SUPPLEMENTAL OIL AND GAS DISCLOSURES

(UNAUDITED)

Our oil and gas operations are substantially located in the United States. We do have operations in Canada that are insignificant. The capitalized costs at year-end and costs incurred during the year were as follows:


	2011			2010			2009
	(In thousands)
Capitalized costs:
Proved properties	$	3,302,032		$	2,738,093		$	2,309,193
Unproved properties		185,632			175,065			140,129

		3,487,664			2,913,158			2,449,322
Accumulated depreciation, depletion, amortization and impairment		(1,724,312	)		(1,542,352	)		(1,424,559	)

Net capitalized costs	$	1,763,352		$	1,370,806		$	1,024,763

Cost incurred:
Unproved properties acquired	$	70,999		$	75,739		$	37,137
Proved properties acquired		50,013			50,000			3,722
Exploration		43,836			48,304			30,547
Development		391,862			279,903			154,579
Asset retirement obligation		23,345			9,924			4,565

Total costs incurred	$	580,055		$	463,870		$	230,550

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2011, by the year in which such costs were incurred:


	2011		2010		2009		2008 and Prior		Total
	(In thousands)
Undeveloped Leasehold Acquired	$	59,691	$	49,923	$	17,766	$	58,252	$	185,632

Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.

The results of operations for producing activities are as follows:


	2011			2010			2009
	(In thousands)
Revenues	$	504,739		$	392,229		$	352,572
Production costs		(115,400	)		(91,143	)		(75,214	)
Depreciation, depletion, amortization and impairment		(181,960	)		(117,793	)		(394,942	)

		207,379			183,293			(117,584	)
Income tax (expense) benefit		(80,048	)		(70,110	)		43,153

Results of operations for producing activities (excluding corporate overhead and financing costs)	$	127,331		$	113,183		$	(74,431	)

Estimated quantities of proved developed oil, liquids and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, liquids and natural gas reserves were as follows:


	Oil Bbls			Liquids Bbls			Natural Gas Mcf
	(In thousands)
2011:
Proved developed and undeveloped reserves:
Beginning of year		17,494			16,117			420,486
Revision of previous estimates ⁽¹⁾		374			2,112			(30,510	)
Extensions and discoveries		3,477			3,924			39,836
Infill reserves in existing proved fields		1,229			1,780			15,592
Purchases of minerals in place		192			393			40,835
Production		(2,511	)		(2,239	)		(44,104	)
Sales		0			0			0

End of Year		20,255			22,087			442,135

Proved developed reserves:
Beginning of year		12,773			12,088			346,928
End of year		15,618			16,649			372,311
Proved undeveloped reserves:
Beginning of year		4,721			4,029			73,558
End of year		4,637			5,438			69,824
2010:
Proved developed and undeveloped reserves:
Beginning of year		11,669			14,653			419,061
Revision of previous estimates ⁽¹⁾		434			(1,559	)		(25,007	)
Extensions and discoveries		3,473			878			31,328
Infill reserves in existing proved fields		2,152			3,482			34,128
Purchases of minerals in place		1,293			212			1,732
Production		(1,521	)		(1,549	)		(40,756	)
Sales		(6	)		0			0

End of Year		17,494			16,117			420,486

Proved developed reserves:
Beginning of year		9,183			11,538			338,217
End of year		12,773			12,088			346,928
Proved undeveloped reserves:
Beginning of year		2,486			3,115			80,844
End of year		4,721			4,029			73,558
2009:
Proved developed and undeveloped reserves:
Beginning of year		9,699			10,171			450,135
Revision of previous estimates ⁽¹⁾		459			2,793			(57,393	)
Extensions and discoveries		2,135			1,996			50,480
Infill reserves in existing proved fields ⁽²⁾		618			1,174			19,872
Purchases of minerals in place		44			7			30
Production		(1,286	)		(1,488	)		(44,063	)

End of Year		11,669			14,653			419,061

Proved developed reserves:
Beginning of year		7,508			8,638			355,824
End of year		9,183			11,538			338,217
Proved undeveloped reserves:
Beginning of year		2,191			1,533			94,311
End of year		2,486			3,115			80,844

(1)	Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

(2)	Previously included in 'Extensions, discoveries and other additions'.

Estimates of oil, NGLs and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.

The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year-end costs and statutory tax rates, adjusted for permanent differences that relate to existing proved oil, NGLs and natural gas reserves. SMOG as of December 31 is as follows:


	2011			2010			2009
	(In thousands)
Future cash flows	$	4,583,629		$	3,745,046		$	2,403,892
Future production costs		(1,277,856	)		(1,054,630	)		(777,725	)
Future development costs		(340,992	)		(303,152	)		(195,486	)
Future income tax expenses		(952,736	)		(799,260	)		(433,366	)

Future net cash flows		2,012,045			1,588,004			997,315
10% annual discount for estimated timing of cash flows		(924,136	)		(732,918	)		(450,980	)

Standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves	$	1,087,909		$	855,086		$	546,335

The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:


	2011			2010			2009
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(389,339	)	$	(301,086	)	$	(277,358	)
Net changes in prices and production costs		115,852			379,097			(145,839	)
Revisions in quantity estimates and changes in production timing		(38,336	)		(67,116	)		(54,327	)
Extensions, discoveries and improved recovery, less related costs		401,134			340,771			136,695
Changes in estimated future development costs		37,742			15,974			100,304
Previously estimated cost incurred during the period		45,327			45,327			16,301
Purchases of minerals in place		58,567			42,280			1,288
Sales of minerals in place		(29	)		(120	)		0
Accretion of discount		128,492			77,536			89,256
Net change in income taxes		(60,675	)		(200,815	)		39,062
Other—net		(65,912	)		(23,097	)		16,479

Net change		232,823			308,751			(78,139	)
Beginning of year		855,086			546,335			624,474

End of year	$	1,087,909		$	855,086		$	546,335

Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.

The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.

The December 31, 2011, future cash flows were computed by applying the unescalated 12-month average prices of $96.19 per barrel for oil, $61.78 per barrel for NGLs and $4.12 per Mcf for natural gas, adjusted for price differentials, relating to proved reserves and to the year-end quantities of those reserves. Prior to 2009, the price was based on the single-day period-end price. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.

Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs and natural gas reserves at the end of the year, based on continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs and natural gas reserves.

Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.