Note 14. Supplemental Natural Gas and Oil Information (Unaudited)

Users of this information should be aware that the process of estimating quantities of proved natural gas, NGLs and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent quantities of natural gas, NGLs and oil which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be recoverable in the future from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment, infrastructure and operating methods.

Estimates of reserves as of December 31, 2011, 2010 and 2009 are based upon studies for each of HighMount's properties prepared by HighMount staff engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. HighMount's reserve estimates for 2011 were audited by Netherland, Sewell & Associates, Inc., ("NSAI"). NSAI is an independent third party petroleum engineering consulting firm, and the audit was performed in accordance with the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the Society of Petroleum Engineers. All proved reserves are located in the United States of America.

Reserves

Estimated net quantities of proved natural gas and oil (including condensate and NGLs) reserves at December 31, 2011, 2010 and 2009 and changes in the reserves during 2011, 2010 and 2009 are shown in the schedule below:


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.

Capitalized Costs

The aggregate amounts of costs capitalized for natural gas and oil producing activities, and related aggregate amounts of accumulated depletion follow:


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

The following costs were 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 Reserves

The following table represents a calculation of the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities that HighMount owns:


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:


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

In the foregoing determination of future cash inflows, sales prices for natural gas and oil represent average prices determined as an unweighted arithmetic average of the first-day-of-the-month price for each month, changed for contractual arrangements with customers. Future costs of developing and producing the proved natural gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of HighMount's proved reserves. HighMount cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision and the 10% discount rate. In addition, costs and prices as of the measurement date are used in the determinations, and no value was assigned to probable or possible reserves.

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

The following table is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:


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