Capitalized Costs Relating to Oil and Gas Producing Activities
			United Kingdom		United States		Total
December 31, 2011:
	Proved	$	429,246	$	67,421	$	496,667
	Unproved		183,110		75,224		258,334
	Total capitalized costs		612,356		142,645		755,001

	Accumulated depreciation, depletion and amortization		(192,027)		(16,735)		(208,762)

	Net capitalized costs	$	420,329	$	125,910	$	546,239

December 31, 2010:
	Proved	$	346,915	$	42,659	$	389,574
	Unproved		85,019		76,412		161,431
	Total capitalized costs		431,934		119,071		551,005

	Accumulated depreciation, depletion and amortization		(182,158)		(6,058)		(188,216)

	Net capitalized costs	$	249,776	$	113,013	$	362,789

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
				United Kingdom		United States		Other		Total Continuing Operations		Discontinued Operations Norway (1)		Total
Year Ended December 31, 2011:
	Acquisition costs:
		Proved	$	2,595	$	-	$	-	$	2,595	$	-	$	2,595
		Unproved		46,107		2,840		-		48,947		-		48,947
	Exploration costs			51,820		75,880		-		127,700		-		127,700
	Development costs			79,898		10,560		-		90,458		-		90,458
Total costs incurred			$	180,420	$	89,280	$	-	$	269,700	$	-	$	269,700

Year Ended December 31, 2010:
	Acquisition costs:
		Proved	$	-	$	2,386	$	-	$	2,386	$	-	$	2,386
		Unproved		1,184		40,155		-		41,339		-		41,339
	Exploration costs			50,328		32,027		-		82,355		-		82,355
	Development costs			22,047		1,884		-		23,931		-		23,931
Total costs incurred			$	73,559	$	76,452	$	-	$	150,011	$	-	$	150,011

Year Ended December 31, 2009:
	Acquisition costs:
		Proved	$	7,589	$	8,999	$	-	$	16,588	$	-	$	16,588
		Unproved		1,450		14,091		23		15,564		-		15,564
	Exploration costs			49,937		17,757		(382)		67,312		4,776		72,088
	Development costs			11,443		-		-		11,443		5,067		16,510
Total costs incurred			$	70,419	$	40,847	$	(359)	$	110,907	$	9,843	$	120,750

Results of Operations for Oil and Gas Producing Activities
				United Kingdom		United States		Total Continuing Operations		Discontinued Operations - Norway (1)		Total
Year Ended December 31, 2011:
	Revenues		$	41,754	$	18,337	$	60,091	$	-	$	60,091
	Production expenses			8,622		9,046		17,668		-		17,668
	DD&A			14,312		10,713		25,025		-		25,025
	Impairment of oil and
		gas properties		-		65,706		65,706		-		65,706
	Income tax expense (benefit)			11,104		(23,495)		(12,391)		-		(12,391)
	Results of activities		$	7,716	$	(43,633)	$	(35,917)	$	-	$	(35,917)

Year Ended December 31, 2010:
	Revenues		$	60,501	$	11,174	$	71,675	$	-	$	71,675
	Production expenses			11,086		4,261		15,347		-		15,347
	DD&A			22,020		5,273		27,293		-		27,293
	Impairment of oil and
		gas properties		-		7,692		7,692		-		7,692
	Income tax expense (benefit)			13,698		(2,118)		11,580		-		11,580
	Results of activities		$	13,697	$	(3,934)	$	9,763	$	-	$	9,763

Year Ended December 31, 2009:
	Revenues		$	60,666	$	1,627	$	62,293	$	17,550	$	79,843
	Production expenses			16,911		865		17,776		5,536		23,312
	DD&A			31,915		817		32,732		4,595		37,327
	Impairment of oil and
		gas properties		31,332		12,597		43,929		-		43,929
	Income tax expense (benefit)			(9,746)		(4,428)		(14,174)		5,787		(8,387)
	Results of activities		$	(9,746)	$	(8,224)	$	(17,970)	$	1,632	$	(16,338)

Note 1: We completed the divestiture of our Norwegian subsidiary on May 14, 2009. The results of operations and financial position of this subsidiary are classified as discontinued operations for all periods presented.

Proved reserves are estimated quantities of oil, gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The reserve volumes presented are estimates only and should not be construed as being exact quantities. These reserves may or may not be recovered and may increase or decrease as a result of our future operations and changes in economic conditions. Our oil and gas reserves were audited by independent reserve engineers at December 31, 2011, 2010 and 2009.

In the fourth quarter of 2009, we adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves to the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2011, 2010 and 2009 have been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied retrospectively.

		United Kingdom	United States	Total Continuing Operations	Discontinued Operations - Norway (1)	Total
Proved Oil Reserves (MBbls):
	Proved reserves at January 1, 2009	2,131	18	2,149	1,406	3,555
	Production	(690)	(4)	(694)	(310)	(1,004)
	Purchases of reserves	-	2	2	-	2
	Sales of reserves in place	-	-	-	(1,107)	(1,107)
	Extensions and discoveries	1,209	3	1,212	-	1,212
	Revisions of previous estimates	698	(1)	697	11	708
	Proved reserves at December 31, 2009	3,348	18	3,366	-	3,366
	Production	(545)	(6)	(551)	-	(551)
	Extensions and discoveries	457	34	491	-	491
	Revisions of previous estimates	404	13	417	-	417
	Proved reserves at December 31, 2010	3,664	59	3,723	-	3,723
	Production	(373)	(7)	(380)	-	(380)
	Purchases of reserves	303	-	303	-	303
	Revisions of previous estimates	466	(11)	455	-	455
	Proved reserves at December 31, 2011	4,060	41	4,101	-	4,101

Proved Developed Oil Reserves (MBbls):
	At December 31, 2009	1,381	8	1,389	-	1,389
	At December 31, 2010	1,240	14	1,254	-	1,254
	At December 31, 2011	1,270	41	1,311	-	1,311

		United Kingdom	United States	Total Continuing Operations	Discontinued Operations - Norway (1)	Total
Proved Gas Reserves (MMcf):
	Proved reserves at January 1, 2009	27,130	690	27,820	4,977	32,797
	Production	(3,743)	(320)	(4,063)	(686)	(4,749)
	Purchases of reserves	-	10,037	10,037	-	10,037
	Sales of reserves in place	-	-	-	(4,241)	(4,241)
	Extensions and discoveries	52,895	6	52,901	-	52,901
	Revisions of previous estimates	2,034	371	2,405	(50)	2,355
	Proved reserves at December 31, 2009	78,316	10,784	89,100	-	89,100
	Production	(3,071)	(2,636)	(5,707)	-	(5,707)
	Purchases of reserves	-	2,657	2,657	-	2,657
	Sales of reserves in place	(51,522)	-	(51,522)	-	(51,522)
	Extensions and discoveries	26,692	24,181	50,873	-	50,873
	Revisions of previous estimates	5,762	(3,209)	2,553	-	2,553
	Proved reserves at December 31, 2010	56,177	31,777	87,954	-	87,954
	Production	(94)	(5,076)	(5,170)	-	(5,170)
	Purchases of reserves	90	-	90	-	90
	Extensions and discoveries	-	46,100	46,100	-	46,100
	Revisions of previous estimates	(5,450)	(11,823)	(17,273)	-	(17,273)
	Proved reserves at December 31, 2011	50,723	60,978	111,701	-	111,701

Proved Developed Gas Reserves (MMcf):
	At December 31, 2009	4,329	4,707	9,036	-	9,036
	At December 31, 2010	555	13,281	13,836	-	13,836
	At December 31, 2011	795	22,704	23,499	-	23,499

	United Kingdom	United States	Total Continuing Operations	Discontinued Operations - Norway	Total

Proved Reserves (MBOE):
Proved reserves at December 31, 2008	6,653	133	6,786	2,236	9,022
Production	(1,314)	(57)	(1,371)	(424)	(1,795)
Extensions and discoveries	10,025	4	10,029	-	10,029
Purchase of proved reserves, in place	-	1,675	1,675	-	1,675
Sales of reserves	-	-	-	(1,815)	(1,815)
Revisions of previous estimates	1,037	60	1,097	3	1,100
Proved reserves at December 31, 2009	16,401	1,815	18,216	-	18,216
Production	(1,057)	(445)	(1,502)	-	(1,502)
Extensions and discoveries	4,906	4,064	8,970	-	8,970
Purchase of proved reserves, in place	-	443	443	-	443
Sales of reserves	(8,587)	-	(8,587)	-	(8,587)
Revisions of previous estimates	1,364	(522)	842	-	842
Proved reserves at December 31, 2010	13,027	5,355	18,382	-	18,382
Production	(389)	(853)	(1,242)	-	(1,242)
Extensions and discoveries	-	7,683	7,683	-	7,683
Purchase of proved reserves, in place	318	-	318	-	318
Revisions of previous estimates	(442)	(1,981)	(2,423)	-	(2,423)

Proved reserves at December 31, 2011	12,514	10,204	22,718	-	22,718

Proved Developed Reserves (MBOE):
At December 31, 2009	2,103	792	2,895	-	2,895
At December 31, 2010	1,333	2,227	3,560	-	3,560
At December 31, 2011	1,402	3,825	5,227	-	5,227

Future cash inflows and future production and development costs are determined by applying average 12-month pricing for 2011, 2010 and 2009. Oil, gas and condensate prices are escalated only for fixed and determinable amounts under provisions in some contracts. Estimated future income taxes are computed using current statutory income tax rates where production occurs. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

At December 31, 2011 and 2010, the prices used to determine the estimates of future cash inflows were as follows:

Estimated future cash inflows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Income tax expense, both U.S. and foreign, is calculated by applying the existing statutory tax rates, including any known future changes, to the pretax net cash flows giving effect to any permanent differences and reduced by the applicable tax basis. The effect of tax credits is considered in determining the income tax expense.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment and the risks inherent in reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows
			United Kingdom		United States		Total
December 31, 2011:
	Future cash inflows	$	941,208	$	218,295	$	1,159,503
	Future production costs		(144,106)		(47,344)		(191,450)
	Future development costs		(306,628)		(64,757)		(371,385)
	Future income tax expense		(238,111)		-		(238,111)

	Future net cash flows (undiscounted)		252,363		106,194		358,557
	Annual discount of 10% for estimated timing		37,250		56,435		93,685

	Standardized measure of future net cash flows	$	215,113	$	49,759	$	264,872

December 31, 2010:
	Future cash inflows	$	704,073	$	129,007	$	833,080
	Future production costs		(101,660)		(26,110)		(127,770)
	Future development costs		(374,380)		(33,433)		(407,813)
	Future income tax expense		(72,870)		-		(72,870)

	Future net cash flows (undiscounted)		155,163		69,464		224,627
	Annual discount of 10% for estimated timing		81,613		31,717		113,330

	Standardized measure of future net cash flows	$	73,550	$	37,747	$	111,297

Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
		2011		2010		2009

Standardized measure, beginning of period	$	111,297	$	55,698	$	49,662
Net changes in prices and production costs		147,776		86,915		(30,155)
Future development costs incurred		76,721		21,112		16,511
Net changes in estimated futue development costs		(9,261)		(48,356)		(81,864)
Revisions of previous quantity estimates		(36,421)		16,375		22,318
Extensions and discoveries		68,452		110,059		128,090
Acretion of discount		18,801		2,630		8,139
Changes in income taxes, net		(136,157)		(35,306)		(1,054)
Sale of oil and gas produced, net of production costs		(44,556)		(56,327)		(56,531)
Purchased reserves		26,340		2,386		8,827
Sales of reserves in place		-		(48,310)		(11,514)
Change in production, timing and other		41,880		4,421		3,269

Standardized measure, end of period	$	264,872	$	111,297	$	55,698