Natural Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2011

Natural Gas Producing Activities (Unaudited)

Natural Gas Producing Activities (Unaudited)

22.Natural Gas Producing Activities (Unaudited)

The supplementary information summarized below presents the results of natural gas and oil activities for the EQT Production segment in accordance with the successful efforts method of accounting for production activities.

Production Costs

The following table presents the costs incurred relating to natural gas and oil production activities (a):

	For the years ended December 31,
	2011		2010		2009
	(Thousands)
At December 31:
Capitalized costs	$	5,772,083	$	4,655,217	$	3,423,068
Accumulated depreciation and depletion	1,177,526		967,473		797,303
Net capitalized costs	4,594,557		3,687,744		$	2,625,765
Costs incurred for the years ended December 31:
Property acquisition:
Proved properties (b)	$	108,717	$	15,359	$	6,035
Unproved properties	41,085		342,372		24,941
Exploration (c)	2,344		5,105		14,909
Development	928,294		881,331		676,121

(a)Amounts exclude capital expenditures for facilities and information technology.

(b)Amount includes $92.6 million of liabilities assumed in exchange for proved developed properties as part of the ANPI transaction in 2011.

(c)Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.

Results of Operations for Producing Activities

The following table presents the results of operations related to natural gas and oil production.

	For the years ended December 31,
	2011		2010		2009
	(Thousands)
Revenues:
Affiliated	$	6,225	$	7,371	$	6,923
Nonaffiliated	785,060		530,286		414,067
Production costs	80,911		67,414		62,978
Exploration costs	4,932		5,368		17,905
Depreciation, depletion and accretion	257,144		183,699		117,424
Income tax expense	174,835		106,847		84,620
Results of operations from producing activities (excluding corporate overhead)	$	273,463	$	174,329	$	138,063

Reserve Information

The information presented below represents estimates of proved natural gas and oil reserves prepared by Company engineers. The engineer primarily responsible for preparing the reserve report and the technical aspects of the reserves audit received a bachelor’s degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University and has twenty-three years of experience in the oil and gas industry.  To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves; production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve roll forward between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas and oil reserves are audited by the independent consulting firm of Ryder Scott Company L.P., who is hired by the Company’s management.  Since 1937, Ryder Scott Company L.P. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment.  There were no differences between the internally prepared and externally audited estimates.  Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.  Ryder Scott Company L.P. reviewed 100% of the total net gas and liquid hydrocarbon proved reserves attributable to the Company’s interests as of December 31, 2011.  Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties.  This audit covered 80% of the Company’s proved reserves.  Ryder Scott’s audit of the remaining 20% of the Company’s properties consisted of an audit of aggregated groups not exceeding 200 wells per group.  The audit utilized the performance method and the analogy method.  Where historical reserve or production data was definitive the performance method, which extrapolates historical data, was utilized.   In other cases the analogy method, which calculates reserves based on correlations to comparable surrounding wells, was utilized.  All of the Company’s proved reserves are located in the United States.

	Years Ended December 31,
	2011	2010	2009
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	5,205,692	4,056,059	3,097,260
Revision of previous estimates	(393,129)	(606,308)	(94,728)
Purchase of natural gas in place	39,436	2,536	–
Sale of natural gas in place	(1,223)	(1,679)	(741)
Extensions, discoveries and other additions	694,180	1,893,387	1,158,602
Production	(197,570)	(138,303)	(104,334)
End of year	5,347,386	5,205,692	4,056,059
Proved developed reserves:
Beginning of year	2,520,569	2,061,353	1,881,767
End of year	2,948,546	2,520,569	2,061,353

	Years Ended December 31,
	2011	2010	2009
	(Thousands of Bbls)
Oil (a)
Proved developed and undeveloped reserves:
Beginning of year	2,307	2,016	2,125
Revision of previous estimates	781	411	(10)
Purchase of oil in place	51	–	–
Sale of oil in place	–	–	–
Production	(208)	(120)	(99)
End of year	2,931	2,307	2,016
Proved developed reserves:
Beginning of year	2,307	2,016	2,125
End of year	2,931	2,307	2,016

(a)One thousand Bbl equals approximately 6 million cubic feet (MMcf).

As discussed in Note 6, the Company acquired the Class A interest in the Appalachian Natural Gas Trust (ANGT) in May 2011. Prior to this acquisition, the Company held a 1% equity interest in ANGT which was accounted for under the equity method.  The Company’s share of these reserves and the impact on the standard measure of discounted future cash flow was not considered material and therefore was excluded from these measures prior to the acquisition.  This acquisition added 39.7 Bcfe of proved developed reserves.

During 2011, the Company recorded downward revisions of 388.4 Bcfe to the December 31, 2010 estimates of its reserves primarily due to removing proved undeveloped reserves in the Huron play in order to focus capital and resources in the Marcellus play over the five-year time horizon included in the proved undeveloped reserves development plan.  The Company’s 2011 extension, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery of 694.2 Bcfe exceeded the 2011 production of 198.8 Bcfe.

During 2010, the Company recorded downward revisions of 603.8 Bcfe to the December 31, 2009 estimates of its reserves primarily due to removing proved undeveloped reserves in the Huron play in order to focus more capital and resources in the Marcellus play over the five-year time horizon included in the proved undeveloped reserves development plan, partially offset by increased prices. The Company’s 2010 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,893.4 Bcfe exceeded the 2010 production of 139.0 Bcfe.

The Company’s 2009 extensions, discoveries and other additions, resulting from extensions of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,158.6 Bcfe exceeded the 2009 production of 104.9 Bcfe.  Of this increase, approximately 715 Bcfe was attributable to drilling in 2009 that would have qualified as reserve extensions, discoveries and other additions under the previous Security Exchange Commission (SEC) rules, including approximately 400 Bcfe related to offset locations from wells drilled in 2009.  The remaining additions are attributable to the SEC’s expanded definition of proved reserves in 2009 to include reserves based on reasonable certainty, partially offset by removing reserves that were previously recorded for future vertical wells.

During 2009, the Company recorded downward revisions of 94.8 Bcfe to the December 31, 2008 estimates of its reserves due to decreased prices and other revisions.  The new SEC oil and gas reporting rule modified the definition of proved reserves as well as the price used in the calculation which resulted in approximately 55 Bcfe of the 94.8 Bcfe revision of previous estimates. Absent the effect of the new SEC oil and gas reporting rule, the price impact would have been minimal as year-end prices only decreased approximately $0.06 per Dth from 2008.

During 2009, as a result of the adoption of the new SEC oil and gas reporting rule, previously recorded reserves from vertical well locations were removed and replaced with new reserves from horizontal well locations.  This aligned the reserves with the Company’s five-year drilling plan.  Increases in proved undeveloped reserves in 2009 were primarily due to the ability to add horizontal proved undeveloped location more than one offset location away from existing horizontals.

As of December 31, 2011, the Company did not have any reserves that have been classified as proved undeveloped reserves for more than five years.

Standard Measure of Discounted Future Cash Flow

Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom.  The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

Estimated future net cash flows from natural gas and oil reserves are as follows at December 31:

	2011		2010		2009
	(Thousands)
Future cash inflows (a) (b) (c)	$	22,145,953	$	20,037,125	$	13,157,580
Future production costs	(3,435,200)		(3,313,378)		(3,804,077)
Future development costs	(2,600,982)		(2,497,312)		(2,929,255)
Future net cash flow before income taxes	16,109,771		14,226,435		6,424,248
10% annual discount for estimated timing of cash flows	(9,887,993)		(9,439,629)		(5,135,935)
Discounted future net cash flows before income taxes	6,221,778		4,786,806		1,288,313
Future income tax expenses, discounted at 10% annually	(2,288,954)		(1,728,594)		(489,559)
Standardized measure of discounted future net cash flows	$	3,932,824	$	3,058,212	$	798,754

(a)  The majority of the Company’s production is sold through liquid trading points on interstate pipelines.  For 2011, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011 of $92.84 per Bbl of oil, $4.198 per Dth for Columbia Gas Transmission Corp., $4.243 per Dth for Dominion Transmission, Inc., $4.159 per Dth for the East Tennessee Natural Gas Pipeline and $4.172 per Dth for the Tennessee LA 500 Leg of Transcontinental Gas Pipe Line Corp.  The Company sold its natural gas processing complex in Langley, Kentucky on February 1, 2011.  As a result of that sale, management determined that the revenue received from the fractionation of NGLs which were extracted from the Company’s produced natural gas would be reported in EQT Production rather than EQT Midstream.  For 2011, the West Virginia Marcellus reserves and certain Kentucky reserves were computed using an additional $1.139 and $2.149, respectively, for revenues earned on NGLs that are produced from those reserves.

(b)  The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2010, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2010 of $76.68 per Bbl of oil, $4.502 per Dth for Columbia Gas Transmission Corp., $4.563 per Dth for Dominion Transmission, Inc., $4.407 per Dth for the East Tennessee Natural Gas Pipeline and $4.422 per Dth for the Tennessee LA 500 Leg of Transcontinental Gas Pipe Line Corp.

(c)  The majority of the Company’s production is sold through liquid trading points on interstate pipelines.  For 2009, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2009 of $58.43 per Bbl of oil, $4.046 per Dth for Columbia Gas Transmission Corp., $4.128 per Dth for Dominion Transmission, Inc., $3.909 per Dth for the East Tennessee Natural Gas Pipeline and $3.920 per Dth for the Tennessee LA 500 Leg of Transcontinental Gas Pipe Line Corp.

Holding production and development costs constant, a change in price of $1 per Dth for natural gas and $10 per barrel for oil would result in a change in the December 31, 2011 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $2.3 billion and $8.5 million, respectively.

Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:

	2011		2010		2009
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(710,373)	$	(470,243)	$	(323,225)
Net changes in prices, production and development costs	52,057		807,971		(3,161,428)
Extensions, discoveries and improved recovery, less related costs	806,597		1,739,308		369,075
Development costs incurred	498,175		310,557		560,911
Purchase of minerals in place – net	46,178		2,330		–
Sale of minerals in place – net	(1,124)		(532)		(775)
Revisions of previous quantity estimates	(356,830)		(191,336)		(31,047)
Accretion of discount	478,165		128,741		324,337
Net change in income taxes	(560,360)		(1,239,035)		743,686
Timing and other (a)	622,127		1,171,697		305,085
Net increase (decrease)	874,612		2,259,458		(1,213,381)
Beginning of year	3,058,212		798,754		2,012,135
End of year	$	3,932,824	$	3,058,212	$	798,754

(a)  The change in the Company’s future drilling plans to include a higher percentage of wells drilled from the Marcellus play resulted in an increase during the year ended December 31, 2011 and 2010 in discounted future net cash flows due to the higher initial production rates and lower development costs per Mcfe from these wells.