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 tables present the total aggregate capitalized costs and the costs incurred relating to natural gas, NGLs and oil production activities (a):



	For the Years Ended December 31,
	2017		2016		2015
	(Thousands)
At December 31:
Capitalized Costs:
Proved properties	$	18,920,855	$	12,179,833	$	10,918,499
Unproved properties	5,016,299		1,698,826		898,270
Total capitalized costs	23,937,154		13,878,659		11,816,769
Accumulated depreciation and depletion	5,121,646		4,217,154		3,425,618
Net capitalized costs	$	18,815,508	$	9,661,505	$	8,391,151



	For the Years Ended December 31,
	2017		2016		2015
	(Thousands)
Costs incurred: (a)
Property acquisition:
Proved properties (b)	$	5,251,711	$	403,314	$	23,890
Unproved properties (c)	3,310,995		880,545		158,405
Exploration (d)	15,505		6,047		53,463
Development	1,365,615		777,787		1,633,498
Geological and geophysical	—		—		—

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

(b) Amounts in 2017 include $2,530.4 million and $1,192.0 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. The purchase of Marcellus leases includes measurement period adjustments to the 2016 acquisitions. Amounts in 2017 also include $1,228.6 million and $0.3 million for the purchase of Utica wells and leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. Amounts in 2016 include $256.2 million and $112.2 million for the purchase of Marcellus wells and leases, respectively, acquired in the 2016 transactions discussed in Note 10.

(c) Amounts in 2017 include $2,625.1 million and $0.5 million for the purchase of Marcellus leases and Utica leases, respectively, acquired in the 2017 transactions discussed in Notes 2 and 10. Amounts in 2016 include $770.4 million for the purchase of Marcellus leases acquired in the 2016 transactions discussed in Note 10.

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

Capitalized costs of unproved oil and gas properties are evaluated at least annually for recoverability on a prospective basis. Indicators of potential impairment include changes in development plans resulting from economic factors, potential shifts in business strategy employed by management and historical experience. If it is determined that the properties will not yield proved reserves prior to the expiration or abandonment of the lease, the related costs are expensed in the period in which that determination is made. For the year ended December 31, 2017, EQT Production recorded no unproved property impairment. For the years ended December 31, 2016 and 2015, the Company recorded unproved property impairments of $6.9 million and $19.7 million, respectively, which are included in the impairment of long-lived assets in the Statements of Consolidated Operations. In addition, non-cash charges for leases which expired prior to drilling of $7.6 million, $8.7 million and $37.4 million are included in exploration expense for the years ended December 31, 2017, 2016 and 2015, respectively. Unproved properties had a net book value of $5,016.3 million and $1,698.8 million at December 31, 2017 and 2016, respectively.

Results of Operations for Producing Activities

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



	For the Years Ended December 31,
	2017		2016			2015
	(Thousands)
Revenues:
Nonaffiliated	$	2,651,318	$	1,594,997		$	1,690,360
Production costs	1,338,069		1,055,017			877,194
Exploration costs	25,117		13,410			61,970
Depreciation, depletion and accretion	982,103		859,018			765,298
Impairment of long-lived assets	—		6,939			122,469
Amortization of intangible assets	5,540		—			—
Income tax expense (benefit)	117,984		(136,323		)	(54,857		)
Results of operations from producing activities (excluding corporate overhead)	$	182,505	$	(203,064	)	$	(81,714	)

Reserve Information

The information presented below represents estimates of proved natural gas, NGLs 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 29 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, NGLs 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. In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company’s interests as of December 31, 2017. Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 81% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining 19% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 256 wells per case for non-operated wells. For undeveloped locations, the Company determined, and Ryder Scott reviewed and approved, the areas within the Company’s acreage considered to be proven. Reserves were assigned and projected by the Company’s reserve engineers for locations within these proven areas and approved by Ryder Scott based on analogous type curves and offset production information. 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,
	2017		2016		2015
	(Millions of Cubic Feet)
Total - Natural Gas, Oil, and NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	13,508,407		9,976,597		10,738,948
Revision of previous estimates	(2,766,981	)	(472,285	)	(2,194,675	)
Purchase of hydrocarbons in place	9,389,638		2,395,776		—
Sale of hydrocarbons in place	(2,646	)	—		(61	)
Extensions, discoveries and other additions	2,225,141		2,384,682		2,051,071
Production	(907,892	)	(776,363	)	(618,686	)
End of year	21,445,667		13,508,407		9,976,597
Proved developed reserves:
Beginning of year	6,842,958		6,279,557		4,826,387
End of year	11,297,956		6,842,958		6,279,557
Proved undeveloped reserves:
Beginning of year	6,665,449		3,697,040		5,912,561
End of year	10,147,711		6,665,449		3,697,040

(a) Oil and NGLs were converted at the rate of one thousand Bbl equal to approximately 6 million cubic feet (MMcf).



	Years Ended December 31,
	2017		2016		2015
	(Millions of Cubic Feet)
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	12,331,867		9,110,311		9,775,954
Revision of previous estimates	(2,760,467	)	(607,171	)	(2,059,531	)
Purchase of natural gas in place	8,890,145		2,288,166		—
Sale of natural gas in place	(1,210	)	—		(61	)
Extensions, discoveries and other additions	2,164,578		2,241,528		1,955,935
Production	(794,677	)	(700,967	)	(561,986	)
End of year	19,830,236		12,331,867		9,110,311
Proved developed reserves:
Beginning of year	6,074,958		5,652,989		4,257,377
End of year	10,152,543		6,074,958		5,652,989
Proved undeveloped reserves:
Beginning of year	6,256,909		3,457,322		5,518,577
End of year	9,677,693		6,256,909		3,457,322



	Years Ended December 31,
	2017		2016		2015
	(Thousands of Bbls)
Oil (a)
Proved developed and undeveloped reserves:
Beginning of year	6,395		5,900		5,005
Revision of previous estimates	5,103		1,159		1,219
Purchase of oil in place	355		3		—
Sale of oil in place	(139	)	—		—
Extensions, discoveries and other additions	9		62		419
Production	(992	)	(729	)	(743	)
End of year	10,731		6,395		5,900
Proved developed reserves:
Beginning of year	6,395		5,900		5,005
End of year	10,731		6,395		5,900
Proved undeveloped reserves:
Beginning of year	—		—		—
End of year	—		—		—

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



	Years Ended December 31,
	2017		2016		2015
	(Thousands of Bbls)
NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	189,695		138,481		155,494
Revision of previous estimates	(6,189	)	21,322		(23,743	)
Purchase of NGLs in place	82,894		17,932		—
Sale of NGLs in place	(100	)	—		—
Extensions, discoveries and other additions	10,084		23,797		15,437
Production	(17,877	)	(11,837	)	(8,707	)
End of year	258,507		189,695		138,481
Proved developed reserves:
Beginning of year	121,605		98,528		89,830
End of year	180,170		121,605		98,528
Proved undeveloped reserves:
Beginning of year	68,090		39,953		65,664
End of year	78,337		68,090		39,953

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

2017 Changes in Reserves


•	Transfer of 987 Bcfe of proved undeveloped reserves to proved developed reserves.


•	Increase of 9,390 Bcfe associated with the acquisition of proved developed reserves (3,330 Bcfe) and proved undeveloped reserves (6,060 Bcfe) in the Company’s Marcellus, Upper Devonian and Utica plays.


•	Extensions, discoveries and other additions of 2,225 Bcfe, which exceeded the 2017 production of 908 Bcfe.


•	Negative revisions of 3,522 Bcfe from proved undeveloped locations, primarily due to 3,074 Bcfe from locations that are no longer anticipated to be drilled within 5 years of booking as a result of acquiring new acreage. The acquired acreage presents opportunities to drill considerably longer laterals, realize operational efficiencies and improve overall returns.


•	Upward revisions of 477 Bcfe from proved developed locations, primarily due to increased reserves from producing wells.


•	Upward revisions of 278 Bcfe associated with previously booked locations whose economic lives had been extended due to improved commodity prices.

2016 Changes in Reserves


•	Transfer of 647 Bcfe of proved undeveloped reserves to proved developed reserves.


•	Increase of 2,396 Bcfe associated with the acquisition of proved developed reserves (320 Bcfe) and proved undeveloped reserves (2,076 Bcfe) in the Company’s Marcellus and Upper Devonian plays.


•	Extensions, discoveries and other additions of 2,385 Bcfe, which exceeded the 2016 production of 776 Bcfe.


•	Negative revisions of 509 Bcfe from proved undeveloped locations, primarily due to 389 Bcfe from economic locations that the Company no longer expects to develop within 5 years of booking, along with the removal of locations that are no longer economic as determined in accordance with Securities and Exchange Commission (SEC) pricing requirements.


•	Upward revisions of 68 Bcfe from proved developed locations, primarily due to increased reserves from producing wells.


•	Negative revisions of 31 Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced commodity prices.

2015 Changes in Reserves


•	Transfer of 1,528 Bcfe of proved undeveloped reserves to proved developed reserves.


•	Extensions, discoveries and other additions of 2,051 Bcfe, which exceeded the 2015 production of 619 Bcfe.


•	Negative revisions of 2,321 Bcfe from proved undeveloped locations, due primarily to the removal of locations that were no longer economic as determined in accordance with SEC pricing requirements and from 342 Bcfe from economic locations that the Company no longer expects to develop within 5 years of booking.


•	Upward revisions of 386 Bcfe from proved developed locations, primarily due to increased reserves from producing wells.


•	Negative revisions of 259 Bcfe associated with previously booked locations whose economic lives had been shortened due to reduced commodity prices.

During 2015, the Company revised its approach utilized to determine the gathering cost assumption within the Company's determination of reserves, which management believes to be a significant cost assumption included in the calculation of reserves. The Company believes the methodology that is currently utilized to determine the gathering rate reflects the Company’s current cash operating costs and gives consideration to EQT’s significant ownership interest in EQGP, EQM and RMP. Previously, the Company developed the gathering cost assumption based on the direct operating costs attributable to the operation of the wholly-owned midstream assets. Due to additional dropdowns of midstream assets from EQT to EQM in 2015 and the resulting increase in the proportion of the volumes that are gathered using EQM owned gathering assets, the current gathering rate assumption was developed in consideration of EQT’s significant ownership interest in its consolidated subsidiaries.

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%. The estimated future net cash flows from natural gas and oil reserves as of December 31, 2017 includes the impact of the Tax Reform Legislation, which resulted in a lower federal income tax rate than the prior years presented.

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



	2017			2016			2015
	(Thousands)
Future cash inflows (a)	$	51,423,920		$	24,011,281		$	17,619,037
Future production costs	(18,379,892		)	(14,864,126		)	(10,963,285		)
Future development costs	(5,637,676		)	(3,778,698		)	(2,377,650		)
Future income tax expenses	(5,811,125		)	(1,753,067		)	(1,333,989		)
Future net cash flow	21,595,227			3,615,390			2,944,113
10% annual discount for estimated timing of cash flows	(12,593,293		)	(2,626,636		)	(1,966,559		)
Standardized measure of discounted future net cash flows	$	9,001,934		$	988,754		$	977,554



(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017 of $51.34 per Bbl of oil (first day of each month closing price for West Texas Intermediate (WTI)) less regional adjustments, $2.801 per Dth for Columbia Gas Transmission Corp., $2.100 per Dth for Dominion Transmission, Inc., $2.914 per Dth for the East Tennessee Natural Gas Pipeline, $2.058 per Dth for Texas Eastern Transmission Corp., $1.995 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.321 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.665 per Dth for Waha, and $2.840 per Dth for the Rockies Express Pipeline Zone 3. For 2017, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2017 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $23.07 per Bbl of NGLs from certain West Virginia Marcellus reserves, $31.11 per Bbl of NGLs from certain Kentucky reserves, $29.47 per Bbl for Ohio Utica reserves, and $27.93 per Bbl for Permian reserves.

	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016 of $42.75 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.342 per Dth for Columbia Gas Transmission Corp., $1.348 per Dth for Dominion Transmission, Inc., $2.334 per Dth for the East Tennessee Natural Gas Pipeline, $1.325 per Dth for Texas Eastern Transmission Corp., $1.305 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $1.862 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.343 per Dth for Waha, and $2.402 per Dth for the Rockies Express Pipeline Zone 3. For 2016, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2016 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $13.87 per Bbl of NGLs from certain West Virginia Marcellus reserves, $17.27 per Bbl of NGLs from certain Kentucky reserves, $14.71 per Bbl for Ohio Utica reserves, and $18.91 per Bbl for Permian reserves.

	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015 of $50.28 per Bbl of oil (first day of each month closing price for WTI) less regional adjustments, $2.506 per Dth for Columbia Gas Transmission Corp., $1.394 per Dth for Dominion Transmission, Inc., $2.552 per Dth for the East Tennessee Natural Gas Pipeline, $1.428 per Dth for Texas Eastern Transmission Corp., $1.079 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $2.430 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $2.473 per Dth for Waha, and $2.549 per Dth for Houston Ship Channel. For 2015, NGLs pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGLs components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from certain West Virginia Marcellus reserves, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Ohio Utica reserves, and $17.51 per Bbl for Permian reserves.

Holding production and development costs constant, a change in price of $0.20 per Dth for natural gas, $10 per barrel for oil and $10 per barrel for NGLs would result in a change in the December 31, 2017 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $1.8 billion, $50.4 million and $978.6 million, respectively.

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



	2017			2016			2015
	(Thousands)
Sales and transfers of natural gas and oil produced – net	$	(1,313,249	)	$	(539,980	)	$	(813,166	)
Net changes in prices, production and development costs	2,236,183			(1,129,026		)	(5,546,405		)
Extensions, discoveries and improved recovery, less related costs	1,269,712			590,885			264,735
Development costs incurred	712,635			402,891			971,186
Purchase of minerals in place – net	5,357,921			592,078			—
Sale of minerals in place – net	(284		)	—			(43		)
Revisions of previous quantity estimates	(297,437		)	(60,959		)	(1,541,418		)
Accretion of discount	115,437			122,674			600,099
Net change in income taxes	(1,477,603		)	(91,823		)	2,424,200
Timing and other (a)	1,409,865			124,460			(191,662		)
Net increase (decrease)	8,013,180			11,200			(3,832,474		)
Beginning of year	988,754			977,554			4,810,028
End of year	$	9,001,934		$	988,754		$	977,554


(a)	Increase in 2017 primarily driven by timing changes to the Company’s development plan as a result of the Rice Merger.