Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited) [Abstract]

Results of operations exclude general office overhead and interest expense attributable to oil and gas activities

	United States			Canada			Colombia			Total
	(in thousands)
Results of Operations
For the year ended December 31, 2011:
Consolidated Subsidiaries
Revenue	$	25,684		$	7,046		$	12,378		$	45,108
Production costs		12,682			27,432	(3)		3,704			43,818
Exploration expenses		23,768			3,324			122			27,214
Depreciation and depletion		22,350			104			949			23,403
Impairment of oil and gas properties		71,392			183,654						255,046
Loss (gain) on dispositions		(6,642	)		—			(39,599	)		(46,241	)
Related income tax expense (benefit)		(38,707	)		(54,979	)		15,577			(78,109	)
Results of producing activities for consolidated subsidiaries	$	(59,159	)	$	(152,489	)	$	31,625		$	(180,023	)
Equity Companies(1)
Revenue	$	98,933		$	1,335		$	26,730		$	126,998
Production costs		27,790			4,600			10,598			42,988
Depreciation and depletion		39,564			1,032			9,806			50,402
Impairment of oil and gas properties		15,624			—			—			15,624
Realized loss (gain) on derivative instruments		(33,969	)		(84	)		—			(34,053	)
Loss (gain) on acquisitions/dispositions		(49,484	)		—			(95,301	)		(144,785	)
Related income tax expense (benefit)(2)		—			—			6,055			6,055
Results of producing activities for equity companies	$	99,408		$	(4,213	)	$	95,572		$	190,767
Total results of operations	$	40,249		$	(156,702	)	$	127,197		$	10,744
For the year ended December 31, 2010:
Consolidated Subsidiaries
Revenue	$	19,180		$	11,276		$	16,619		$	47,075
Production costs		8,510			7,965			7,918			24,393
Exploration expenses		—			—			39,047			39,047
Depreciation and depletion		20,092			5,424			3,737			29,253
Impairment of oil and gas properties		110,165			—			—			110,165
Related income tax expense (benefit)		(15,856	)		(3,078	)		610			(18,324	)
Results of producing activities for consolidated subsidiaries	$	(103,731	)	$	965		$	(34,693	)	$	(137,459	)
Equity Companies(1)
Revenue	$	64,736		$	6,038		$	20,176		$	90,950
Production costs		18,460			9,036			9,174			36,670
Depreciation and depletion		24,221			6,033			7,058			37,312
Impairment of oil and gas properties		851			—			—			851
Realized gain on derivative instruments		(25,424	)		(2,543	)		—			(27,967	)
Related income tax expense (benefit)(2)		—			—			—			—
Results of producing activities for equity companies	$	46,628		$	(6,488	)	$	3,944		$	44,084
Total results of operations	$	(57,103	)	$	(5,523	)	$	(30,749	)	$	(93,375	)

(1) Represents our proportionate share of interests in our equity companies.

(2) Equity companies are pass-through entities for tax purposes.

(3) Includes $24.2 million of transportation costs from pipeline commitments.

Capitalized costs

	United States			Canada			Colombia			Total
	(in thousands)
Capitalized Costs
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	587,385		$	101,402		$	—		$	688,787
Property acquisition costs, unproved		101,611			92,750			23,767			218,128
Total acquisition costs		688,996			194,152			23,767			906,915
Accumulated depreciation and depletion		(539,380	)		(28,838	)		(741	)		(568,959	)
Net capitalized costs for consolidated subsidiaries	$	149,616		$	165,314		$	23,026		$	337,956
Equity Companies(1)
Property acquisition costs, proved	$	1,141,393		$	—		$	—		$	1,141,393
Property acquisition costs, unproved		103,657			—			—			103,657
Total acquisition costs		1,245,050			—			—			1,245,050
Accumulated depreciation and depletion		(512,503	)		—			—			(512,503	)
Net capitalized costs for equity companies	$	732,547		$	—		$	—		$	732,547
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	480,618		$	62,109		$	57,251		$	599,978
Property acquisition costs, unproved		136,625			89,785			1,174			227,584
Total acquisition costs		617,243			151,894			58,425			827,562
Accumulated depreciation and depletion		(463,330	)		(7,344	)		(3,782	)		(474,456	)
Net capitalized costs for consolidated subsidiaries	$	153,913		$	144,550		$	54,643		$	353,106
Equity Companies(1)
Property acquisition costs, proved	$	749,515		$	78,224		$	98,629		$	926,368
Property acquisition costs, unproved		108,541			28,884			883			138,308
Total acquisition costs		858,056			107,108			99,512			1,064,676
Accumulated depreciation and depletion		(460,622	)		(72,338	)		(31,825	)		(564,785	)
Net capitalized costs for equity companies	$	397,434		$	34,770		$	67,687		$	499,891

(1) Represents our proportionate share of interests in our equity companies.

Costs incurred in property acquisitions, exploration development activities

	United States		Canada		Colombia			Total
	(in thousands)
Costs incurred in property acquisitions, exploration and development activities
For the year ended December 31, 2011:
Consolidated Subsidiaries
Property acquisition costs, proved	$	23,051	$	7,748	$	—		$	30,799
Property acquisition costs, unproved		37,272		26,099		—			63,371
Exploration costs		49,156		—		122			49,278
Development costs		43,780		184		19,605			63,569
Asset retirement costs		496		750		254			1,500
Total costs incurred for consolidated subsidiaries	$	153,755	$	34,781	$	19,981		$	208,517
Equity Companies(1)
Property acquisition costs, proved	$	232,410	$	—	$	—		$	232,410
Property acquisition costs, unproved		14,268		—		4,395			18,663
Exploration costs		252		—		—			252
Development costs		136,711		—		—			136,711
Asset retirement costs		2,834		—		—			2,834
Total costs incurred for equity companies	$	386,475	$	—	$	4,395		$	390,870
For the year ended December 31, 2010:
Consolidated Subsidiaries
Property acquisition costs, proved	$	25,080	$	—	$	—		$	25,080
Property acquisition costs, unproved		25,202		—		1,000			26,202
Exploration costs		8,199		—		33,599			41,798
Development costs		19,118		3,876		—			22,994
Asset retirement costs		—		—		770			770
Total costs incurred for consolidated subsidiaries	$	77,599	$	3,876	$	35,369		$	116,844
Equity Companies(1)
Property acquisition costs, proved	$	29,975	$	—	$	—		$	29,975
Property acquisition costs, unproved		34,207		—		—			34,207
Exploration costs		108		—		29,927			30,035
Development costs		118,828		1,056		11,805			131,689
Asset retirement costs		296		—		(104	)		192
Total costs incurred for equity companies	$	183,414	$	1,056	$	41,628		$	226,098

(1) Represents our proportionate share of interests in equity companies.

Net Proved Reserves

	United States						Canada					Colombia					Total
Reserves	Liquids (MMBbls)			Natural Gas (Bcf)			Liquids (MMBbls)		Natural Gas (Bcf)			Liquids (MMBbls)			Natural Gas (Bcf)		Liquids (MMBbls)			Natural Gas (Bcf)
Net proved reserves of consolidated subsidiaries
January 1, 2011		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Revisions		0.1			(3.9	)		—		0.9			—			—		0.1			(3.0	)
Extensions, additions and discoveries		1.6			4.0			—		—			—			—		1.6			4.0
Production		(0.2	)		(3.0	)		—		(2.1	)		(0.1	)		—		(0.3	)		(5.1	)
Purchases in place		—			—			—		3.9			—			—		—			3.9
Sales in place		(20.9	)(2)		—			—		—			(1.9	)		—		(22.8	)		—
December 31, 2011		1.8			16.9			—		8.2			—			—		1.8			25.1
January 1, 2010		0.4			29.6			—		5.0			0.9			—		1.3			34.6
Revisions		0.1			(11.7	)		—		3.6			(0.7	)		—		(0.6	)		(8.1	)
Extensions, additions and discoveries		—			5.0			—		—			2.0			—		2.0			5.0
Production		(0.1	)		(3.1	)		—		(3.1	)		(0.2	)		—		(0.3	)		(6.2	)
Purchases in place		20.8	(2)		—			—		—			—			—		20.8			—
Sales in place		—			—			—		—			—			—		—			—
December 31, 2010		21.2			19.8			—		5.5			2.0			—		23.2			25.3
Proportional interest in proved reserves of equity companies
January 1, 2011		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Revisions		(4.2	)		(359.0	)		—		—			—			—		(4.2	)		(359.0	)
Extensions, additions and discoveries		3.2			103.1			—		—			—			—		3.2			103.1
Production		(0.4	)		(18.6	)		—		(0.4	)		(0.3	)		—		(0.7	)		(19.0	)
Purchases in place		9.4			304.2	(3)		—		—			—			—		9.4			304.2
Sales in place		—			—			—		(4.8	)(4)		(1.6	)(5)		—		(1.6	)		(4.8	)
December 31, 2011		15.9			582.5			—		—			—			—		15.9			582.5
January 1, 2010		5.2			466.9			—		7.5			0.6			—		5.8			474.4
Revisions		1.5			(119.1	)		—		(0.8	)		0.5			—		2.0			(119.9	)
Extensions, additions and discoveries		0.6			108.5			—		—			1.3			—		1.9			108.5
Production		(0.2	)		(12.3	)		—		(1.5	)		(0.3	)		—		(0.5	)		(13.8	)
Purchases in place		0.8			109.8			—		—			—			—		0.8			109.8
Sales in place		—			(1.0	)		—		—			(0.2	)		—		(0.2	)		(1.0	)
December 31, 2010		7.9			552.8			—		5.2			1.9			—		9.8			558.0
Total proved reserves at December 31, 2009		5.6			496.5			—		12.5			1.5			—		7.1			509.0
Total proved reserves at December 31, 2010		29.1			572.6			—		10.7			3.9			—		33.0			583.3
Total proved reserves at December 31, 2011		17.7			599.4			—		8.2			—			—		17.7			607.6
Proved Developed Reserves at January 1, 2010
Consolidated subsidiaries		0.2			18.4			—		5.0			0.6			—		0.8			23.4
Equity companies(1)		1.8			106.6			—		7.5			0.5			—		2.3			114.1
Proved Developed Reserves at December 31, 2010
Consolidated subsidiaries		2.7			17.1			—		5.5			1.6			—		4.3			22.6
Equity companies(1)		3.0			147.1			—		5.2			0.5			—		3.5			152.3
Proved Developed Reserves at December 31, 2011
Consolidated subsidiaries		0.9			13.6			—		8.2			—			—		0.9			21.8
Equity companies(1)		6.3			256.4			—		—			—			—		6.3			256.4
Proved Undeveloped Reserves at January 1, 2010
Consolidated subsidiaries		0.2			11.2			—		—			0.3			—		0.5			11.2
Equity companies(1)		3.4			360.3			—		—			0.1			—		3.5			360.3
Proved Undeveloped Reserves at December 31, 2010
Consolidated subsidiaries		18.5			2.7			—		—			0.4			—		18.9			2.7
Equity companies(1)		4.9			405.7			—		—			1.4			—		6.3			405.7
Proved Undeveloped Reserves at December 31, 2011
Consolidated subsidiaries		0.9			3.3			—		—			—			—		0.9			3.3
Equity companies(1)		9.6			326.1			—		—			—			—		9.6			326.1

(1) Represents our proportionate share of interests in equity companies.

(2) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(3) Relates to acquisitions of properties with 360.4 Bcfe and drilling of non-proved properties of 122.2 Bcfe. In addition, negative revisions of 384 Bcfe were noted primarily resulting from proved undeveloped reserves being reclassified to non-proved status in accordance with the SEC five-year guidance for recording proved reserves.

(4) Relates to SMVP that was dissolved in June 2011, and of proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.

(5) Relates to the sale of Remora’s assets which resulted in a decrease in proved reserves of 9.5 Bcfe.

Standardized Measure of Discounted Future Cash Flows

	United States			Canada			Colombia			Total
	(in thousands)
Standardized Measure of Discounted Future Cash Flows
For the year ended December 31, 2011:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	225,141		$	20,906		$	—		$	246,047
Future production costs		(66,448	)		(5,761	)		—			(72,209	)
Future development costs		(45,505	)		(1,607	)		—			(47,112	)
Future income tax expense(2)		—			—			—			—
Future net cash inflows		113,188			13,538			—			126,726
Effect of discounting net cash flows at 10%		(55,886	)		(2,527	)		—			(58,413	)
Discounted future net cash flows	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Future cash flows from sales of oil and gas	$	3,347,348		$	—		$	—		$	3,347,348
Future production costs		(1,005,922	)		—			—			(1,005,922	)
Future development costs		(660,509	)		—			—			(660,509	)
Future income tax expense(3)		—			—			—			—
Future net cash inflows		1,680,917			—			—			1,680,917
Effect of discounting net cash flows at 10%		(1,098,854	)		—			—			(1,098,854	)
Discounted future net cash flows	$	582,063		$	—		$	—		$	582,063
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	639,365		$	11,011		$	—		$	650,376
For the year ended December 31, 2010:
Consolidated Subsidiaries
Future cash flows from sales of oil and gas	$	1,468,944		$	16,435		$	156,921		$	1,642,300
Future production costs		(481,487	)		(5,600	)		(83,556	)		(570,643	)
Future development costs		(152,309	)		(360	)		(16,216	)		(168,885	)
Future income tax expense(2)		(268,774	)		—			—			(268,774	)
Future net cash inflows		566,374			10,475			57,149			633,998
Effect of discounting net cash flows at 10%		(353,232	)		(2,046	)		(10,256	)		(365,534	)
Discounted future net cash flows	$	213,142		$	8,429		$	46,893		$	268,464
Equity Companies(1)
Future cash flows from sales of oil and gas	$	2,889,308		$	14,713		$	141,410		$	3,045,431
Future production costs		(752,792	)		(6,463	)		(56,837	)		(816,092	)
Future development costs		(850,053	)		(992	)		(12,307	)		(863,352	)
Future income tax expense (3)		—			—			—			—
Future net cash inflows		1,286,463			7,258			72,266			1,365,987
Effect of discounting net cash flows at 10%		(995,091	)		(1,477	)		(14,313	)		(1,010,881	)
Discounted future net cash flows	$	291,372		$	5,781		$	57,953		$	355,106
Total consolidated and equity interests in standardized measure of discounted future net cash flows	$	504,514		$	14,210		$	104,846		$	623,570

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

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

	United States			Canada			Colombia			Total
	(in thousands)
Change in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Consolidated Subsidiaries
Discounted future net cash flows as of December 31, 2009	$	38,345		$	6,527		$	11,741		$	56,613
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		8,037			—			45,072			53,109
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(10,670	)		(3,311	)		(8,701	)		(22,682	)
Development costs incurred during the year		8,359			—			—			8,359
Net change in prices and production costs		96,662			46			(2,555	)		94,153
Net change in future development costs		4,155			(192	)		285			4,248
Revisions of previous reserves estimates		(27,501	)		5,628			(7,093	)		(28,966	)
Purchases of reserves		196,613	(4)		—			—			196,613
Accretion of discount		3,562			496			1,030			5,088
Other		(17,357	)		(765	)		7,114			(11,008	)
Net change in income taxes(2)		(87,063	)		—			—			(87,063	)
Total change in the standardized measure for consolidated subsidiaries	$	174,797		$	1,902		$	35,152		$	211,851
Discounted future net cash flows as of December 31, 2010	$	213,142		$	8,429		$	46,893		$	268,464
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		32,838			—			—			32,838
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(14,247	)		(5,848	)		(8,674	)		(28,769	)
Development costs incurred during the year		360			—			—			360
Net change in prices and production costs		(15,274	)		1,221			—			(14,053	)
Net change in future development costs		775			—			—			775
Revisions of previous reserves estimates		(5,285	)		1,219			19,859			15,793
Purchases of reserves					4,557						4,557
Divestiture of reserves		(272,448	)(4)					(58,078	)(5)		(330,526	)
Accretion of discount		30,021			843						30,864
Other		356			590						946
Net change in income taxes(2)		87,064									87,064
Total change in the standardized measure for consolidated subsidiaries	$	(155,840	)	$	2,582		$	(46,893	)	$	(200,151	)
Discounted future net cash flows as of December 31, 2011	$	57,302		$	11,011		$	—		$	68,313
Equity Companies(1)
Discounted future net cash flows as of December 31, 2009	$	52,941		$	9,569		$	13,706		$	76,216
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		20,230			—			40,664			60,894
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(46,276	)		2,998			(11,002	)		(54,280	)
Development costs incurred during the year		69,207			—			—			69,207
Net change in prices and production costs		90,974			(5,205	)		3,032			88,801
Net change in future development costs		—			(374	)		(847	)		(1,221	)
Revisions of previous reserves estimates		76,723			(1,077	)		17,289			92,935
Purchases of reserves		5,453			—			—			5,453
Sales of reserves		(1,446	)		—			(5,418	)		(6,864	)
Accretion of discount		5,294			794			529			6,617
Other		18,272			(924	)		—			17,348
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	238,431		$	(3,788	)	$	44,247		$	278,890
Discounted future net cash flows as of December 31, 2010	$	291,372		$	5,781		$	57,953		$	355,106
Value of reserves added during the year due to extensions, discoveries and net purchases less related costs		83,692			—			—			83,692
Changes in value of previous-year reserves due to:
Sales of oil and gas produced, net of production costs		(71,143	)		3,245			(16,132	)		(84,030	)
Development costs incurred during the year		44,294			—			—			44,294
Net change in prices and production costs		(20,856	)		—			—			(20,856	)
Net change in future development costs		(51,098	)		—			—			(51,098	)
Revisions of previous reserves estimates		20,178			—			—			20,178
Purchases of reserves		262,719			—			—			262,719
Divestiture of reserves		—			(9,026	)(6)		(41,821	)(5)		(50,847	)
Sales of reserves		—			—			—			—
Accretion of discount		29,155			—			—			29,155
Other		(6,250	)		—			—			(6,250	)
Net change in income taxes(3)		—			—			—			—
Total change in the standardized measure for equity companies	$	290,691		$	(5,781	)	$	(57,953	)	$	226,957
Discounted future net cash flows as of December 31, 2011	$	582,063		$	—		$	—		$	582,063

(1) Represents our proportionate share of interests in equity companies.

(2) For Canada and Colombia, there are net operating loss carryforwards that are expected to offset any future taxable earnings.

(3) Equity companies are pass-through entities for tax purposes.

(4) On December 14, 2011, we sold our 25% working interest in the Cat Canyon and West Cat Canyon fields in Santa Barbara County, California. We received approximately $71.6 million in cash from the sale. During 2010, we purchased our 25% working interest and at December 31, 2010, proved reserves in Cat Canyon were estimated at 20.8 MMBbls.

(5) In April 2011, some of our wholly owned oil and gas assets in Colombia were sold. Remora completed sales of its oil and gas assets in Colombia, resulting in a decrease of proved reserves of 9.5 Bcfe, in the second quarter of 2011.

(6) In June 2011, SMVP that was dissolved in June 2011, resulting in a decrease in proved reserves of 4.8 Bcfe that was exchanged for our ownership interest.