Note 19 — Supplemental Oil and Gas Disclosures (Unaudited)

Accounting Rules Activities

We adopted the modernized oil and gas reserve requirements for our proved reserve estimates and the related reserve report at December 31, 2009. Generally, adoption of these new regulations had little effect on our estimates of reserves however, the rule requiring development of proved undeveloped reserves within five years has subsequently affected our proved reserve estimate and could significantly impact future estimates of our proved reserves (see "Proved Undeveloped Reserves" below).

Capitalized Costs

Aggregate amounts of capitalized costs relating to our oil and gas activities and the aggregate amount of related accumulated depletion, depreciation and amortization as of the dates indicated are presented below (in thousands):

		2011			2010

Unproved oil and gas properties	$	50,389		$	56,093
Proved oil and gas properties		2,524,304			2,691,802
Total oil and gas properties		2,574,693			2,747,895

Accumulated depletion, depreciation and amortization		(1,703,046	)		(1,673,740	)
Net capitalized costs	$	871,647		$	1,074,155

Included in the depreciable basis of our proved oil and gas properties is the estimate of our proportionate share of asset retirement obligations relating to these properties which are also reflected as asset retirement obligations in the accompanying consolidated balance sheets. At December 31, 2011 and 2010, our oil and gas asset retirement obligations totaled $254.4 million and $234.9 million, respectively.

Costs Incurred in Oil and Gas Producing Activities

The following table reflects the costs incurred in oil and gas property acquisition and development activities, including estimated asset retirement obligations, during the years indicated (in thousands):


	United States		United Kingdom		Total
Year Ended December 31, 2011—
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties		41		—		41
Total property acquisition costs		41		—		41

Exploration costs		2,513		—		2,513
Development costs(1)		126,196		—		126,196
Asset retirement cost		26,523		19,923		46,446
Total costs incurred	$	155,273	$	19,923	$	175,196

Year Ended December 31, 2010—
Property acquisition costs:
Proved properties	$	—	$	—	$	—
Unproved properties		364		—		364
Total property acquisition costs		364		—		364

Exploration costs		1,362		—		1,362
Development costs(1)		53,002		—		53,002
Asset retirement cost		18,814		6,542		25,356
Total costs incurred	$	73,542	$	6,542	$	80,084

Year Ended December 31, 2009—
Property acquisition costs:
Proved properties	$	56	$	—	$	56
Unproved properties		1,829		—		1,829
Total property acquisition costs		1,885		—		1,885
Exploration costs		39,225		—		39,225
Development costs(1)		71,489		—		71,489
Asset retirement cost		66,468		2,644		69,112
Total costs incurred	$	179,067	$	2,644	$	181,711

(1)	Development costs include costs incurred to obtain access to proved reserves to drill and equip development wells. Development costs also include costs of developmental dry holes.

Results of Operations for Oil and Gas Producing Activities

Amounts in thousands:


	United States			United Kingdom			Total

Year Ended December 31, 2011—
Revenues	$	696,607		$	—		$	696,607
Production (lifting) costs		176,269			3,974			180,243
Hurricane repair expense (Note 4)		(4,838	)		—			(4,838	)
Exploration expenses(2)		10,914			—			10,914
Depreciation, depletion, amortization and accretion		219,915			—			219,915
Proved property impairment charges and other (3)		113,439			19,967			133,406
Gain on sale or acquisition of oil and gas properties		(4,531	)		—			(4,531	)
Selling and administrative expenses		31,455			107			31,562
Pretax income (loss) from producing activities		153,984			(24,048	)		129,936
Income tax expense (benefit)		45,233			(9,375	)		35,858
Results of oil and gas producing activities(1)	$	108,751		$	(14,673	)	$	94,078

Year Ended December 31, 2010—
Revenues	$	425,369		$	—		$	425,369
Production (lifting) costs		131,156			4,529			135,685
Net hurricane costs (Note 4)		4,699			—			4,699
Exploration expenses(2)		8,276			—			8,276
Depreciation, depletion, amortization and accretion		235,243			47			235,290
Proved property impairment charges and other (3)		177,138			4,995			182,133
Gain on sale of oil and gas properties		(287	)		(5,959	)		(6,246	)
Gain on oil and gas derivative contracts		(1,088	)		—			(1,088	)
Selling and administrative expenses		26,714			112			26,826
Pretax loss from producing activities		(156,482	)		(3,724	)		(160,206	)
Income tax expense (benefit)		(62,526	)		(428	)		(62,954	)
Results of oil and gas producing activities(1)	$	(93,956	)	$	(3,296	)	$	(97,252	)

	United States			United Kingdom			Total
Year Ended December 31, 2009—
Revenues	$	384,375		$	963		$	385,338
Production (lifting) costs		117,565			2,271			119,836
Net hurricane costs (Note 4)		(23,332	)		—			(23,332	)
Exploration expenses(2)		24,383			—			24,383
Depreciation, depletion, amortization and accretion		167,812			1,444			169,256
Proved property impairment charges and other (3)		73,407			—			73,407
Gain on sale of oil and gas properties		(1,949	)		—			(1,949	)
Gain on oil and gas derivative contracts		(89,485	)		—			(89,485	)
Selling and administrative expenses		21,495			59			21,554
Pretax loss from producing activities		94,479			(2,811	)		91,668
Income tax expense (benefit)		24,280			(1,028	)		23,252
Results of oil and gas producing activities(1)	$	70,199		$	(1,783	)	$	68,416

(1)	Excludes net interest expense and other.

(2)	See Note 5 for additional information related to the components of our exploration costs, including impairment charges for expiring unproved leases.
(3)	Other amounts represent additional asset retirement expense recorded upon completion of a field's abandonment.

Estimated Quantities of Proved Oil and Gas Reserves

We employ full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. Our engineering reserve estimates were prepared based upon interpretation of production performance data and sub-surface information obtained from the drilling of existing wells. Our internal reservoir engineers and independent petroleum engineers analyze 100% of our significant United States oil and gas fields (65 fields as of December 31, 2011). We consider any field with discounted future net revenues of 1% or greater of the total discounted future net revenues of all our fields to be significant.

We engaged Huddleston & Co., Inc. ("Huddleston"), an independent reservoir engineering firm, to prepare a report to estimate our proved reserves. Huddleston prepared a report to estimate our proved reserves at December 31, 2011, 2010 and 2009. Their reserve report at December 31, 2011 is included as Exhibit 99.1 to this Annual Report.

The following table presents our net ownership interest in proved oil reserves (MBbls):


	United States			United Kingdom		Total

Total proved reserves at December 31, 2008		32,012			—		32,012
Revision of previous estimates		232			—		232
Production		(2,741	)		—		(2,741	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		(1	)		—		(1	)
Extensions and discoveries		225			—		225
Total proved reserves at December 31, 2009		29,727			—		29,727
Revision of previous estimates(1)		(1,555	)		—		(1,555	)
Production		(3,354	)		—		(3,354	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		—			—		—
Extensions and discoveries		—			—		—
Total proved reserves at December 31, 2010		24,818			—		24,818
Revision of previous estimates(2)		3,475			—		3,475
Production		(5,785	)		—		(5,785	)
Purchases of reserves in place		—			—		—
Sales of reserves in place		(205	)		—		(205	)
Extensions and discoveries		386			—		386
Total proved reserves at December 31, 2011		22,689			—		22,689

Total proved developed reserves as of :
December 31, 2008		12,809			—		12,809
December 31, 2009		14,850			—		14,850
December 31, 2010		11,796			—		11,796
December 31, 2011		12,754			—		12,754


(1)	Includes an approximate 1.8 MMBbls decrease as reflected in our independent petroleum engineer reserve report at June 30, 2010 resulting from a combination of factors, including well performance issues at certain of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest all or a portion of our oil and gas assets and the increasing uncertainties about future oil and gas operations in the Gulf of Mexico as a result of the oil spill from the Macondo well.

(2)	The positive revision reflects the better than expected production volumes primarily from our Phoenix field at Green Canyon Blocks 236, 237, 238 and 282 since it began production in October 2010.

The following table presents our net ownership interest in proved gas reserves, including natural gas liquids (MMcf):


	United States			United(1)Kingdom			Total

Total proved reserves at December 31, 2008		460,456			12,950			473,406
Revision of previous estimates (2)		(44,615	)		(755	)		(45,370	)
Production		(27,139	)		(195	)		(27,334	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(7,933	)		—			(7,933	)
Extensions and discoveries		6,546			—			6,546
Total proved reserves at December 31, 2009		387,315			12,000			399,315
Revision of previous estimates (3)		(132,954	)		(12,000	)		(144,954	)
Production		(27,097	)		—			(27,097	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		—			—			—
Extensions and discoveries		—			—			—
Total proved reserves at December 31, 2010		227,264			—			227,264
Revision of previous estimates(4)		(108,947	)		—			(108,947	)
Production		(17,458	)		—			(17,458	)
Purchases of reserves in place		—			—			—
Sales of reserves in place		(4,109	)		—			(4,109	)
Extensions and discoveries		271			—			271
Total proved reserves at December 31, 2011		97,021			—			97,021

Total proved developed reserves as of :
December 31, 2008		256,794			950			257,744
December 31, 2009		124,763			—			124,763
December 31, 2010		75,664			—			75,664
December 31, 2011		59,859			—			59,859

(1)	Reflects 50% ownership in the Camelot field's reserves in 2009 and 2008. In February 2010 we acquired the other 50% ownership interest in the Camelot field. We no longer have any development plans for the field and we intend to fully abandon the field in 2012 in accordance with the applicable regulations in the United Kingdom. See Note 5 for additional information regarding our Camelot field.

(2)	Includes a 38 Bcfe reduction of the proved reserves at Bushwood field reflecting certain reservoir issues for our Noonan Gas wells subsequent to their reestablishing sustained production in January 2009 and new geologic data collected throughout 2009.

(3)	Includes an approximate 131 Bcf decrease as reflected in our independent petroleum engineer reserve report at June 30, 2010 resulting from a combination of factors, including well performance issues at certain of our producing fields, most notably our Bushwood field at Garden Banks Blocks 462/463/506/507, as well as changes in the field economics of some of our other oil and gas properties. The changes in field economics primarily affected properties that were either close to the end of their production life or in which we had proved undeveloped reserves, which would have been required to be developed in the near term. The decision not to develop these properties in light of these economic changes was also driven by our desire to pursue potential alternatives to divest all or a portion of our oil and gas assets and the increasing uncertainties about future oil and gas operations in the Gulf of Mexico as a result of the oil spill from the Macondo well.

(4)	Decrease primarily represents a reclassification of estimate proved reserves to the probable reserve category following the receipt and interpretation of new seismic data. The field with the largest shift from the proved to probable reserve category was our Bushwood field, where we reclassified approximately 87 Bcf at December 31, 2011.

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

The following table reflects the standardized measure of discounted future net cash flows relating to our interest in proved oil and gas reserves (in thousands):


	United States			United(1)Kingdom			Total

As of December 31, 2011—
Future cash inflows	$	2,811,956		$	—		$	2,811,956
Future costs:
Production		(419,617	)		—			(419,617	)
Development and abandonment		(557,323	)		(27,300	)		(584,623	)
Future net cash flows before income taxes		1,835,016			(27,300	)		1,807,716
Future income tax expense		(477,630	)		—			(477,630	)
Future net cash flows		1,357,386			(27,300	)		1,330,086
Discount at 10% annual rate		(266,954	)		—			(266,954	)
Standardized measure of discounted future net cash flows	$	1,090,432		$	(27,300	)	$	1,063,132

As of December 31, 2010—
Future cash inflows	$	2,925,744		$	—		$	2,925,744
Future costs:
Production		(583,050	)		—			(583,050	)
Development and abandonment		(590,870	)		(12,200	)		(603,070	)
Future net cash flows before income taxes		1,751,824			(12,200	)		1,739,624
Future income tax expense		(430,153	)		—			(430,153	)
Future net cash flows		1,321,671			(12,200	)		1,309,471
Discount at 10% annual rate		(318,404	)		—			(318,404	)
Standardized measure of discounted future net cash flows	$	1,003,267		$	(12,200	)	$	991,067

As of December 31, 2009—
Future cash inflows	$	3,166,306		$	60,840		$	3,227,146
Future costs:
Production		(618,391	)		(19,075	)		(637,466	)
Development and abandonment		(755,726	)		(33,807	)		(789,533	)
Future net cash flows before income taxes		1,792,189			7,958			1,800,147
Future income tax expense		(417,042	)		(1,560	)		(418,602	)
Future net cash flows		1,375,147			6,398			1,381,545
Discount at 10% annual rate		(387,036	)		(3,449	)		(390,485	)
Standardized measure of discounted future net cash flows	$	988,111		$	2,949		$	991,060

(1)	Reflects 50% ownership in the Camelot field's reserves in 2009. In February 2010 we acquired the other 50% ownership interest in the Camelot field (Note 5).

Future cash inflows are computed by applying the appropriate average twelve month commodity prices as based on the price of oil and natural gas on the first day of each month during the year, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of our derivative instruments. See the following table for base prices used in determining the standardized measure:


	United States		United Kingdom		Total

Year Ended December 31, 2011—
Oil price per Bbl	$	105.35	$	—	$	105.35
Natural gas prices per Mcf	$	4.34	$	—	$	4.34

Year Ended December 31, 2010—
Oil price per Bbl	$	77.55	$	—	$	77.55
Natural gas prices per Mcf	$	4.40	$	—	$	4.40

Year Ended December 31, 2009—
Oil price per Bbl	$	58.05	$	—	$	58.05
Natural gas prices per Mcf	$	3.72	$	5.07	$	3.76

The future income tax expense was computed by applying the appropriate year-end statutory rates, with consideration of future tax rates already legislated, to the future pretax net cash flows less the tax basis of the associated properties. Future net cash flows are discounted at the prescribed rate of 10%. We caution that actual future net cash flows may vary considerably from these estimates. Although our estimates of total proved reserves, development costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those assumed. Therefore, such estimated future net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to our proved oil and gas reserves are as follows (in thousands):


		Year Ended December 31,
		2011			2010			2009

Standardized measure, beginning of year	$	991,067		$	991,060		$	1,312,155
Changes during the year:
Sales, net of production costs		(516,895	)		(294,212	)		(265,501	)
Net change in prices and production costs		414,426			577,687			(245,883	)
Changes in future development costs		(108,007	)		84,907			(16,905	)
Development costs incurred		168,005			55,646			74,133
Accretion of discount		131,464			129,083			161,254
Net change in income taxes		(54,613	)		(41,115	)		257,919
Purchases of reserves in place		—			—			—
Extensions and discoveries		29,479			—			10,457
Sales of reserves in place		(14,324	)		—			(30,124	)
Net change due to revision in quantity estimates		(186,197	)		(422,987	)		(85,450	)
Changes in production rates (timing) and other		208,727			(89,002	)		(180,995	)
Total		72,065			7			(321,095	)
Standardized measure, end of year	$	1,063,132		$	991,067		$	991,060