15. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited)

At December 31, 2012, the Company’s oil and gas properties are located in the U.S. and U.K. North Sea. All information presented as "U.K." in this footnote relates to the U.K. North Sea discontinued operations. For additional information see “Note 3. Assets Held for Sale and Discontinued Operations.”

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:



	Year Ended December 31,
	2012		2011		2010
	(In thousands)
U.S.
Unproved property acquisition costs	$	139,344	$	108,212	$	126,783
Exploration costs	557,523		374,366		134,487
Development costs	25,756		19,769		62,952
Asset retirement obligations	2,401		3,369		1,031
Total costs incurred	$	725,024	$	505,716	$	325,253
U.K.
Unproved property acquisition costs	$	11,135	$	1,004	$	806
Exploration costs	—		—		—
Development costs	35,225		38,775		5,375
Asset retirement obligations	1,036		2,649		—
Total costs incurred	$	47,396	$	42,428	$	6,181
Total Worldwide
Unproved property acquisition costs	$	150,479	$	109,216	$	127,589
Exploration costs	557,523		374,366		134,487
Development costs	60,981		58,544		68,327
Asset retirement obligations	3,437		6,018		1,031
Total costs incurred	$	772,420	$	548,144	$	331,434

Costs incurred excludes capitalized interest on U.S. unproved properties of $24.8 million, $23.4 million, and $20.7 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Proved Oil and Gas Reserve Quantities

Proved reserves are generally those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include proved reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are generally proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and gas reserve quantities at December 31, 2012, 2011 and 2010, and the related discounted future net cash flows before income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company Petroleum Engineers. Such estimates have been prepared in accordance with guidelines established by the SEC.

The Company’s net proved oil and gas reserves and changes in net proved oil and gas reserves, which are located in the U.S. and U.K., are summarized below:



	Crude Oil, Condensate and Natural Gas Liquids (MBoe)
	U.S.		U.K.		Worldwide
Proved reserves:
January 1, 2010	14,803		—		14,803
Extensions and discoveries	10,961		5,263		16,224
Revisions of previous estimates	(2,102	)	—		(2,102	)
Production	(452	)	—		(452	)
December 31, 2010	23,210		5,263		28,473
Extensions and discoveries	17,404		—		17,404
Revisions of previous estimates	(71	)	174		103
Sales of reserves in place	(10,310	)	—		(10,310	)
Production	(1,011	)	—		(1,011	)
December 31, 2011	29,222		5,437		34,659
Extensions and discoveries	17,153		—		17,153
Revisions of previous estimates	2,500		(196	)	2,304
Sales of reserves in place	(1,250	)	—		(1,250	)
Production	(3,167	)	—		(3,167	)
December 31, 2012	44,458		5,241		49,699

Proved developed reserves:
December 31, 2010	7,387		—		7,387
December 31, 2011	7,989		2,719		10,708
December 31, 2012	14,295		5,241		19,536

Proved undeveloped reserves:
December 31, 2010	15,823		5,263		21,086
December 31, 2011	21,233		2,718		23,951
December 31, 2012	30,163		—		30,163

Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following:



2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation.
2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale and the Niobrara Formation; Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.
2010	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010.

Crude oil, condensate and natural gas liquids sales of reserves in place are primarily attributable to the following:



2011	Sales of properties to KKR during the second quarter and GAIL during the third quarter.



	Natural Gas (MMcf)
	U.S.		U.K.		Worldwide
Proved reserves:
January 1, 2010	513,047		—		513,047
Extensions and discoveries	240,347		4,684		245,031
Revisions of previous estimates	(54,132	)	—		(54,132	)
Production	(34,095	)	—		(34,095	)
December 31, 2010	665,167		4,684		669,851
Extensions and discoveries	221,544		—		221,544
Revisions of previous estimates	(41,990	)	154		(41,836	)
Sales of reserves in place	(82,884	)	—		(82,884	)
Production	(38,990	)	—		(38,990	)
December 31, 2011	722,847		4,838		727,685
Extensions and discoveries	72,916		—		72,916
Revisions of previous estimates	(20,996	)	(174	)	(21,170	)
Sales of reserves in place	(313,483	)	—		(313,483	)
Production	(37,612	)	—		(37,612	)
December 31, 2012	423,672		4,664		428,336

Proved developed reserves:
December 31, 2010	358,543		—		358,543
December 31, 2011	389,795		2,419		392,214
December 31, 2012	229,539		4,664		234,203

Proved undeveloped reserves:
December 31, 2010	306,624		4,684		311,308
December 31, 2011	333,052		2,419		335,471
December 31, 2012	194,134		—		194,134

Natural gas extensions and discoveries are primarily attributable to the following:



2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett Shale, Marcellus Shale, and Eagle Ford Shale.
2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett Shale, Marcellus Shale, and Eagle Ford Shale. Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.
2010	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett Shale and Eagle Ford Shale, as well as an increase in previously estimated proved undeveloped reserves based on operational performance; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010.

Natural gas revisions of previous estimates are primarily attributable to the following:



2012	Negative price revisions primarily in the Barnett Shale.
2011	Negative price revisions primarily in the Barnett Shale.
2010	Positive price revisions offset by negative quantity revisions due to a planned shift in future drilling priorities focusing more on drilling in the core of the Barnett Shale, which resulted in removing natural gas reserves previously classified as proved undeveloped in the Barnett Shale.

Natural gas sales of reserves in place are primarily attributable to the following:



2012	Sales of properties to Atlas during the second quarter and sale of Gulf Coast properties during the third quarter.
2011	Sales of properties to KKR during the second quarter and GAIL during the third quarter.

Standardized Measure

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



	U.S.			U.K.			Worldwide
	(In thousands)
2010
Future cash inflows	$	3,514,978		$	432,230		$	3,947,208
Future production costs	(952,148		)	(96,782		)	(1,048,930		)
Future development costs	(597,444		)	(78,439		)	(675,883		)
Future income taxes	(415,021		)	(128,618		)	(543,639		)
Future net cash flows	1,550,365			128,391			1,678,756
Less 10% annual discount to reflect timing of cash flows	(895,681		)	(34,289		)	(929,970		)
Standard measure of discounted future net cash flows	$	654,684		$	94,102		$	748,786
2011
Future cash inflows	$	4,834,725		$	617,667		$	5,452,392
Future production costs	(1,212,722		)	(95,229		)	(1,307,951		)
Future development costs	(1,163,377		)	(43,954		)	(1,207,331		)
Future income taxes	(477,824		)	(246,273		)	(724,097		)
Future net cash flows	1,980,802			232,211			2,213,013
Less 10% annual discount to reflect timing of cash flows	(1,124,339		)	(47,638		)	(1,171,977		)
Standard measure of discounted future net cash flows	$	856,463		$	184,573		$	1,041,036
2012
Future cash inflows	$	4,960,687		$	623,678		$	5,584,365
Future production costs	(1,009,850		)	(87,727		)	(1,097,577		)
Future development costs	(982,101		)	(11,194		)	(993,295		)
Future income taxes	(511,790		)	(252,493		)	(764,283		)
Future net cash flows	2,456,946			272,264			2,729,210
Less 10% annual discount to reflect timing of cash flows	(1,277,463		)	(33,352		)	(1,310,815		)
Standard measure of discounted future net cash flows	$	1,179,483		$	238,912		$	1,418,395

Reserve estimates and future cash flows are based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2012, 2011 and 2010 were $102.03, $95.28, and $74.39 per barrel, respectively, for crude oil and condensate, $32.12, $44.90 and $35.18 per barrel, respectively, for natural gas liquids, and $2.08, $3.24 and $3.50 per Mcf, respectively, for natural gas.

Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil and gas reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below:



	U.S.			U.K.			Worldwide
	(In thousands)
Standardized measure — January 1, 2010	$	382,093		$	—		$	382,093
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production	263,663			—			263,663
Net change in estimated future development costs	83			—			83
Net change due to revisions in quantity estimates	(25,451		)	—			(25,451		)
Accretion of discount	39,833			—			39,833
Changes in production rates (timing) and other	49,806			—			49,806
Total revisions	327,934			—			327,934
Net change due to extensions and discoveries, net of estimated future development and production costs	157,846			193,985			351,831
Net change due to sales of minerals in place	—			—			—
Sales of oil and gas produced, net of production costs	(115,800		)	—			(115,800		)
Previously estimated development costs incurred	43,940			—			43,940
Net change in income taxes	(141,329		)	(99,883		)	(241,212		)
Net change in standardized measure of discounted future net cash flows	272,591			94,102			366,693
Standardized measure — December 31, 2010	$	654,684		$	94,102		$	748,786
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production	134,952			128,525			263,477
Net change in estimated future development costs	(509		)	(4,144		)	(4,653		)
Net change due to revisions in quantity estimates	(64,860		)	13,078			(51,782		)
Accretion of discount	81,225			19,399			100,624
Changes in production rates (timing) and other	(78,199		)	(16,094		)	(94,293		)
Total revisions	72,609			140,764			213,373
Net change due to extensions and discoveries, net of estimated future development and production costs	508,558			—			508,558
Net change due to sales of minerals in place	(150,437		)	—			(150,437		)
Sales of oil and gas produced, net of production costs	(173,853		)	—			(173,853		)
Previously estimated development costs incurred	5,381			39,779			45,160
Net change in income taxes	(60,479		)	(90,072		)	(150,551		)
Net change in standardized measure of discounted future net cash flows	201,779			90,471			292,250
Standardized measure — December 31, 2011	$	856,463		$	184,573		$	1,041,036
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production	(55,249		)	49,719			(5,530		)
Net change in estimated future development costs	91,404			—			91,404
Net change due to revisions in quantity estimates	(77,919		)	(46,803		)	(124,722		)
Accretion of discount	107,451			37,453			144,904
Changes in production rates (timing) and other	(3,369		)	(6,061		)	(9,430		)
Total revisions	62,318			34,308			96,626
Net change due to extensions and discoveries, net of estimated future development and production costs	599,544			—			599,544
Net change due to sales of minerals in place	(212,910		)	—			(212,910		)
Sales of oil and gas produced, net of production costs	(313,354		)	—			(313,354		)
Previously estimated development costs incurred	202,187			32,760			234,947
Net change in income taxes	(14,765		)	(12,729		)	(27,494		)
Net change in standardized measure of discounted future net cash flows	323,020			54,339			377,359
Standardized measure — December 31, 2012	$	1,179,483		$	238,912		$	1,418,395