21. 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, NGL and oil production activities (a):

	For the Years Ended December 31,
	2013		2012		2011
	(Thousands)
At December 31:
Capitalized costs	$	8,152,951	$	6,750,343	$	5,772,083
Accumulated depreciation and depletion	2,134,953		1,572,775		1,177,526
Net capitalized costs	$	6,017,998	$	5,177,568	$	4,594,557
Costs incurred for the years ended December 31:
Property acquisition:
Proved properties (b)	$	90,390	$	16,965	$	108,717
Unproved properties	95,861		117,654		41,085
Exploration (c)	4,285		4,827		2,344
Development	1,230,301		850,854		928,294

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

(b) Amounts include $57.0 million for the purchase of Marcellus wells acquired in the Chesapeake acquisition in 2013 and $92.6 million of liabilities assumed in exchange for proved developed properties as part of the ANPI transaction in 2011.

Results of Operations for Producing Activities

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

	For the Years Ended December 31,
	2013		2012		2011
	(Thousands)
Revenues:
Affiliated	$	5,912	$	3,433	$	6,225
Nonaffiliated	1,162,745		790,340		785,060
Production costs	108,091		96,155		80,911
Exploration costs	18,483		10,370		4,932
Depreciation, depletion and accretion	578,641		409,628		257,144
Income tax expense	183,060		109,660		174,835
Results of operations from producing activities (excluding corporate overhead)	$	280,382	$	167,960	$	273,463

Reserve Information

The information presented below represents estimates of proved natural gas, NGL 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 25 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; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGL and oil reserves are audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management. Since 1937, Ryder Scott 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 reviewed 100% of the total net gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2013. 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,
	2013		2012		2011
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	5,985,758		5,347,386		5,205,692
Revision of previous estimates	(375,887	)	(755,788	)	(393,129	)
Purchase of natural gas in place	472,798		–		39,436
Sale of natural gas in place	(455	)	(694	)	(1,223	)
Extensions, discoveries and other additions	1,844,840		1,654,228		694,180
Production	(365,493	)	(259,374	)	(197,570	)
End of year	7,561,561		5,985,758		5,347,386
Proved developed reserves:
Beginning of year	2,779,187		2,948,546		2,520,569
End of year	3,567,313		2,779,187		2,948,546

	Years Ended December 31,
	2013		2012		2011
	(Thousands of Bbls)
Oil (a)
Proved developed and undeveloped reserves:
Beginning of year	3,199		2,931		2,307
Revision of previous estimates	270		265		781
Purchase of oil in place	–		–		51
Sale of oil in place	–		–		–
Extensions, discoveries and other additions	757		268		–
Production	(270	)	(265	)	(208	)
End of year	3,956		3,199		2,931
Proved developed reserves:
Beginning of year	3,199		2,931		2,307
End of year	3,892		3,199		2,931

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

		Year Ended December 31, 2013
NGLs (a)		(Thousands of Bbls)
Proved developed and undeveloped reserves:
Beginning of year		–
Revision of previous estimates		94,296
Purchase of NGLs in place		–
Sale of NGLs in place		–
Extensions, discoveries and other additions		32,866
Production		–
End of year		127,162
Proved developed reserves:
Beginning of year		–
End of year		65,837

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

As discussed in Note 8, the Company acquired the Class A interest in 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 2013, the Company recorded upward revisions of 191.5 Bcfe to the December 31, 2012 estimates of its reserves primarily due to the increase in the average NYMEX natural gas price for the year causing the properties to remain economic for a longer period. This increase was partially offset by negative revisions of 349 Bcfe, which was primarily due to the removal of 58 undeveloped locations and their associated reserves. The Company has included NGL reserves for the first time in 2013. This caused a one-time decrease in gas reserves and an increase in equivalent reserves. Due to the continued growth in NGL reserves, the Company is separately calculating and presenting such reserves. The Company’s 2013 extensions, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 2,046.6 Bcfe exceeded the 2013 production of 367.1 Bcfe. These reserve extensions and discoveries were mainly due to decreased lateral spacing in one of the Company’s locations in Greene County, Pennsylvania, and additional proved locations in the Company’s Pennsylvania and West Virginia Marcellus fields and the addition of Huron proved undeveloped reserves due to the re-establishment of the Huron development program.

During 2012, the Company recorded downward revisions of 754.2 Bcfe to the December 31, 2011 estimates of its reserves primarily due to the decrease in the average NYMEX natural gas price for the year causing the existing reserves to become uneconomic in accordance with SEC pricing requirements. The Company’s 2012 extensions, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,655.8 Bcfe exceeded the 2012 production of 261.0 Bcfe. These reserve extensions and discoveries were mainly due to decreased lateral spacing in one of the Company’s Greene County, Pennsylvania locations and additional proved locations in the Company’s Wetzel and Doddridge County, West Virginia development areas.

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 extensions, 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.

As of December 31, 2013, 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:

	2013			2012			2011
	(Thousands)
Future cash inflows (a)	$	25,912,542		$	15,250,019		$	22,145,953
Future production costs	(4,180,136		)	(3,070,957		)	(3,435,200		)
Future development costs	(4,199,722		)	(3,082,053		)	(2,600,982		)
Future income tax expenses	(6,533,817		)	(3,324,472		)	(6,075,539		)
Future net cash flow	10,998,867			5,772,537			10,034,232
10% annual discount for estimated timing of cash flows	(7,047,588		)	(3,617,378		)	(6,101,408		)
Standardized measure of discounted future net cash flows	$	3,951,279		$	2,155,159		$	3,932,824

(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2013, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013 of $89.22 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $3.653 per Dth for Columbia Gas Transmission Corp., $3.447 per Dth for Dominion Transmission, Inc., $3.693 per Dth for the East Tennessee Natural Gas Pipeline, $3.495 per Dth for Texas Eastern Transmission Corp., $2.842 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $3.521 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.

	For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012 of $82.90 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $2.793 per Dth for Columbia Gas Transmission Corp., $2.785 per Dth for Dominion Transmission, Inc., $2.769 per Dth for the East Tennessee Natural Gas Pipeline, $2.782 per Dth for Texas Eastern Transmission Corp., $2.403 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.878 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company. For 2012, the West Virginia Marcellus reserves from Doddridge and Ritchie Counties were computed using an additional $0.591 and reserves from Wetzel County were computed using an additional $0.398 for revenues earned on NGLs that are produced from those reserves. Revenues earned on NGLs that are produced from certain Kentucky reserves were computed using an additional $0.764.

	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 (first day of each month closing price for WTI less Appalachian Basin adjustment), $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 Tennessee Gas Pipeline Company. The Company sold Langley 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.

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, 2013 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $3.2 billion and $15.6 million, respectively.

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

	2013			2012			2011
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(1,060,566	)	$	(697,618	)	$	(710,373	)
Net changes in prices, production and development costs	(292,533		)	(3,530,086		)	52,057
Extensions, discoveries and improved recovery, less related costs	1,509,002			917,986			806,597
Development costs incurred	1,319,135			548,852			498,175
Purchase of minerals in place – net	348,608			–			46,178
Sale of minerals in place – net	(252		)	(807		)	(1,124		)
Revisions of previous quantity estimates	106,170			(876,336		)	(356,830		)
Accretion of discount	343,502			622,072			478,165
Net change in income taxes	(1,031,105		)	1,127,272			(560,360		)
Timing and other	554,159			111,000			622,127
Net increase (decrease)	1,796,120			(1,777,665		)	874,612
Beginning of year	2,155,159			3,932,824			3,058,212
End of year	$	3,951,279		$	2,155,159		$	3,932,824