MBOE)		Oil (MBbl)		Gas (MMcf)		Total (MBOE)		Oil (MBbl)		Gas (MMcf)		Total (MBOE)
Balance at beginning of year	357,733		625,208		461,934		338,276		357,893		397,925		192,879		87,975		207,542
Revisions of previous estimates	(7,099	)	(16,720	)	(9,886	)	(4,478	)	(14,058	)	(6,821	)	3,538		16,171		6,233
Revisions due to price changes	(401	)	(37,969	)	(6,729	)	2,558		485		2,639		2,780		811		2,915
Extensions and discoveries	14,910		10,005		16,579		42,936		52,339		51,658		26,313		130,245		48,021
Improved recovery ⁽¹⁾	69,543		—		69,543		264		—		264		30,173		—		30,173
Production	(24,462	)	(10,654	)	(26,238	)	(22,169	)	(10,783	)	(23,966	)	(21,870	)	(28,491	)	(26,619	)
Acquisition of minerals in place	24,677		20,598		28,110		346		239,332		40,235		155,021		622,984		258,852
Sales of minerals in place	(105,777	)	(108,827	)	(123,915	)	—		—		—		(50,558	)	(471,802	)	(129,192	)
Balance at end of year	329,124		481,641		409,398		357,733		625,208		461,934		338,276		357,893		397,925

Proved Developed Reserves:
Balance at beginning of year	239,741		125,970		260,736		219,077		110,516		237,496		116,192		69,513		127,778
Balance at end of year	236,009		64,191		246,708		239,741		125,970		260,736		219,077		110,516		237,496

(1)

Improved recovery reflects reserve additions which result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO₂ flooding. In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO₂ injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.

We added 114.2 MMBOE of estimated proved reserves during 2012, including tertiary reserves of 69.5 MMBbls, primarily at Hastings and Oyster Bayou fields, 25.9 MMBOE from the acquisition of interests in the Thompson, Webster and Hartzog Draw fields and 11.5 MMBOE from our Bakken area assets prior to their sale in the fourth quarter of 2012. These increases were offset by the disposition of 123.9 MMBOE of reserves associated with disposed properties, including our Bakken area assets, and non-core assets in the Gulf Coast region and Paradox Basin in Utah.

Acquisitions of minerals in place during 2011 were primarily related to the acquisition of the remaining interest in Riley Ridge. Extensions and discoveries primarily include proved undeveloped reserves and were added primarily through additional drilling in the Bakken.

Acquisitions of minerals in place during 2010 were primarily from the Encore Merger and the initial acquisition of interests at Riley Ridge. The sales of minerals in place during 2010 were primarily due to the sale of the non-strategic Encore properties and our ownership interests in ENP. Extensions and discoveries primarily include reserves added at our Bakken and Haynesville fields. We added 39.4 MMBbls of tertiary proved oil reserves during 2010, primarily initial proved tertiary oil reserves at Delhi Field, plus upward revisions to reserves in other tertiary floods.

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

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month 12-month average price to the estimated future production of year-end proved reserves. The product prices used in calculating these reserves have varied widely during the three-year period. These prices have a significant impact on both the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the reserves. The following representative oil and natural gas prices were used in the Standardized Measure. These prices were adjusted by field to arrive at the appropriate corporate net price.



	December 31,
	2012		2011		2010
Oil (NYMEX)	$	94.71	$	96.19	$	79.43
Natural Gas (Henry Hub)	2.85		4.16		4.40

Future cash inflows were reduced by estimated future production, development and abandonment costs based on current cost, with no escalation to determine pre-tax cash inflows. Our future net inflows do not include a reduction for cash previously expended on our capitalized CO₂ assets that will be consumed in the production of proved tertiary reserves. Future income taxes were computed by applying the statutory tax rate to the excess of net cash inflows over our tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.



	December 31,
In thousands	2012			2011			2010
Future cash inflows	$	34,779,549		$	38,165,122		$	26,698,819
Future production costs	(13,114,740		)	(12,570,015		)	(9,702,896		)
Future development costs	(2,034,174		)	(3,026,898		)	(1,912,457		)
Future income taxes	(6,672,857		)	(7,379,972		)	(4,700,023		)
Future net cash flows	12,957,778			15,188,237			10,383,443
10% annual discount for estimated timing of cash flows	(6,543,398		)	(8,180,632		)	(5,465,516		)
Standardized measure of discounted future net cash flows	$	6,414,380		$	7,007,605		$	4,917,927

The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:



	Year Ended December 31,
In thousands	2012			2011			2010
Beginning of year	$	7,007,605		$	4,917,927		$	2,457,385
Sales of oil and natural gas produced, net of production costs	(1,673,253		)	(1,597,288		)	(1,177,322		)
Net changes in sales prices	(584,526		)	4,646,086			2,062,181
Extensions and discoveries, less applicable future development and production costs	291,558			762,370			295,074
Improved recovery ⁽¹⁾	1,901,109			15,708			623,622
Previously estimated development costs incurred	376,199			354,228			193,947
Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production	(797,975		)	(1,673,283		)	(285,158		)
Accretion of discount	875,383			729,234			307,546
Acquisition of minerals in place	767,267			29,737			3,671,439
Sales of minerals in place	(1,805,309		)	—			(1,474,443		)
Net change in income taxes	56,322			(1,177,114		)	(1,756,344		)
End of year	$	6,414,380		$	7,007,605		$	4,917,927


(1)	Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO₂ flooding.