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

At December 31, 2013, the Company’s oil and gas properties are located in the U.S. At December 31, 2012 and 2011, the Company’s oil and gas properties were 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. Discontinued Operations.”

Costs Incurred

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



	Year Ended December 31,
	2013		2012		2011
	(In thousands)
U.S.
Unproved property acquisition costs	$	254,099	$	139,344	$	108,212
Exploration costs	106,329		211,289		270,688
Development costs	423,871		374,391		126,816
Total costs incurred	$	784,299	$	725,024	$	505,716
U.K.
Unproved property acquisition costs	$	—	$	11,135	$	1,004
Exploration costs	—		—		—
Development costs	—		36,261		41,424
Total costs incurred	$	—	$	47,396	$	42,428
Total Worldwide
Unproved property acquisition costs	$	254,099	$	150,479	$	109,216
Exploration costs	106,329		211,289		270,688
Development costs	423,871		410,652		168,240
Total costs incurred	$	784,299	$	772,420	$	548,144

Costs incurred excludes capitalized interest on U.S. unproved properties of $29.9 million, $24.8 million, and $23.4 million for the years ended December 31, 2013, 2012 and 2011, 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, 2013, and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott Company, L.P. Proved oil and gas reserve quantities at December 31, 2012 and 2011, and the related discounted future net cash flows before income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd., Ryder Scott Company, L.P., and Fairchild and Wells, Inc. 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 and Condensate (MBbls)						Natural Gas Liquids (MBbls)
	U.S.		U.K.		Worldwide		U.S.		U.K.	Worldwide
Proved reserves:
January 1, 2011	10,631		5,263		15,894		12,579		—	12,579
Extensions and discoveries	16,978		—		16,978		426		—	426
Revisions of previous estimates	103		174		277		(174	)	—	(174	)
Sales of reserves in place	(1,809	)	—		(1,809	)	(8,501	)	—	(8,501	)
Production	(802	)	—		(802	)	(209	)	—	(209	)
December 31, 2011	25,101		5,437		30,538		4,121		—	4,121
Extensions and discoveries	15,403		—		15,403		1,750		—	1,750
Revisions of previous estimates	1,760		(196	)	1,564		740		—	740
Sales of reserves in place	(327	)	—		(327	)	(923	)	—	(923	)
Production	(2,862	)	—		(2,862	)	(305	)	—	(305	)
December 31, 2012	39,075		5,241		44,316		5,383		—	5,383
Extensions and discoveries	27,295		—		27,295		2,992		—	2,992
Revisions of previous estimates	778		—		778		308		—	308
Sales of reserves in place	(876	)	(5,241	)	(6,117	)	—		—	—
Production	(4,231	)	—		(4,231	)	(531	)	—	(531	)
December 31, 2013	62,041		—		62,041		8,152		—	8,152

Proved developed reserves:
December 31, 2011	6,803		2,719		9,522		1,186		—	1,186
December 31, 2012	12,675		5,241		17,916		1,620		—	1,620
December 31, 2013	18,321		—		18,321		2,779		—	2,779

Proved undeveloped reserves:
December 31, 2011	18,298		2,718		21,016		2,935		—	2,935
December 31, 2012	26,400		—		26,400		3,763		—	3,763
December 31, 2013	43,720		—		43,720		5,373		—	5,373

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



2013	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.
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.

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



2013	Sales of U.K. North Sea properties to Iona Energy during the first quarter and sales of U.S. properties in East Texas in the third quarter.
2011	Sales of U.S. properties to KKR during the second quarter and GAIL during the third quarter.



	Natural Gas (MMcf)						Oil-Equivalent Proved Reserves (MBoe)
	U.S.		U.K.		Worldwide		U.S.		U.K.		Worldwide
Proved reserves:
January 1, 2011	665,167		4,684		669,851		134,071		6,044		140,115
Extensions and discoveries	221,544		—		221,544		54,328		—		54,328
Revisions of previous estimates	(41,990	)	154		(41,836	)	(7,069	)	199		(6,870	)
Sales of reserves in place	(82,884	)	—		(82,884	)	(24,124	)	—		(24,124	)
Production	(38,990	)	—		(38,990	)	(7,509	)	—		(7,509	)
December 31, 2011	722,847		4,838		727,685		149,697		6,243		155,940
Extensions and discoveries	72,916		—		72,916		29,305		—		29,305
Revisions of previous estimates	(20,996	)	(174	)	(21,170	)	(999	)	(225	)	(1,224	)
Sales of reserves in place	(313,483	)	—		(313,483	)	(53,497	)	—		(53,497	)
Production	(37,612	)	—		(37,612	)	(9,436	)	—		(9,436	)
December 31, 2012	423,672		4,664		428,336		115,070		6,018		121,088
Extensions and discoveries	73,360		—		73,360		42,514		—		42,514
Revisions of previous estimates	29,819		—		29,819		6,055		—		6,055
Sales of reserves in place	(307,472	)	(4,664	)	(312,136	)	(52,121	)	(6,018	)	(58,139	)
Production	(31,422	)	—		(31,422	)	(9,999	)	—		(9,999	)
December 31, 2013	187,957		—		187,957		101,519		—		101,519

Proved developed reserves:
December 31, 2011	389,795		2,419		392,214		72,955		3,122		76,077
December 31, 2012	229,539		4,664		234,203		52,552		6,018		58,570
December 31, 2013	106,976		—		106,976		38,929		—		38,929

Proved undeveloped reserves:
December 31, 2011	333,052		2,419		335,471		76,742		3,121		79,863
December 31, 2012	194,134		—		194,134		62,519		—		62,519
December 31, 2013	80,981		—		80,981		62,590		—		62,590

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



2013	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Marcellus and Eagle Ford.
2012	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford.
2011	Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett, Marcellus, and Eagle Ford. Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling.

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



2013	Positive price revisions in the U.S. primarily in the Barnett and Marcellus.
2012	Negative price revisions in the U.S. primarily in the Barnett.
2011	Negative price revisions in the U.S. primarily in the Barnett.

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



2013	Sale of U.S. properties in the Barnett Shale to EnerVest during the fourth quarter and U.K. properties to Iona during the first quarter.
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)
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
2013
Future cash inflows	$	6,936,276		$	—		$	6,936,276
Future production costs	(1,629,663		)	—			(1,629,663		)
Future development costs	(1,340,722		)	—			(1,340,722		)
Future income taxes	(835,840		)	—			(835,840		)
Future net cash flows	3,130,051			—			3,130,051
Less 10% annual discount to reflect timing of cash flows	(1,508,640		)	—			(1,508,640		)
Standard measure of discounted future net cash flows	$	1,621,411		$	—		$	1,621,411

Reserve estimates and future cash flows are based on the average realized prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2013, 2012 and 2011 were $99.44, $102.03, and $95.28 per barrel, respectively, for crude oil and condensate, $25.60, $32.12 and $44.90 per barrel, respectively, for natural gas liquids, and $2.97, $2.08 and $3.24 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 current 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, 2011	$	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
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production	(232,361		)	—			(232,361		)
Net change in estimated future development costs	(10,602		)	—			(10,602		)
Net change due to revisions in quantity estimates	205,686			—			205,686
Accretion of discount	141,229			44,160			185,389
Changes in production rates (timing) and other	56,052			(44,160		)	11,892
Total revisions	160,004			—			160,004
Net change due to extensions and discoveries, net of estimated future development and production costs	873,028			—			873,028
Net change due to sales of minerals in place	(191,155		)	(441,597		)	(632,752		)
Sales of oil and gas produced, net of production costs	(444,841		)	—			(444,841		)
Previously estimated development costs incurred	217,395			—			217,395
Net change in income taxes	(172,503		)	202,685			30,182
Net change in standardized measure of discounted future net cash flows	441,928			(238,912		)	203,016
Standardized measure — December 31, 2013	$	1,621,411		$	—		$	1,621,411