Supplemental Information On Oil and Gas Exploration and Production Activities (unaudited)

12 Months Ended

Dec. 31, 2011

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

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

Note 24    Supplemental Information on Oil and Gas Exploration and Production Activities (unaudited)

The operations of our Oil and Gas operating segment focus on the exploration for and the acquisition, development and production of natural gas, oil and natural gas liquids in the United States, the Canadian provinces of Alberta and British Columbia, and Colombia.

Our Oil and Gas operating segment includes our wholly owned oil and gas assets and our unconsolidated oil and gas joint ventures. In December 2008, the SEC revised oil and gas reporting disclosures, which clarified that we should consider our equity-method investments when determining whether we have significant oil and gas activities beginning in 2009. A one-year deferral of the disclosure requirements was allowed if an entity became subject to the requirements because of the change to the definition of significant oil and gas activities. When operating results from our wholly owned oil and gas activities were considered with operating results from our unconsolidated oil and gas joint ventures, which we account for under the equity method of accounting, we determined that we had significant oil and gas activities under the new definition at December 31, 2009. Accordingly after the one-year deferral, we are presenting the information with regard to our oil and gas producing activities for the years ended December 31, 2011 and 2010.

The estimates of net proved oil and gas reserves as of December 31, 2011 were based on reserve reports prepared by independent petroleum engineers. AJM Deloitte prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Canada. Miller and Lents, Ltd. prepared reports of estimated proved oil and gas reserves for both our wholly owned assets and our U.S. joint venture’s interests in natural gas and oil properties located in the United States. Cawley, Gillespie & Associates, Inc. prepared reports of estimated proved oil reserves for wholly owned assets located in the Eagle Ford Shale and Giddings field in Grimes County, Texas.

The estimates of net proved natural gas and oil reserves as of December 31, 2010 were based on reserve reports prepared by the following independent petroleum engineers. AJM Petroleum Consultants prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Canada. Miller and Lents, Ltd. prepared reports of estimated proved oil and gas reserves for both our wholly owned assets and our U.S. joint venture’s interests in natural gas and oil properties located in the United States. Netherland, Sewell & Associates, Inc., prepared reports of estimated proved oil reserves for certain properties located in the Cat Canyon and West Cat Canyon Fields in Santa Barbara County, California. Lonquist & Co., LLC prepared reports of estimated proved oil and gas reserves for our wholly owned assets in Colombia.

The following supplementary information includes our results of operations for oil and gas production activities; capitalized costs related to oil and gas producing activities; and costs incurred in oil and gas property acquisition, exploration and development. Supplemental information is also provided for the estimated quantities of proved oil and gas reserves; the standardized measure of discounted future net cash flows associated with proved oil and gas reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil and gas reserves.

Results of Operations

Results of operations consist of all activities within our Oil and Gas operating segment, or in discontinued operations in some cases. Net revenues from production include only the revenues from the production and sale of natural gas, oil, and natural gas liquids. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Exploration expenses include dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization (“DD&A”) allowances, after giving effect to permanent differences. The 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 Cost

Capitalized costs include the cost of properties, equipment and facilities for oil and gas-producing activities. Capitalized costs for proved properties include costs for oil and gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or for active completion, and costs of exploratory wells suspended or waiting for completion.

	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 Oil and Gas Property Acquisitions, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense during 2011 and 2010, respectively, for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs include the costs of drilling and equipping successful exploration wells, as well as dry-hole costs, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

	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.

Oil and Gas Reserves

The reserve disclosures that follow reflect estimates of proved reserves for our consolidated subsidiaries and equity companies of natural gas, oil, and natural gas liquids owned at December 31, 2011 and 2010 and changes in proved reserves during 2011 and 2010. Our year-end reserve volumes in the following tables were calculated using average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserve quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Estimates of volumes of proved reserves of natural gas at year end are expressed in billions of cubic feet of natural gas (“Bcf”) at a pressure base of 14.73 pounds per square inch for natural gas and in millions of barrels (“MMBbls”) for oil and natural gas liquids.

For our wholly owned properties in the United States and the properties of our unconsolidated U.S. joint venture, the prices used in our reserve reports were $4.12 per mcf for the 12-month average of natural gas, $57.71 per barrel for natural gas liquids and $96.19 per barrel for oil at December 31, 2011. For our wholly owned properties in Canada, the price used in our reserve reports was $3.85 per mcf for the 12-month average of natural gas at December 31, 2011.

For our wholly owned properties in the United States, the prices used in our reserve reports were $3.72 per mcf for the 12-month average of natural gas, $36.43 per barrel for liquid natural gas and $61.12 per barrel for oil at December 31, 2010. The prices used in our reserve reports by our unconsolidated U.S. joint venture were $4.53 per mcf for the 12-month average of natural gas, $39.04 per barrel for liquid natural gas and $70.60 per barrel for oil at December 31, 2010. For our wholly owned properties in Canada, the price used in our reserve reports was $2.81 per mcf for the 12-month average of natural gas at December 31, 2010. The 12-month average price for natural gas used in the reserve report by our unconsolidated Canada joint venture was $2.78 per mcf at December 31, 2010. For our wholly owned properties in Colombia, the price used in our reserve reports was $78.21 per barrel for oil at December 31, 2010. The oil price used in the reserve report by our unconsolidated Colombia joint venture was $76.00 per barrel at December 31, 2010.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation of (1) already available geologic, reservoir or production data, (2) new geologic, reservoir or production data or (3) changes in average prices and year-end costs that are used in the estimation of reserves. This category can also include significant changes in either development strategy or production equipment/facility capacity.

Proved reserves include 100 percent of each majority-owned affiliate’s participation in proved reserves and our ownership percentage of the proved reserves of equity companies, but exclude royalties and quantities due others.

In the proved reserves tables, consolidated reserves and equity company reserves are reported separately. However, we do not view equity company reserves any differently than those of our consolidated subsidiaries.

Net proved developed reserves are those volumes that are expected to be recovered 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. Net proved undeveloped reserves are those volumes 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.

	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

For the years ended December 31, 2011 and 2010, the standardized measure of discounted future net cash flow was computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. Estimated future net cash flows for all periods presented are reduced by estimated future development, production, abandonment and dismantlement costs based on existing costs, assuming continuation of existing economic conditions, and by estimated future income tax expense. These estimates also include assumptions about the timing of future production of proved reserves, and timing of future development, production costs, and abandonment and dismantlement. Income tax expense, both U.S. and global, 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 10-percent discount factor is prescribed by GAAP.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our consolidated subsidiaries and equity companies’ proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Significant changes in estimated reserve volumes or commodity prices could have a material effect on our consolidated financial statements.

	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.

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

The following table reflects the estimate of changes in the standardized measure of discounted future net cash flows from proved 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.