Supplemental Natural Gas And Oil Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Natural Gas and Oil Information [Abstract]

Estimated Net Quantities Of Proved Natural Gas And Oil Reserves

Proved Developed and Undeveloped Reserves	Natural Gas			NGLs and Oil			Natural Gas Equivalents
	(Bcf)			(thousands of barrels)			(Bcfe)
January 1, 2009		1,694			84,827			2,203
Changes in reserves:
Extensions, discoveries and other additions		39			2,278			53
Revisions of previous estimates (a)		(141	)		(6,669	)		(181	)
Production		(77	)		(3,679	)		(99	)
Sales of reserves in place		(1	)		(2,919	)		(19	)
Purchases of reserves in place		7						7
December 31, 2009		1,521			73,838			1,964
Changes in reserves:
Extensions, discoveries and other additions (b)		251			13,370			331
Revisions of previous estimates (c)		(407	)		(24,518	)		(554	)
Production		(57	)		(3,263	)		(77	)
Sales of reserves in place		(363	)		(232	)		(364	)
Purchases of reserves in place
December 31, 2010		945			59,195			1,300
Changes in reserves:
Extensions, discoveries and other additions		26			3,556			48
Revisions of previous estimates (d)		(107	)		(7,540	)		(152	)
Production		(45	)		(2,976	)		(63	)
Sales of reserves in place					(11	)
Purchases of reserves in place					167			1
December 31, 2011		819			52,391			1,134
Proved developed reserves at:
December 31, 2009		1,231			58,227			1,580
December 31, 2010		741			45,804			1,016
December 31, 2011		623			37,951			851

(a) The 2009 revision is primarily attributable to lower 2009 average prices as compared to December 31, 2008. The lower 2009 average prices caused the reclassification of some proven undeveloped reserves.

(b) HighMount added 238 Bcfe of proved undeveloped reserves from non-proved categories in 2010. These additions pertain to locations HighMount expects to drill during the next five years. Additionally, HighMount added 42 Bcfe primarily through drilling and the remaining 51 Bcfe in additions were associated with the Alabama and Michigan properties prior to sale.

(c) During 2010, HighMount reclassified 208 Bcfe of proved undeveloped reserves to a non-proved category due to certain wells reaching their five year maturity as a result of reduced drilling activity in 2009 and 2010. Additionally, HighMount reduced its proved developed and proved undeveloped reserves by 346 Bcfe as a result of higher production declines on its producing wells than previously anticipated.

(d) During 2011, HighMount reduced its proved developed and proved undeveloped reserves by 152 Bcfe as a result of recent higher decline rates of producing wells and economic factors such as lower gas prices and higher operating expenses.

Aggregate Amounts Of Costs Capitalized For Natural Gas And Oil Producing Activities

December 31	2011		2010		2009
(In millions)
Subject to depletion	$	3,002	$	2,818	$	3,194
Costs excluded from depletion		384		272		317
Gross natural gas, NGL and oil properties		3,386		3,090		3,511
Less accumulated depletion		2,056		1,991		2,061
Net natural gas, NGL and oil properties	$	1,330	$	1,099	$	1,450

Costs Incurred In Natural Gas And Oil Producing Activities

Year Ended December 31	2011		2010		2009
(In millions)
Acquisition of properties:
Proved	$	12			$	7
Unproved		128	$	29		24
Subtotal		140		29		31
Exploration costs		11		5		8
Development costs (a)		159		143		148
Total	$	310	$	177	$	187

(a) Development costs incurred for proved undeveloped reserves were $25, $23 and $27 in 2011, 2010 and 2009.

Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Natural Gas And Oil Reserve Quantities

December 31	2011		2010		2009
(In millions)
Future cash inflows (a) (b)	$	5,688	$	6,044	$	7,171
Less:
Future production costs		1,969		2,073		3,098
Future development costs		636		580		538
Future income tax expense		456		571		455
Future cash flows		2,627		2,820		3,080
Less annual discount (10% a year)		1,725		1,863		1,982
Standardized measure of discounted future net cash flows	$	902	$	957	$	1,098

(a) 2011, 2010 and 2009 amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year end.

(b) The following prices were used in the determination of standardized measure:

Determination Of Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Natural Gas And Oil Reserve Quantities

December 31		2011		2010		2009
Gas (per million British thermal units)	$	4.12	$	4.38	$	3.87
NGL (per barrel)		55.18		43.75		31.73
Oil (per barrel)		96.19		79.43		61.18

Changes Between The Total Standardized Measure Of Discounted Future Net Cash Flows

Year Ended December 31	2011			2010			2009
(In millions)
Standardized measure, beginning of period	$	957		$	1,098		$	1,563
Changes in the year resulting from:
Sales and transfers of natural gas and oil produced during the year, less production costs		(291	)		(345	)		(466	)
Net changes in prices and development costs		164			890			(443	)
Extensions, discoveries and other additions, less production and development costs		82			67			46
Previously estimated development costs incurred during the period		25			23			41
Revisions of previous quantity estimates		(173	)		(346	)		19
Net changes in purchases and sales of proved reserves in place		3			(446	)		(42	)
Accretion of discount		107			114			182
Income taxes		20			(77	)		220
Net changes in production rates and other		8			(21	)		(22	)
Standardized measure, end of period	$	902		$	957		$	1,098