EQT (EQT) 10-K 11 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) shares in Thousands, $ in Billions	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Document and Entity Information
Entity Registrant Name	EQT Corp
Entity Central Index Key	33,213
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		152,568
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 10.5

STATEMENTS OF CONSOLIDATED INCO

STATEMENTS OF CONSOLIDATED INCOME - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Sales of natural gas, oil and NGLs	$ 1,690,360	$ 2,132,409	$ 1,710,245
Pipeline and marketing services	263,640	256,359	148,932
Gain on derivatives not designated as hedges	385,762	80,942	2,834
Total operating revenues	2,339,762	2,469,710	1,862,011
Operating expenses:
Transportation and processing	275,348	202,203	148,708
Operation and maintenance	124,030	108,283	97,762
Production	123,665	133,488	108,091
Exploration	61,970	21,716	18,483
Selling, general and administrative	249,925	238,134	200,849
Depreciation, depletion and amortization	819,216	679,298	653,132
Impairment of long-lived assets	122,469	267,339	0
Total operating expenses	1,776,623	1,650,461	1,227,025
Gain on sale / exchange of assets	0	34,146	19,618
Operating income	563,139	853,395	654,604
Other income	9,953	6,853	9,242
Interest expense	146,531	136,537	142,688
Income before income taxes	426,561	723,711	521,158
Income tax expense	104,675	214,092	175,186
Income from continuing operations	321,886	509,619	345,972
Income from discontinued operations, net of tax	0	1,371	91,843
Net income	321,886	510,990	437,815
Less: Net income attributable to noncontrolling interests	236,715	124,025	47,243
Net income attributable to EQT Corporation	85,171	386,965	390,572
Amounts attributable to EQT Corporation:
Income from continuing operations	85,171	385,594	298,729
Income from discontinued operations, net of tax	0	1,371	91,843
Net income	$ 85,171	$ 386,965	$ 390,572
Basic:
Average common shares outstanding	152,398	151,553	150,574
Income from continuing operations (in dollars per share)	$ 0.56	$ 2.54	$ 1.98
Income from discontinued operations, net of tax (in dollars per share)	0	0.01	0.61
Net income (in dollars per share)	$ 0.56	$ 2.55	$ 2.59
Diluted:
Average common shares outstanding	152,939	152,513	151,787
Income from continuing operations (in dollars per share)	$ 0.56	$ 2.53	$ 1.97
Income from discontinued operations, net of tax (in dollars per share)	0	0.01	0.60
Net income (in dollars per share)	$ 0.56	$ 2.54	$ 2.57

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 321,886	$ 510,990	$ 437,815
Net change in cash flow hedges:
Natural gas, net of tax (benefit) expense of ($102,271), $102,850 and ($50,200)	(152,359)	155,422	(76,489)
Interest rate, net of tax expense of $100, $104 and $63	144	145	144
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of ($564), ($515) and $16,115	(901)	(776)	21,501
Other comprehensive (loss) income	(153,116)	154,791	(54,844)
Comprehensive income	168,770	665,781	382,971
Less: Comprehensive income attributable to noncontrolling interests	236,715	124,025	47,243
Comprehensive (loss) income attributable to EQT Corporation	$ (67,945)	$ 541,756	$ 335,728

STATEMENTS OF CONSOLIDATED COM4

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net change in cash flow hedges:
Natural gas, tax expense (benefit)	$ (102,271)	$ 102,850	$ (50,200)
Interest rate, tax expense	100	104	63
Pension and other post-retirement benefits liability adjustment, tax (benefit) expense	$ (564)	$ (515)	$ 16,115

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income	$ 321,886	$ 510,990	$ 437,815
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes	17,876	32,021	110,363
Depreciation, depletion and amortization	819,216	679,298	676,570
Impairment of long-lived assets and exploratory well costs	182,242	281,979	14,198
Gain on sale / exchange of assets	0	(34,146)	(19,618)
Gain on dispositions included in discontinued operations	0	(2,898)	(166,276)
(Recoveries of) provision for losses on accounts receivable	(1,903)	88	2,957
Other income	(9,953)	(6,853)	(9,508)
Stock-based compensation expense	58,629	42,123	52,618
(Gain) loss recognized in operating revenues for hedging ineffectiveness	0	(24,774)	21,335
Gain on derivatives not designated as hedges	(385,762)	(80,942)	(2,834)
Gain on derivatives not designated as hedges	172,093	34,239	1,115
Changes in other assets and liabilities:
Dividend from Nora Gathering, LLC	0	9,463	9,000
Excess tax benefits on stock-based compensation	(22,945)	(33,216)	(12,251)
Accounts receivable	131,031	(70,392)	(44,818)
Accounts payable	(37,623)	30,350	15,990
Other items, net	(27,847)	47,412	76,205
Net cash provided by operating activities	1,216,940	1,414,742	1,162,861
Cash flows from investing activities:
Capital expenditures from continuing operations	(2,434,018)	(2,277,306)	(1,612,501)
Capital expenditures for acquisitions	0	(174,184)	(114,224)
Capital expenditures from discontinued operations	0	0	(36,637)
Dry hole costs	(17,130)	(166)	0
Capital contributions to Mountain Valley Pipeline, LLC, net of sales of interest	(74,459)	0	0
Proceeds from sale of assets	0	7,444	740,587
Proceeds from sale of energy marketing contracts	0	0	23,000
Net cash used in investing activities	(2,525,607)	(2,444,212)	(999,775)
Cash flows from financing activities:
Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs	1,182,002	902,467	529,442
Proceeds from the sale of common units of EQT GP Holdings, LP, net of sale costs	673,964	0	0
Proceeds from issuance of EQT Midstream Partners, LP debt	0	500,000	0
Increase in borrowings on credit facility	617,000	450,000	178,500
Decrease in borrowings on credit facility	(318,000)	(450,000)	(178,500)
Dividends paid	(18,310)	(18,207)	(18,094)
Distributions to noncontrolling interests	(121,759)	(67,819)	(32,781)
Repayments and retirements of long-term debt	(169,004)	(11,162)	(23,204)
Proceeds and excess tax benefits from awards under employee compensation plans	36,965	52,373	45,137
Cash paid for taxes related to net settlement of share-based incentive awards	(47,013)	(51,262)	0
Debt issuance costs and revolving credit facility origination fees	0	(12,764)	0
Repurchase and retirement of common stock	(3,375)	(32,368)	0
Net cash provided by financing activities	1,832,470	1,261,258	500,500
Net change in cash and cash equivalents	523,803	231,788	663,586
Cash and cash equivalents at beginning of year	1,077,429	845,641	182,055
Cash and cash equivalents at end of year	1,601,232	1,077,429	845,641
Cash paid during the year for:
Interest, net of amount capitalized	147,550	128,567	143,187
Income taxes, net	$ 95,708	$ 204,818	$ 163,703

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 1,601,232	$ 1,077,429
Accounts receivable (less accumulated provision for doubtful accounts: $3,018 in 2015; $5,311 in 2014)	176,957	306,085
Derivative instruments, at fair value	417,397	458,460
Prepaid expenses and other	55,433	62,349
Total current assets	2,251,019	1,904,323
Property, plant and equipment	15,635,549	13,427,429
Less: accumulated depreciation and depletion	4,163,528	3,350,615
Net property, plant and equipment	11,472,021	10,076,814
Other assets	253,132	54,216
Total assets	13,976,172	12,035,353
Current liabilities:
Current portion of long-term debt	0	165,874
Credit facility borrowings	299,000	0
Accounts payable	291,550	444,077
Derivative instruments, at fair value	23,434	22,942
Other current liabilities	181,835	200,449
Total current liabilities	795,819	833,342
Long-term debt	2,793,343	2,793,479
Deferred income taxes	1,972,170	1,750,870
Other liabilities and credits	386,798	284,599
Total liabilities	5,948,130	5,662,290
Stockholders’ equity
Common stock, no par value, authorized 320,000 shares, shares issued: 158,347 in 2015 and 175,384 in 2014	2,153,280	1,895,632
Treasury stock, shares at cost: 5,793 in 2015 (including 292 held in rabbi trust) and 23,788 in 2014	(104,079)	(429,440)
Retained earnings	2,982,212	2,917,129
Accumulated other comprehensive income	46,378	199,494
Total common stockholders’ equity	5,077,791	4,582,815
Noncontrolling interests in consolidated subsidiaries	2,950,251	1,790,248
Total equity	8,028,042	6,373,063
Total liabilities and equity	$ 13,976,172	$ 12,035,353

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable, accumulated provision for doubtful accounts	$ 3,018	$ 5,311
Common stock, par value (in dollars per share)	$ 0	$ 0
Common stock, authorized shares	320,000,000	320,000,000
Common stock, shares issued	158,347,000	175,384,000
Treasury stock, shares	5,793,000	23,788,000
Treasury stock, shares held in rabbi trust	292,000

STATEMENTS OF CONSOLIDATED EQUI

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Thousands	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests in Consolidated Subsidiaries
Beginning Balance (in shares) at Dec. 31, 2012		150,109,000
Beginning Balance at Dec. 31, 2012	$ 3,888,802	$ 1,308,771	$ 2,195,502	$ 99,547	$ 284,982
Increase (Decrease) in Stockholders' Equity
Net income	437,815		390,572		47,243
Net change in cash flow hedges:
Natural gas, net of tax	(76,489)			(76,489)
Interest rate, net of tax	144			144
Pension and other post-retirement benefits liability adjustment, net of tax	21,501			21,501
Dividends ($0.12 per share)	(18,094)		(18,094)
Stock-based compensation plans, net (in shares)		775,000
Stock-based compensation plans, net	115,429	$ 114,975			454
Distributions to noncontrolling interests	(32,781)				(32,781)
Issuance of common units of EQT Midstream Partners, LP	529,442				529,442
Deferred taxes related to the public offering of common units of EQT Midstream Partners, LP	(1,641)	$ (1,641)
Ending Balance (in shares) at Dec. 31, 2013		150,884,000
Ending Balance at Dec. 31, 2013	$ 4,864,128	$ 1,422,105	2,567,980	44,703	829,340
Net change in cash flow hedges:
Common stock, authorized shares	320,000,000
Preferred stock, authorized shares	3,000,000
Preferred stock, shares issued	0
Net income	$ 510,990		386,965		124,025
Natural gas, net of tax	155,422			155,422
Interest rate, net of tax	145			145
Pension and other post-retirement benefits liability adjustment, net of tax	(776)			(776)
Dividends ($0.12 per share)	(18,207)		(18,207)
Stock-based compensation plans, net (in shares)		1,012,000
Stock-based compensation plans, net	59,081	$ 56,846			2,235
Distributions to noncontrolling interests	(67,819)				(67,819)
Issuance of common units of EQT Midstream Partners, LP	902,467				902,467
Repurchase and retirement of common stock (in shares)		(300,000)
Repurchase and retirement of common stock	(32,368)	$ (12,759)	(19,609)
Ending Balance (in shares) at Dec. 31, 2014		151,596,000
Ending Balance at Dec. 31, 2014	$ 6,373,063	$ 1,466,192	2,917,129	199,494	1,790,248
Net change in cash flow hedges:
Common stock, authorized shares	320,000,000
Preferred stock, authorized shares	3,000,000
Preferred stock, shares issued	0
Net income	$ 321,886		85,171		236,715
Natural gas, net of tax	(152,359)			(152,359)
Interest rate, net of tax	144			144
Pension and other post-retirement benefits liability adjustment, net of tax	(901)			(901)
Dividends ($0.12 per share)	(18,310)		(18,310)
Stock-based compensation plans, net (in shares)		996,000
Stock-based compensation plans, net	78,434	$ 77,378			1,056
Distributions to noncontrolling interests	(121,759)				(121,759)
Issuance of common units of EQT Midstream Partners, LP	1,182,002				1,182,002
Sale of common units of EQT GP Holdings, LP	673,964				673,964
Changes in ownership of consolidated subsidiaries	(304,747)	$ 507,228			(811,975)
Repurchase and retirement of common stock (in shares)		(38,000)
Repurchase and retirement of common stock	(3,375)	$ (1,597)	(1,778)
Ending Balance (in shares) at Dec. 31, 2015		152,554,000
Ending Balance at Dec. 31, 2015	$ 8,028,042	$ 2,049,201	$ 2,982,212	$ 46,378	$ 2,950,251
Net change in cash flow hedges:
Common stock, authorized shares	320,000,000
Preferred stock, authorized shares	3,000,000
Preferred stock, shares issued	0

STATEMENTS OF CONSOLIDATED EQU9

STATEMENTS OF CONSOLIDATED EQUITY (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Stockholders' Equity [Abstract]
Natural gas, tax (benefit)	$ (102,271)	$ 102,850	$ (50,200)
Interest rate, tax	100	104	63
Pension and other post-retirement benefits liability adjustment, tax expense (benefit)	$ 564	$ 515	$ (16,115)
Dividends (in dollars per share)	$ 0.12	$ 0.12	$ 0.12
Distributions to noncontrolling interests (in dollars per share)		$ 2.02	$ 1.55
Common stock, authorized shares	320,000,000	320,000,000	320,000,000
Preferred stock, authorized shares	3,000,000	3,000,000	3,000,000
Preferred stock, shares issued	0	0	0
Preferred shares, shares outstanding	0	0	0
EQM
Distributions to noncontrolling interests (in dollars per share)	$ 2.505
EQGP
Distributions to noncontrolling interests (in dollars per share)	$ 0.15139

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which a controlling interest is held (EQT or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. The results of EQT GP Holdings, LP (EQGP) and EQT Midstream Partners, LP (EQM) are both consolidated in the Company’s financial statements. The Company records the noncontrolling interests of the public limited partners in its financial statements. Segments: Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and which are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources. The Company reports its operations in two segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas, natural gas liquids (NGLs) and a limited amount of crude oil, primarily in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, transmission, storage and marketing activities of the Company, including ownership and operation of EQGP and EQM. Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in the United States. Reclassification: Certain previously reported amounts have been reclassified to conform to the current year presentation. Use of Estimates: The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates. Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense. Inventories: Generally, the Company’s inventory balance consists of natural gas stored underground or in pipelines and materials and supplies recorded at the lower of average cost or market. During the year ended December 31, 2015, the Company recorded no lower of cost or market adjustments related to inventory. During the years ended December 31, 2014 and 2013, the Company recorded losses for lower of cost or market adjustments of $3.2 million and $0.4 million , respectively, which became part of the average cost of the inventory. Property, Plant and Equipment: The Company’s property, plant and equipment consist of the following: As of December 31, 2015 2014 (Thousands) Oil and gas producing properties, successful efforts method $ 11,816,769 $ 10,082,825 Accumulated depreciation and depletion (3,425,618 ) (2,693,535 ) Net oil and gas producing properties 8,391,151 7,389,290 Midstream plant 3,703,994 3,234,370 Accumulated depreciation and amortization (685,398 ) (606,998 ) Net midstream plant 3,018,596 2,627,372 Other properties, at cost less accumulated depreciation 62,274 60,152 Net property, plant and equipment $ 11,472,021 $ 10,076,814 The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, the cost of productive wells, wells and related equipment, development dry holes, as well as productive acreage, including productive mineral interest, are capitalized and depleted using the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $114.4 million , $108.5 million and $93.5 million in 2015 , 2014 and 2013 , respectively. The Company capitalized $35.8 million , $35.0 million and $22.9 million of interest relative to Marcellus and Utica well development in 2015 , 2014 and 2013 , respectively. Depletion expense is calculated based on the actual production multiplied by the applicable depletion rate per unit. The depletion rates are derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves for lease costs and well costs separately. Costs of exploratory dry holes, exploratory geological and geophysical activities, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s producing oil and gas properties consist of producing gas properties which were depleted at an overall average rate of $1.18 per Mcfe, $1.22 per Mcfe and $1.50 per Mcfe for the years ended December 31, 2015 , 2014 and 2013 , respectively. The carrying values of the Company’s proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its oil and gas properties and compares these estimates to the carrying values of the properties. The estimated future cash flows used to test those properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable and possible reserves, utilizing assumptions generally consistent with the assumptions utilized by the Company's management for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil, adjusted accordingly for basis differentials, future operating costs and inflation, some of which are interdependent. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate and other assumptions that marketplace participants would use in their estimates of fair value. Due to the decline in commodity prices during 2015 and 2014, there were indications that the carrying values of certain of the Company’s oil and gas producing properties were impaired and future undiscounted cash flows attributed to these assets indicated their carrying amounts were not expected to be fully recovered. Their fair value was measured using an income approach based upon estimates of future production levels, commodity prices, operating costs and discount rates. The future production levels, future commodity prices, which were inflated for periods after the five -year forward price curve and included observed basis differentials and contractual transportation costs, future operating costs, which were inflated consistent with price assumptions, as well as the assumed market participant discount rate, which was estimated to be a rate of 12% , were considered to be significant unobservable inputs in the Company's calculation of fair value. As a result, valuation of the impaired assets was considered to be a Level 3 fair value measurement. For the years ended December 31, 2015 and 2014, EQT Production recognized pretax impairment charges on proved oil and gas properties of $98.6 million and $180.7 million , respectively, which are included in impairment of long-lived assets in the Statements of Consolidated Income. The 2015 impairment included a charge of $94.3 million to record the proved properties in the Permian Basin of Texas at a fair value of $44.8 million and a charge of $4.3 million to record the proved properties in the Utica Shale of Ohio at a fair value of $5.7 million . After this charge to the Permian assets, the carrying value of Permian properties as of December 31, 2015 was approximately $345 million , including approximately $300 million of undeveloped properties. Because the estimated future undiscounted cash flows from the Company’s proved oil and gas properties in the Marcellus play and the non-core Huron and Coalbed Methane plays exceeded the carrying values of the respective properties, the Company did not recognize an impairment charge in 2015 related to these oil and gas properties. The 2014 impairment included charges of $105.2 million to record the proved properties in the Permian Basin of Texas at a fair value of $109.2 million and $75.5 million to record the proved properties in the Utica Shale of Ohio at a fair value of $7.4 million . The 2015 and 2014 impairments on proved properties in the Permian Basin of Texas were due to a decline in commodity prices. The 2015 and 2014 impairments in the Utica Shale of Ohio were a result of insufficient recovery of hydrocarbons to support continued development, along with the decline in commodity prices. For the year ended December 31, 2013, the Company did not recognize impairment charges on proved oil and gas properties. 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 brought about by 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, the related costs are expensed in the period in which that determination is made. For the years ended December 31, 2015 and 2014, EQT Production recorded unproved property impairments of $19.7 million and $86.6 million , respectively, which are included in impairment of long-lived assets in the Statements of Consolidated Income. For the year ended December 31, 2013, the Company did not recognize impairment charges on unproved oil and gas properties. The unproved property impairment in 2015 related to the Company’s non-core Marcellus acreage, based on the Company’s decision to focus near-term development on its core Marcellus and deep Utica acreage. The unproved property impairment in 2014 related to the Company’s decision to stop development of properties in its Utica Shale of Ohio. In addition, unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling of $37.4 million , $14.6 million and $14.2 million are included in exploration expense of EQT Production for the years ended December 31, 2015, 2014 and 2013, respectively. Unproved properties had a net book value of $898.3 million and $824.5 million at December 31, 2015 and 2014 , respectively. At December 31, 2014, the Company had $9.0 million of capitalized exploratory well costs that were pending the determination of proved reserves. These exploratory well costs were reclassified to wells, equipment and facilities during the third quarter of 2015 upon the successful completion of the Company’s first deep Utica well in Pennsylvania. During 2015, the Company drilled one exploratory dry hole within its non-core acreage and the related expenditures have been included within exploration expense in the Statements of Consolidated Income as of December 31, 2015. There were no capitalized exploratory wells costs at December 31, 2015 and 2013. Midstream property, plant and equipment is carried at cost. Depreciation is calculated using the straight-line method based on estimated service lives. Midstream property consists largely of gathering and transmission systems ( 25 - 60 year estimated service life), buildings ( 35 year estimated service life), office equipment ( 3 - 7 year estimated service life), vehicles ( 5 year estimated service life), and computer and telecommunications equipment and systems ( 3 - 7 year estimated service life). Major maintenance projects that do not increase the overall life of the related assets are expensed. When major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. When events or changes in circumstances indicate that the carrying amount of any long-lived asset other than proved and unproved oil and gas properties may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company records an impairment loss equal to the difference between the carrying value and fair value of the assets. During the year ended December 31, 2015, EQT Midstream recorded an impairment of long-lived assets of approximately $4.2 million related to an asset that will not be utilized in Midstream operations. No impairment of any long-lived asset other than proved and unproved oil and gas properties was recorded in 2014 or 2013. Sales and Retirements Policies: No gain or loss is recognized on the partial sale of proved developed oil and gas reserves unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds. Regulatory Accounting: EQT Midstream’s regulated operations include interstate pipeline operations subject to regulation by the Federal Energy Regulatory Commission (FERC) and certain FERC-regulated gathering operations. The application of regulatory accounting allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates. The following table presents the total regulated net revenues and operating expenses included in the operations of EQT Midstream: Years Ended December 31, 2015 2014 2013 (Thousands) Net revenues $ 309,984 $ 267,997 $ 184,767 Operating expenses $ 109,954 $ 89,617 $ 71,517 The following table presents the regulated net property, plant and equipment included in EQT Midstream: As of December 31, 2015 2014 (Thousands) Property, plant & equipment $ 1,356,206 $ 1,160,696 Accumulated depreciation and amortization (193,349 ) (188,884 ) Net property, plant & equipment $ 1,162,857 $ 971,812 The regulatory assets associated with deferred taxes of $73.1 million and $15.2 million as of December 31, 2015 and 2014 , respectively, are included in other assets in the Consolidated Balance Sheets and primarily represent deferred income taxes recoverable through future rates related to a historical deferred tax position and the equity component of allowance for funds used during construction (AFUDC). The Company expects to recover the amortization of the deferred tax position ratably over the corresponding life of the underlying assets that created the difference. The deferred tax regulatory asset associated with AFUDC represents the offset to the deferred taxes associated with the equity component of AFUDC of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes will be collected through rates over the depreciable lives of the long-lived assets to which they relate. Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Hedge and Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Company's Board of Directors. The HFRC is composed of the chief executive officer, the president, the chief financial officer and other officers of the Company. In regards to commodity price risk, the financial instruments currently utilized by the Company are primarily fixed price swap agreements and collar agreements which may require payments to or receipt of payments from counterparties based on the differential between two prices for the commodity. The Company also uses a limited number of other contractual agreements in implementing its commodity hedging strategy. The Company may execute interest rate swap agreements to hedge exposures to fluctuations in interest rates. The Company does not enter into derivative instruments for trading purposes. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (OCI), net of tax, and is subsequently reclassified into the Statements of Consolidated Income in the same period or periods during which the hedged forecasted transaction affects earnings. The Company assesses the effectiveness of hedging relationships, as determined by the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, both at the inception of the hedge and on an on-going basis. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, the ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. Effective December 31, 2014, the Company elected to de-designate all derivative commodity instruments that were designated and qualified as cash flow hedges. If a cash flow hedge was terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of deferred gain or loss within accumulated OCI recorded up to that date remained deferred, provided that the forecasted transaction remained probable of occurring. Subsequent changes in fair value of a de-designated derivative instrument are recorded in earnings. The amount recorded in accumulated OCI is primarily related to instruments that were previously designated as cash flow hedges. Any changes in fair value of derivative instruments that have not been designated as hedges are recognized within operating revenues in the Statements of Consolidated Income each period. The Company reports all gains and losses on its natural gas derivative commodity instruments net as operating revenues on its Statements of Consolidated Income. AFUDC: Carrying costs for the construction of certain long-term assets are capitalized by the Company and amortized over the related assets’ estimated useful lives. The capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these assets which are subject to regulation by the FERC. The debt portion of AFUDC is calculated based on the average cost of debt and is included as a reduction of interest expense in the Statements of Consolidated Income. AFUDC interest costs capitalized were $1.6 million , $1.0 million and $0.5 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The equity portion of AFUDC is calculated using the most recent equity rate of return approved by the applicable regulator. Equity amounts capitalized are included in other income in the Statements of Consolidated Income. The AFUDC equity amounts capitalized were $6.3 million , $3.2 million and $1.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Other Current Liabilities: Other current liabilities as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 (Thousands) Incentive compensation $ 67,049 $ 70,826 Taxes other than income 44,925 52,035 Accrued interest payable 36,330 37,349 All other accrued liabilities 33,531 40,239 Total other current liabilities $ 181,835 $ 200,449 Revenue Recognition: Revenue is recognized for production and gathering activities when deliveries of natural gas, NGLs and crude oil occur. Revenues from natural gas transmission and storage activities are recognized in the period the service is provided. Reservation revenues on firm contracted capacity are recognized over the contract period based on the contracted volume regardless of the amount of natural gas that is transported. The Company reports revenue from all energy trading contracts net in the Statements of Consolidated Income, regardless of whether the contracts are physically or financially settled. Contracts which result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are considered normal purchases and sales and are not subject to derivative accounting. Revenues from these contracts are recognized at contract value when delivered and are reported in operating revenues. The Company reports all gains and losses on its derivative commodity instruments net as operating revenues on its Statements of Consolidated Income. The Company accounts for gas-balancing arrangements under the entitlement method. The Company uses the gross method to account for overhead cost reimbursements from joint operating partners. During periods in which rates are subject to refund as a result of a pending rate case, the Company records revenue at the rates which are pending approval but reserves these revenues to the level of previously approved rates until the final settlement of the rate case. Investments in Consolidated Affiliates : In January 2015, the Company formed EQGP to own the Company's partnership interests in EQM. On May 15, 2015, EQGP completed an initial public offering (IPO) of 26,450,000 common units representing limited partner interests in EQGP, which represented 9.9% of EQGP's outstanding limited partner interests. The Company retained 239,715,000 common units, which represented a 90.1% limited partner interest, and the entire non-economic general partner interest, in EQGP. As of December 31, 2015, EQGP owned 21,811,643 EQM common units, representing a 27.6% limited partner interest in EQM; 1,443,015 EQM general partner units, representing a 1.8% general partner interest in EQM; and all of EQM's incentive distribution rights. EQGP and EQM are both consolidated in the Company's consolidated financial statements and the Company records the noncontrolling interests of the public limited partners in its financial statements. See Notes 3 and 4. Investments in Nonconsolidated Affiliates: Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership), but which the Company does not control, are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company evaluates its investments in nonconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, the Company compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. See Note 11. Unamortized Debt Discount and Issuance Expense: Discounts and expenses incurred with the issuance of long-term debt are amortized over the term of the debt. These amounts are presented as a reduction of long-term debt on the accompanying Consolidated Balance Sheets. See Note 13. Transportation and Processing: Third-party costs incurred to gather, process and transport gas produced by EQT Production to market sales points are recorded as a portion of transportation and processing costs in the Statements of Consolidated Income. The Company markets some transportation for resale and the related costs are not incurred to transport gas produced by EQT Production. These transportation costs are reflected as a deduction from operating revenues. Income Taxes: The Company files a consolidated federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes, exclusive of amounts recorded in OCI. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, income from discontinued operations and items charged or credited directly to stockholders’ equity. Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, the Company utilizes a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense. Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the creditworthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense in the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts. Earnings Per Share (EPS): Basic EPS are computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS are computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. See Note 16. Asset Retirement Obligations : The Company accrues a liability for legal asset retirement obligations based on an estimate of the timing and amount of settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are spud. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets. The Company is required to operate and maintain its natural gas pipeline and storage systems, and intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company believes that the substantial majority of its natural gas pipeline and storage system assets have indeterminate lives. The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations which are included in other liabilities and credits in the Consolidated Balance Sheets. The Company does not have any assets that are legally restricted for purposes of settling these obligations. Years Ended December 31, 2015 2014 (Thousands) Asset retirement obligation as of beginning of period $ 140,086 $ 116,045 Accretion expense 10,646 9,420 Liabilities incurred 2,251 16,953 Liabilities settled (5,027 ) (14,025 ) Change in estimates 20,186 11,693 Asset retirement obligation as of end of period $ 168,142 $ 140,086 In connection with the exchange of certain assets with Range Resources Corporation (Range) (see Note 8 for additional information), the Company settled $7.7 million and incurred $14.2 million of asset retirement obligation liabilities during the year ended December 31, 2014. These amounts are included in the respective captions in the table above. Self-Insurance: The Company is self-insured for certain losses related to workers’ compensation and maintains a self-insured retention for general liability, automobile liability, environmental liability and other casualty coverage. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims, differ from estimates. Accumulated other comprehensive income: The components of accumulated OCI, net of tax, are as follows: As of December 31, 2015 2014 (Thousands) Net gain from natural gas hedging transactions $ 64,762 $ 217,121 Net loss from interest rate swaps (843 ) (987 ) Pension and other post-retirement benefits liability adjustment (17,541 ) (16,640 ) Accumulated OCI $ 46,378 $ 199,494 Noncontrolling interests: Noncontrolling interests represent third-party equity ownership in EQGP and EQM and are presented as a component of equity in the Consolidated Balance Sheets. In the Statements of Consolidated Income, noncontrolling interests reflect the allocation of earnings to third-party investors. See Notes 3 and 4 for further discussion of noncontrolling interests related to EQGP and EQM. Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers . The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers - Deferral of the Effective Date which approved a one year deferral of ASU 2014-09 for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations On December 17, 2013, the Company and its indirect wholly owned subsidiary Distribution Holdco, LLC completed the disposition of their ownership interests in Equitable Gas Company, LLC (Equitable Gas) and Equitable Homeworks, LLC (Homeworks) to PNG Companies LLC (the Equitable Gas Transaction). Equitable Gas and Homeworks comprised substantially all of the Company’s previously reported Distribution segment. The financial information of Equitable Gas and Homeworks is reflected as discontinued operations for all periods presented in these financial statements. The financial results for 2013 have been recast to reflect the presentation of discontinued operations. During the year ended December 31, 2014, the Company received additional cash proceeds of $7.4 million as a result of post-closing purchase price adjustments for the Equitable Gas Transaction. The Company recognized an additional gain of $2.9 million for the year ended December 31, 2014, included in income from discontinued operations, net of tax, in the Statements of Consolidated Income. As consideration for the Equitable Gas Transaction, the Company received total cash proceeds of $748.0 million , select midstream assets (including the Allegheny Valley Connector) with a fair value of $140.9 million and other contractual assets with a fair value of $32.5 million . During the year ended December 31, 2013, the Company recognized a gain on the sale of $43.8 million , subject to customary post-closing adjustments. The gain is net of tax expense of $122.5 million and is included in income from discontinued operations, net of tax, in the Statements of Consolidated Income. The following table summarizes the components of discontinued operations activity: Years Ended December 31, 2015 2014 2013 (Thousands) Operating revenues $ — $ — $ 332,947 Income from discontinued operations before income taxes — 2,377 251,378 Income taxes — 1,006 159,535 Income from discontinued operations, net of tax $ — $ 1,371 $ 91,843 The Company incurred $8.1 million of transaction costs related to the Equitable Gas Transaction for the year ended December 31, 2013, which are included in the results of discontinued operations. The Company also recognized a $51.6 million write off of income tax related regulatory assets (net of related deferred taxes) through income tax expense in discontinued operations in 2013.

EQT GP Holdings, LP

EQT GP Holdings, LP	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
EQT GP Holdings, LP	EQT GP Holdings, LP In January 2015, the Company formed EQGP, a Delaware limited partnership, to own the Company's partnership interests in EQM. In April 2015, EQT Midstream Investments, LLC, an indirect wholly owned subsidiary of the Company that held EQT's EQM common units, merged with and into EQGP, and EQT Gathering Holdings, LLC (EQT Gathering Holdings), an indirect wholly owned subsidiary of EQT, contributed 100% of the outstanding limited liability company interests in EQT Midstream Services, LLC, EQM's general partner, to EQGP. As a result of these restructuring transactions, EQGP owned the following EQM partnership interests as of December 31, 2015 , which represent EQGP's only cash-generating assets: 21,811,643 EQM common units, representing a 27.6% limited partner interest in EQM; 1,443,015 EQM general partner units, representing a 1.8% general partner interest in EQM; and all of EQM's incentive distribution rights, or IDRs, which entitle EQGP to receive up to 48.0% of all incremental cash distributed in a quarter after $0.5250 has been distributed in respect of each common unit and general partner unit of EQM for that quarter. The Company is the ultimate parent company of EQGP and EQM. On May 15, 2015, EQGP completed an underwritten IPO of 26,450,000 common units representing limited partner interests in EQGP, which represented 9.9% of EQGP's outstanding limited partner interests. The Company retained 239,715,000 common units, which represented a 90.1% limited partner interest, and the entire non-economic general partner interest, in EQGP. EQT Gathering Holdings, as the selling unitholder, sold all of the EQGP common units in the offering, resulting in net proceeds to the Company of approximately $674.0 million after deducting the underwriters' discount of approximately $37.5 million and structuring fees of approximately $2.7 million . EQGP did not receive any of the proceeds from, or incur any expenses in connection with, EQGP's IPO. The Company continues to consolidate the results of EQGP, but records an income tax provision only as to its ownership percentage. The Company records the noncontrolling interest of the EQGP public limited partners in its financial statements. In connection with the EQGP IPO, the Company recorded a $320.4 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $512.9 million and an increase to deferred tax liability of $192.5 million . On January 21, 2016, the Board of Directors of EQGP's general partner declared a cash distribution to EQGP's unitholders for the fourth quarter of 2015 of $0.122 per common unit, or approximately $32.5 million . The distribution will be paid on February 22, 2016 to unitholders of record, including the Company, at the close of business on February 1, 2016. Net income attributable to noncontrolling interests (i.e., to the EQGP limited partner interests not owned by the Company and the EQM limited partner interests not owned by EQGP) was $236.7 million for the year ended December 31, 2015. Net income attributable to noncontrolling interests (i.e., to the EQM limited partner interests not owned by the Company) was $124.0 million and $47.2 million for the years ended December 31, 2014 and 2013, respectively.

EQT Midstream Partners, LP

EQT Midstream Partners, LP	12 Months Ended
	Dec. 31, 2015
EQT Midstream Partners, LP
EQT Midstream Partners, LP	EQT Midstream Partners, LP In January 2012, the Company formed EQM to own, operate, acquire and develop midstream assets in the Appalachian Basin. EQM provides midstream services to the Company and other third parties. EQM is consolidated in the Company's consolidated financial statements. The Company records the noncontrolling interest of the EQM public limited partners in its financial statements. In connection with EQM's IPO in July 2012, EQM issued 17,339,718 subordinated units of EQM to the Company. On February 17, 2015, the subordinated units converted into common units representing limited partner interests in EQM on a one -for-one basis as a result of satisfaction of certain conditions for termination of the subordination period set forth in EQM's partnership agreement. On May 7, 2014, EQT Gathering, LLC, an indirect wholly owned subsidiary of the Company, contributed the Jupiter gathering system to EQM Gathering in exchange for $1.18 billion (the Jupiter Transaction). On May 7, 2014, EQM completed an underwritten public offering of 12,362,500 common units, which included the full exercise of the underwriters’ overallotment option. EQM received net proceeds of approximately $902.5 million from the offering, after deducting the underwriters’ discount and offering expenses of approximately $34.0 million . In August 2014, EQM issued 4.00% Senior Notes due 2024 ( 4.00% Senior Notes) in the aggregate principal amount of $500.0 million . The indenture governing the 4.00% Senior Notes contains covenants that limit EQM’s ability to, among other things, incur certain liens securing indebtedness, engage in certain sale and leaseback transactions, and enter into certain consolidations, mergers, conveyances, transfers or leases of all or substantially all of EQM’s assets. The payment obligations under the 4.00% Senior Notes were unconditionally guaranteed by each of EQM’s subsidiaries that guaranteed EQM’s credit facility (other than EQT Midstream Finance Corporation). The subsidiary guarantors were released from their guarantees of the 4.00% Senior Notes in January 2015 in connection with an amendment to EQM’s credit facility. On March 10, 2015, the Company and certain subsidiaries of the Company entered into a contribution and sale agreement (Contribution Agreement) with EQM and EQM Gathering Opco, LLC (EQM Gathering), an indirect wholly owned subsidiary of EQM. Pursuant to the Contribution Agreement, on March 17, 2015, a subsidiary of the Company contributed the Northern West Virginia Marcellus gathering system to EQM Gathering in exchange for total consideration of $925.7 million , consisting of $873.2 million in cash, 511,973 EQM common units and 178,816 EQM general partner units (the NWV Gathering Transaction). EQM Gathering is consolidated by the Company as it is still controlled by the Company. On April 15, 2015, pursuant to the Contribution Agreement, the Company transferred a preferred interest in EQT Energy Supply, LLC, an indirect subsidiary of the Company, to EQM in exchange for total consideration of $124.3 million . EQT Energy Supply, LLC generates revenue from services provided to a local distribution company. On March 17, 2015 , EQM completed an underwritten public offering of 8,250,000 common units. On March 18, 2015 , the underwriters exercised their option to purchase 1,237,500 additional common units on the same terms as the offering. EQM received net proceeds of $696.6 million from the offering after deducting the underwriters’ discount and offering expenses of $24.5 million . In connection with the offering, the Company recorded a $122.3 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $195.8 million and an increase to deferred tax liability of $73.5 million . EQM used the proceeds from the offering to fund a portion of the purchase price for the NWV Gathering Transaction. On March 30, 2015, the Company assigned 100% of the membership interest in MVP Holdco, LLC (MVP Holdco), an indirect wholly owned subsidiary of the Company that as of February 11, 2016 owned a 45.5% interest (the MVP Interest) in Mountain Valley Pipeline, LLC (MVP Joint Venture), to EQM for $54.2 million , which represented EQM's reimbursement to the Company for 100% of the capital contributions made by the Company to the MVP Joint Venture as of March 30, 2015. The MVP Joint Venture plans to construct the Mountain Valley Pipeline (MVP), an estimated 300 -mile natural gas interstate pipeline spanning from northern West Virginia to southern Virginia. The MVP Joint Venture has secured a total of 2.0 Bcf per day of 20 -year firm capacity commitments, including a 1.29 Bcf per day firm capacity commitment by the Company. The MVP Joint Venture submitted the MVP certificate application to the FERC in October 2015 and anticipates receiving the certificate in the fourth quarter of 2016. Subject to FERC approval, construction is scheduled to begin shortly thereafter and the pipeline is expected to be in-service during the fourth quarter of 2018. The MVP Joint Venture has been determined to be a variable interest entity because the MVP Joint Venture has insufficient equity to finance activities during the construction stage of the project. EQM is not the primary beneficiary because it does not have the power to direct the activities of the MVP Joint Venture that most significantly impact its economic performance. Beginning on the date it was assumed from the Company, EQM accounted for the MVP Interest as an equity method investment as EQM has the ability to exercise significant influence over operating and financial policies of the MVP Joint Venture. On January 21, 2016, affiliates of Consolidated Edison, Inc. (ConEd) acquired a 12.5% interest in the MVP Joint Venture and entered into 20 -year firm capacity commitments for approximately 0.25 Bcf per day on both the MVP and EQM’s transmission system (ConEd Transaction). As a result of the ConEd Transaction, EQM’s interest in the MVP Joint Venture decreased by 8.5% to 45.5% , and during the first quarter of 2016, ConEd reimbursed EQM for $12.5 million related to the proportionate reduction in EQM’s interest in the joint venture. ConEd has the right to terminate its purchase of the interest in the MVP Joint Venture and be reimbursed for the purchase price and all capital contributions made to the MVP Joint Venture for a period ending no later than December 31, 2016. During the second half of 2015 , EQM entered into an equity distribution agreement that established an "At the Market" (ATM) common unit offering program, pursuant to which a group of managers, acting as EQM's sales agents, may sell EQM common units having an aggregate offering price of up to $750 million (the $750 million ATM Program). EQM issued 1,162,475 common units at an average price per unit of $74.92 during the six months ended December 31, 2015 . EQM received net proceeds of approximately $85.5 million after deducting commissions of approximately $0.9 million and other offering expenses of approximately $0.7 million . EQM used the net proceeds from the sales for general partnership purposes. In connection with the offerings, the Company recorded a $12.4 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $19.8 million and an increase to deferred tax liability of $7.4 million . On November 16, 2015, EQM completed an underwritten public offering of 5,650,000 common units. EQM received net proceeds of $399.9 million from the offering after deducting the underwriters’ discount and offering expenses of $5.7 million . EQM will use the net proceeds from the offering for general partnership purposes, including to fund a portion of EQM's anticipated 2016 capital expenditures related to transmission and gathering expansion projects and to repay amounts outstanding under EQM's credit facility. In connection with the offering, the Company recorded a $52.1 million gain to additional paid-in-capital, a decrease in noncontrolling interest in consolidated subsidiary of $83.5 million and an increase to deferred tax liability of $31.3 million . On January 21, 2016, the Board of Directors of EQM’s general partner declared a cash distribution to EQM’s unitholders for the fourth quarter of 2015 of $0.71 per common unit. The cash distribution will be paid on February 12, 2016 to unitholders of record, including EQGP, at the close of business on February 1, 2016. EQGP will receive approximately $33.0 million consisting of $15.5 million in respect of its limited partner interest, $1.3 million in respect of its general partner interest and $16.2 million in respect of its IDRs in EQM.

Financial Information by Busine

Financial Information by Business Segment	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Financial Information by Business Segment	Financial Information by Business Segment Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and which are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources. The Company reports its operations in two segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas, NGLs and a limited amount of crude oil in the Appalachian and Permian Basins. The EQT Midstream segment’s operations include the natural gas gathering, transmission, storage and marketing activities of the Company, including ownership and operation of EQGP and EQM. EQT Production segment revenues in the table below are reduced by charges from EQT Midstream for midstream services. On the Statements of Consolidated Income, the sales of natural gas, oil and NGLs are not reduced by these charges. Operating segments are evaluated on their contribution to the Company’s consolidated results based on operating income. Other income, interest and income taxes are managed on a consolidated basis. Headquarters’ costs are billed to the operating segments based upon an allocation of the headquarters’ annual operating budget. Differences between budget and actual headquarters’ expenses are not allocated to the operating segments. Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in United States. Years Ended December 31, 2015 2014 2013 (Thousands) Revenues from external customers, including affiliates: EQT Production $ 1,540,889 $ 1,813,292 $ 1,310,938 EQT Midstream 807,904 699,083 614,042 Less intersegment revenues, net (a) (9,031 ) (42,665 ) (62,969 ) Total $ 2,339,762 $ 2,469,710 $ 1,862,011 Operating income: EQT Production (b) $ 104,865 $ 505,950 $ 371,245 EQT Midstream (b) 473,378 384,309 328,782 Unallocated expenses (c) (15,104 ) (36,864 ) (45,423 ) Total operating income $ 563,139 $ 853,395 $ 654,604 Reconciliation of operating income to income from continuing operations: Other income $ 9,953 $ 6,853 $ 9,242 Interest expense 146,531 136,537 142,688 Income tax expense 104,675 214,092 175,186 Income from continuing operations $ 321,886 $ 509,619 $ 345,972 As of December 31, 2015 2014 2013 (Thousands) Segment assets: EQT Production $ 8,995,853 $ 8,153,199 $ 6,359,065 EQT Midstream 3,226,138 2,709,052 2,514,429 Total operating segments 12,221,991 10,862,251 8,873,494 Headquarters assets, including cash and short-term investments 1,754,181 1,173,102 892,413 Total assets $ 13,976,172 $ 12,035,353 $ 9,765,907 (a) Eliminates intercompany natural gas sales from EQT Production to EQT Midstream. (b) Gains on sales / exchanges of assets of $27.4 million and $6.8 million are included in EQT Production and EQT Midstream operating income, respectively, for 2014. See Note 8. Impairment of long-lived assets of $118.3 million and $267.3 million are included in EQT Production operating income for 2015 and 2014, respectively. Impairment of long-lived assets of $4.2 million is included in EQT Midstream operating income for 2015. See Note 1 for a discussion of impairment of long-lived assets. (c) Unallocated expenses consist primarily of a $20.0 million contribution to the EQT Foundation in 2014, incentive compensation expense, and administrative costs. Years Ended December 31, 2015 2014 2013 (Thousands) Depreciation, depletion and amortization: EQT Production $ 723,448 $ 592,855 $ 578,641 EQT Midstream 95,280 87,034 75,032 Other 488 (591 ) (541 ) Total $ 819,216 $ 679,298 $ 653,132 Expenditures for segment assets: (d) EQT Production (e) $ 1,852,100 $ 2,441,486 $ 1,423,185 EQT Midstream 486,809 455,359 369,399 Other 5,505 3,341 4,292 Total $ 2,344,414 $ 2,900,186 $ 1,796,876 (d) Includes a portion of non-cash stock-based compensation expense and the impact of capital accruals. (e) Expenditures for segment assets in the EQT Production segment included $182.3 million , $724.4 million and $186.2 million for property acquisitions in 2015 , 2014 and 2013 , respectively. Included within the $724.4 million of property acquisitions for the year ended December 31, 2014 was $349.2 million of non-cash capital expenditures for the exchange of assets with Range (described in Note 8).

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments The Company’s primary market risk exposure is the volatility of future prices for natural gas and NGLs, which can affect the operating results of the Company primarily at EQT Production. The Company’s overall objective in its hedging program is to protect cash flows from undue exposure to the risk of changing commodity prices. The Company uses over the counter (OTC) derivative commodity instruments, primarily swap and collar agreements that are primarily placed with financial institutions. The creditworthiness of all counterparties is regularly monitored. The Company also uses exchange traded futures contracts that obligate the Company to buy or sell a designated commodity at a future date for a specified price and quantity at a specified location. Swap agreements involve payments to or receipts from counterparties based on the differential between two prices for the commodity. Collar agreements require the counterparty to pay the Company if the index price falls below the floor price and the Company to pay the counterparty if the index price rises above the cap price. The Company also engages in basis swaps to protect earnings from undue exposure to the risk of geographic disparities in commodity prices and interest rate swaps to hedge exposure to interest rate fluctuations on potential debt issuances. The Company has also engaged in a limited number of swaptions and call options. The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These derivative instruments are reported as either current assets or current liabilities due to their highly liquid nature. The Company can net settle its derivative instruments at any time. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument had been designated and qualified as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated OCI, net of tax, and is subsequently reclassified into the Statements of Consolidated Income in the same period or periods during which the forecasted transaction affects earnings. In conjunction with the exchange of assets with Range (see Note 8), the Company de-designated certain derivative instruments that were previously designated as cash flow hedges because it was probable that the forecasted transactions would not occur, resulting in a pre-tax gain of $28.0 million recorded within gain on sale / exchange of assets in the Statements of Consolidated Income for the year ended December 31, 2014. Any subsequent changes in fair value of these derivative instruments are recognized within operating revenues in the Statements of Consolidated Income each period. Historically, derivative commodity instruments used by the Company to hedge its exposure to variability in expected future cash flows associated with the fluctuations in the price of natural gas related to the Company’s forecasted sale of equity production and forecasted natural gas purchases and sales were designated and qualified as cash flow hedges. As of December 31, 2015 and 2014, the Company deferred net gains of $64.8 million and $217.1 million , respectively, in accumulated OCI, net of tax, related to the effective portion of the change in fair value of its derivative commodity instruments designated as cash flow hedges. Effective December 31, 2014, the Company elected to de-designate all cash flow hedges and discontinue the use of cash flow hedge accounting. As of December 31, 2015 and 2014, the forecasted transactions remained probable of occurring and as such, the amounts in accumulated OCI will continue to be reported in accumulated OCI and will be reclassified into earnings in future periods when the underlying hedged transactions occur. The forecasted transactions extend through December 2018. The Company estimates that approximately $54.7 million of net gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of December 31, 2015 will be recognized in earnings during the next twelve months due to the settlement of hedged transactions. As a result of the discontinuance of cash flow hedge accounting, beginning in 2015, all changes in fair value of the Company’s derivative instruments are recognized within operating revenues in the Statements of Consolidated Income. The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and sales exception and are not subject to derivative instrument accounting. Exchange-traded instruments are generally settled with offsetting positions. OTC arrangements require settlement in cash. Settlements of derivative commodity instruments are reported as a component of cash flows from operations in the accompanying Statements of Consolidated Cash Flows. Years Ended December 31, 2015 2014 2013 (Thousands) Commodity derivatives designated as cash flow hedges Amount of gain recognized in OCI (effective portion), net of tax $ — $ 156,207 $ 10,669 Amount of gain reclassified from accumulated OCI, net of tax, into gain on sale / exchange of assets and dispositions due to forecasted transactions probable to not occur — 16,735 — Amount of gain (loss) reclassified from accumulated OCI, net of tax, into operating revenues (effective portion) 152,359 (15,950 ) 87,158 Amount of gain (loss) recognized in operating revenues (ineffective portion) (a) — 24,774 (21,335 ) Interest rate derivatives designated as cash flow hedges Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion) $ (144 ) $ (145 ) $ (144 ) Commodity derivatives designated as fair value hedges (b) Amount of loss recognized in operating revenues for fair value commodity contracts $ — $ — $ (1,341 ) Fair value gain recognized in operating revenues for inventory designated as hedged item — — 386 Derivatives not designated as hedging instruments Amount of gain recognized in operating revenues $ 385,762 $ 80,942 $ 2,834 (a) No amounts were excluded from effectiveness testing of cash flow hedges. (b) For the year ended December 31, 2013, the net impact on operating revenues consisted of a $0.5 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $1.5 million loss due to changes in basis. The absolute quantities of the Company’s derivative commodity instruments totaled 676 Bcf and 624 Bcf as of December 31, 2015 and 2014 , respectively, and were primarily related to natural gas swaps, basis swaps and collars. The open positions at December 31, 2015 and 2014 had maturities extending through December 2019 and 2018, respectively. When the net fair value of any of the Company’s swap agreements represents a liability to the Company which is in excess of the agreed-upon threshold between the Company and the counterparty, the counterparty requires the Company to remit funds as a margin deposit for the derivative liability which is in excess of the threshold amount. The Company records these deposits as a current asset. When the net fair value of any of the Company’s swap agreements represents an asset to the Company which is in excess of the agreed-upon threshold between the Company and the counterparty, the Company requires the counterparty to remit funds as margin deposits in an amount equal to the portion of the derivative asset which is in excess of the threshold amount. The Company records a current liability for such amounts received. The Company had no such deposits in its Consolidated Balance Sheets as of December 31, 2015 or 2014. When the Company enters into exchange-traded natural gas contracts, exchanges may require the Company to remit funds to the corresponding broker as good-faith deposits to guard against the risks associated with changing market conditions. The Company must make such deposits based on an established initial margin requirement as well as the net liability position, if any, of the fair value of the associated contracts. The Company records these deposits as a current asset in the Consolidated Balance Sheets. In the case where the fair value of such contracts is in a net asset position, the broker may remit funds to the Company, in which case the Company records a current liability for such amounts received. The initial margin requirements are established by the exchanges based on the price, volatility and the time to expiration of the related contract. The margin requirements are subject to change at the exchanges’ discretion. The Company had no such deposits in its Consolidated Balance Sheets as of December 31, 2015. The Company recorded current assets of $0.1 million as of December 31, 2014 for such deposits in its Consolidated Balance Sheets. The Company has netting agreements with financial institutions and its brokers that permit net settlement of gross commodity derivative assets against gross commodity derivative liabilities. The table below reflects the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of December 31, 2015 and 2014 . As of December 31, 2015 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 417,397 $ (19,909 ) $ — $ 397,488 Liability derivatives: Derivative instruments, at fair value $ 23,434 $ (19,909 ) $ — $ 3,525 As of December 31, 2014 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 458,460 $ (22,810 ) $ — $ 435,650 Liability derivatives: Derivative instruments, at fair value $ 22,942 $ (22,810 ) $ (132 ) $ — Certain of the Company’s derivative instrument contracts provide that if the Company’s credit ratings by Standard & Poor’s Rating Services (S&P) or Moody’s Investor Services (Moody’s) are lowered below investment grade, additional collateral must be deposited with the counterparty. The additional collateral can be up to 100% of the derivative liability. As of December 31, 2015 , the aggregate fair value of all derivative instruments with credit risk-related contingent features that were in a net liability position was $4.8 million , for which the Company had no collateral posted on December 31, 2015 . If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on December 31, 2015 , the Company would not have been required to post any additional collateral under the agreements with the respective counterparties. Investment grade refers to the quality of the Company’s credit as assessed by one or more credit rating agencies. The Company’s senior unsecured debt was rated BBB by S&P and Baa3 by Moody’s at December 31, 2015 . On December 16, 2015, Moody's announced that it had placed 29 U.S. exploration and production companies, including the Company, under review for a downgrade due to the low commodity price environment. In order to be considered investment grade, the Company must be rated BBB- or higher by S&P and Baa3 or higher by Moody’s. Anything below these ratings is considered non-investment grade. Having a non-investment grade rating would result in greater borrowing costs and collateral requirements than would be available if all credit ratings were investment grade.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Company records its financial instruments, principally derivative instruments, at fair value in its Consolidated Balance Sheets. The Company estimates the fair value using quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use market-based parameters as inputs, including forward curves, discount rates, volatilities and nonperformance risk. Nonperformance risk considers the effect of the Company’s credit standing on the fair value of liabilities and the effect of the counterparty’s credit standing on the fair value of assets. The Company estimates nonperformance risk by analyzing publicly available market information, including a comparison of the yield on debt instruments with credit ratings similar to the Company’s or counterparty’s credit rating and the yield of a risk-free instrument and credit default swaps rates where available. The Company has categorized its assets and liabilities recorded at fair value into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities included in Level 1 include the Company’s futures contracts. Assets and liabilities in Level 2 primarily include the Company’s swap and collar agreements. There were no transfers between Level 1 and 2 during the periods presented. There were no transfers into or out of Level 3 during the periods presented. The Company recognizes transfers between Levels as of the actual date of the event or change in circumstances that caused the transfer. The fair value of the assets and liabilities included in Level 2 is based on standard industry income approach models that use significant observable inputs, including New York Mercantile Exchange (NYMEX) forward curves, LIBOR-based discount rates and basis forward curves. The Company’s collars and options are valued using standard industry income approach option models. The significant observable inputs utilized by the option pricing models include NYMEX forward curves, natural gas volatilities and LIBOR-based discount rates. The Company uses NYMEX forward curves to value futures, commodity swaps and collars. The NYMEX forward curves, LIBOR-based discount rates, natural gas volatilities and basis forward curves are validated to external sources at least monthly. The following assets and liabilities were measured at fair value on a recurring basis during the applicable period: Fair value measurements at reporting date using Description December 31, 2015 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 417,397 $ — $ 417,397 $ — Liabilities Derivative instruments, at fair value $ 23,434 $ — $ 23,434 $ — Fair value measurements at reporting date using Description December 31, 2014 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 458,460 $ — $ 458,460 $ — Liabilities Derivative instruments, at fair value $ 22,942 $ 132 $ 22,810 $ — The carrying value of cash equivalents, accounts receivable, amounts due to/from related parties and accounts payable approximate fair value due to the short-term maturity of the instruments. The carrying value of borrowings under EQM's credit facility approximates fair value as the interest rates are based on prevailing market rates. The Company estimates the fair value of its debt using its established fair value methodology. Because not all of the Company’s debt is actively traded, the fair value of the debt is a Level 2 fair value measurement. Fair value for non-traded debt obligations is estimated using a standard industry income approach model which utilizes a discount rate based on market rates for debt with similar remaining time to maturity and credit risk. The estimated fair value of total debt (including EQM’s long-term debt) on the Consolidated Balance Sheets at December 31, 2015 and 2014 was approximately $2.8 billion and $3.3 billion , respectively. The carrying value of total debt (including EQM's long-term debt) on the Consolidated Balance Sheets at December 31, 2015 and 2014 was approximately $2.8 billion and $3.0 billion , respectively. Refer to Note 13 for further information regarding the Company's debt as of December 31, 2015 and 2014. For information on the fair values of assets related to the impairment of proved and unproved oil and gas properties, assets acquired in the Range exchange, the assets acquired in the Chesapeake acquisition and the assets related to the defined benefit pension plan assets, see Notes 1, 8, 9 and Note 14, respectively.

Sales of Properties and Contrac

Sales of Properties and Contracts	12 Months Ended
	Dec. 31, 2015
Sales of Properties and Contracts
Sales of Properties and Contracts	Sales of Properties and Contracts On December 17, 2013, the Company executed the Equitable Gas Transaction. Refer to Note 2 for additional information. On December 31, 2013, the Company sold certain energy marketing contracts to a third party for $20.0 million . These contracts were natural gas sales agreements with approximately 1,000 customers with total volumes of approximately 12 Bcf in 2013. The Company received $18.0 million of cash on December 31, 2013 and the remaining $2.0 million in 2014. In conjunction with this transaction, the Company realized a pre-tax gain of $19.6 million in 2013. Assets acquired as part of the Equitable Gas Transaction included energy marketing contracts with approximately 50 customers valued at $5.0 million . On December 31, 2013, the Company sold these contracts to a third party for $5.0 million , which was received on December 31, 2013. In June 2014, the Company exchanged certain assets with Range. The Company received approximately 73,000 net acres and approximately 900 producing wells, most of which are vertical wells, in the Permian Basin of Texas. In exchange, Range received approximately 138,000 net acres in the Company’s Nora field of Virginia (Nora), the Company’s working interest in approximately 2,000 producing vertical wells in Nora, the Company’s 50% ownership interest in Nora Gathering, LLC (Nora LLC), which owns the supporting gathering system in Nora, and $167.3 million in cash. The Company previously recorded its 50% ownership interest in Nora LLC as a nonconsolidated investment in the Company’s Consolidated Balance Sheets. The fair value of the assets exchanged by the Company was approximately $516.5 million . Fair value of $318.3 million was allocated to the acquired acreage and $198.2 million was allocated to the acquired wells. The Company recorded a pre-tax gain of $34.1 million , which is included in gain on sale / exchange of assets in the Statements of Consolidated Income. The gain on sale / exchange of assets included a $28.0 million pre-tax gain related to the de-designation of certain derivative instruments that were previously designated as cash flow hedges because it was probable that the forecasted transactions would not occur. As the asset exchange qualified as a business combination under United States GAAP, the fair value of the acquired assets was determined using a discounted cash flow model under the market approach. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves, NYMEX forward pricing and comparable sales transactions, which classify the acquired assets as a Level 3 measurement.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions In June 2013, the Company acquired approximately 99,000 net acres in southwestern Pennsylvania and ten horizontal Marcellus wells, located in Washington County, Pennsylvania, from Chesapeake Energy Corporation and its partners (Chesapeake) for approximately $114.2 million . The acreage included 67,000 Marcellus acres, of which 42,000 acres were unlikely to be developed due to near-term lease expirations or a scattered footprint. Of the total purchase price, $57.2 million was allocated to the undeveloped acreage and $57.0 million was allocated to the acquired Marcellus wells. As the transaction qualified as a business combination under United States GAAP, the fair value of the acquired assets was determined using a market approach for the undeveloped acreage and a discounted cash flow model under the income approach for the wells. Significant unobservable inputs used in the analysis included the determination of estimated developed reserves and NYMEX forward pricing; as a result, valuation of the acquired assets was a Level 3 measurement.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Income tax expense (benefit) from continuing operations is summarized as follows: Years Ended December 31, 2015 2014 2013 (Thousands) Current: Federal $ 85,696 $ 164,935 $ 100,796 State 1,103 17,136 46,758 Subtotal 86,799 182,071 147,554 Deferred: Federal (109,642 ) 38,357 51,767 State 127,518 (6,336 ) (23,940 ) Subtotal 17,876 32,021 27,827 Amortization of deferred investment tax credit — — (195 ) Total income taxes $ 104,675 $ 214,092 $ 175,186 The current federal and state income tax expense primarily relates to federal alternative minimum tax (AMT) due to tax gains generated as a result of the net proceeds received from EQGP's IPO and the NWV Gathering Transaction in 2015, the Jupiter Transaction in 2014 and the merger of Sunrise Pipeline, LLC with and into Equitrans, L.P., an indirect wholly owned subsidiary of EQM (Equitrans), in 2013 (Sunrise Merger) as well as the Equitable Gas Transaction. The Protecting Americans from Tax Hikes (PATH) Act of 2015 was enacted on December 18, 2015 and retroactively and permanently extended the research and experimentation (R&E) tax credit for 2015 and forward. The PATH Act also reinstated and extended through the end of 2017 50% bonus depreciation phasing down to 40% in 2018 and 30% in 2019. The Tax Increase Prevention Act of 2014 was enacted on December 19, 2014 and retroactively extended the R&E tax credit for 2014 and reinstated 50% bonus depreciation for property placed in service in 2014. The impact of these law changes have been reflected in the Company’s financial statements. In 2013, the Commonwealth of Pennsylvania adopted multiple changes to the Commonwealth’s tax code, including an intangible expense addback provision effective in 2015, an increase of the cap on the net operating loss (NOL) deduction in 2014 and 2015 and an extension of the franchise tax through 2015. The impact of this law change has been reflected in the Company’s financial statements. In September 2013, the United States Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property and proposed regulations addressing the disposition of tangible property. These regulations do not address the tax treatment for network assets such as natural gas pipelines; however, they do replace previously issued temporary regulations and are effective for tax years beginning January 1, 2014. The Company performed an analysis of the regulations and concluded that they have no significant impact on its financial statements. The Company utilized its remaining NOLs for federal tax purposes in 2014 and 2013, given the increase in current taxable income, and no longer has any federal NOLs available as of December 31, 2015. For federal income tax purposes, the Company deducts a portion of drilling costs as intangible drilling costs (IDCs) in the year incurred which allows the Company to minimize such tax. IDCs, however, are sometimes limited for AMT purposes which can result in the Company paying AMT despite the fact that taxable income has been fully offset by current tax deductions or NOL carryforwards. Income tax expense differed from amounts computed at the federal statutory rate of 35% on pre-tax income as follows: Years Ended December 31, 2015 2014 2013 (Thousands) Tax at statutory rate $ 149,296 $ 253,299 $ 182,406 State income taxes (7,566 ) (2,992 ) 26,012 Valuation allowance 91,144 10,012 (9,832 ) Noncontrolling partners’ share of EQGP and EQM earnings (82,850 ) (43,409 ) (16,535 ) Regulatory asset (35,438 ) — — Research and experimentation credit (7,243 ) (468 ) (375 ) Other (2,668 ) (2,350 ) (6,490 ) Income tax expense $ 104,675 $ 214,092 $ 175,186 Effective tax rate 24.5 % 29.6 % 33.6 % The Company's effective tax rate for the year ended December 31, 2015 was 24.5% compared to 29.6% for the year ended December 31, 2014. The decrease in the rate from 2014 to 2015 was primarily due to an increase in earnings allocated to noncontrolling limited partners of EQGP and EQM, the effects of the Internal Revenue Service (IRS) guidance (which is further discussed below), a decrease in EQT Production’s operating income, increased tax credits in 2015 and a decrease in state taxes in 2015 as a result of lower pre-tax income on state income tax paying entities. These decreases were significantly offset by an increase in the valuation allowance recorded primarily on Pennsylvania state NOLs. The increase to noncontrolling limited partners income was primarily the result of higher net income at EQM and increased noncontrolling interests as a result of EQM’s March and November 2015 public offerings of common units, issuances of EQM common units under the $750 million ATM Program and EQGP’s IPO. The Company consolidates 100% of the pre-tax income related to the noncontrolling limited partners’ share of EQGP earnings but is not required to record an income tax provision with respect to the portion of the earnings allocated to the EQM and EQGP noncontrolling limited partners. For the year ended December 31, 2015, the Company realized a $35.4 million tax benefit in connection with recent IRS guidance received by the Company regarding the Company’s sale of Equitable Gas, a regulated entity, in 2013. The transaction included a partial like-kind exchange of assets that resulted in tax deferral for the Company. However, in order to be in compliance with the normalization rules of the Internal Revenue Code, the IRS guidance held that the deferred tax liability associated with the exchanged regulatory assets should not be considered for ratemaking purposes. As a result, during the second quarter of 2015, the Company recorded a regulatory asset equal to the taxes deferred from the exchange and an associated income tax benefit. The regulatory asset and deferred taxes will be reversed when the assets are disposed of in a taxable transaction such as a sale of assets or amortized over the 32 years remaining life of the assets received in the exchange, in either event increasing tax expense at that time. The Company believes that it is more likely than not that the benefit from certain state NOL carryforwards will not be realized. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2015 and 2014, positive evidence considered included financial and tax earnings generated over the past three years, reversals of financial to tax temporary differences, the implementation of and/or ability to employ various tax planning strategies and the estimation of future taxable income. Uncertainties such as future commodity prices can affect the Company's calculations and its ability to utilize these NOLs prior to expiration. Negative evidence considered included the projection of low commodity prices generating pretax book losses in the near future. A review of positive and negative evidence regarding these tax benefits concluded that the valuation allowances for certain Pennsylvania and Kentucky NOLs were warranted as it was more likely than not that the Company would not utilize some of the state NOLs prior to expiration. The Company’s effective tax rate for the year ended December 31, 2014 was 29.6% compared to 33.6% for the year ended December 31, 2013. The decrease in the rate from 2013 to 2014 was primarily due to an internal reorganization of subsidiaries resulting in a reduction to state taxes as well as an increase in EQM earnings and the noncontrolling public limited partners’ share of EQM earnings as a result of the Sunrise Merger and Jupiter Transaction. The following table reconciles the beginning and ending amount of reserve for uncertain tax positions (excluding interest and penalties): 2015 2014 2013 (Thousands) Balance at January 1 $ 56,957 $ 57,087 $ 17,858 Additions based on tax positions related to current year 152,983 1,195 49,289 Additions for tax positions of prior years 50,688 93 — Reductions for tax positions of prior years (1,327 ) (1,418 ) (790 ) Lapse of statute of limitations — — (9,270 ) Balance at December 31 $ 259,301 $ 56,957 $ 57,087 Included in the balance are unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate of $94.1 million , $33.9 million and $33.3 million as of December 31, 2015, 2014 and 2013, respectively. Additionally, there are uncertain tax positions of $114.2 million , $10.1 million , and $9.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, that are included in the tabular reconciliation above, but recorded in the Consolidated Balance Sheets as a reduction of the related deferred tax asset for AMT credit carryforwards and NOLs. Included in the tabular reconciliation above at December 31, 2015 , 2014 and 2013 are $6.4 million , $6.9 million and $7.6 million , respectively, for tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of tax deductions. Because of the impact of deferred tax accounting, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash taxes to an earlier period. The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense. The Company recorded approximately $1.6 million and $1.9 million for 2015 and 2014, respectively, and reversed $0.4 million of previously recorded interest expense in 2013 . Interest and penalties of $3.6 million , $2.0 million and $0.2 million were included in the balance sheet reserve at December 31, 2015 , 2014 and 2013 , respectively. As of December 31, 2015 , the Company does not expect any of its unrecognized tax benefits to decrease within the next 12 months due to potential settlements with taxing authorities, legal or administrative guidance by relevant taxing authorities or the lapse of applicable statutes of limitation. The consolidated federal income tax liability of the Company has been settled with the IRS through 2009. The IRS has completed its review of the 2010 and 2011 tax years and the Company is in the process of appealing its R&E tax credit claim for such years. The IRS review of the Company's 2012 tax year has commenced. The Company also is the subject of various state income tax examinations. With few exceptions, as of December 31, 2015, the Company is no longer subject to state examinations by tax authorities for years before 2012. There were no material changes to the Company’s methodology for unrecognized tax benefits during 2015. The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities: As of December 31, 2015 2014 (Thousands) Deferred income taxes: Total deferred income tax assets $ (827,161 ) $ (971,531 ) Total deferred income tax liabilities 2,799,331 2,700,467 Total net deferred income tax liabilities 1,972,170 1,728,936 Total deferred income tax liabilities (assets) Drilling and development costs expensed for income tax reporting 1,421,581 1,391,156 Tax depreciation in excess of book depreciation 1,224,377 1,154,082 Accumulated OCI 29,154 130,770 Post-retirement benefits 3,326 3,146 Incentive compensation and deferred compensation plans (75,143 ) (65,086 ) Net operating loss carryforwards (214,714 ) (212,718 ) Investment in EQGP and EQM (426,343 ) (336,394 ) Alternative minimum tax credit carryforward (267,045 ) (412,345 ) Unrealized hedge gains 107,854 21,314 Other 13,039 (9,976 ) Total excluding valuation allowances 1,816,086 1,663,949 Valuation allowance 156,084 64,987 Total (including amounts classified as current assets of $21,934 in 2014) $ 1,972,170 $ 1,728,936 The net deferred tax liability relating to the Company’s accumulated OCI balance as of December 31, 2015 consisted of a $40.2 million deferred tax liability related to the Company’s net unrealized gain from hedging transactions, a $4.9 million deferred tax asset related to other post-retirement benefits, and a $6.1 million deferred tax asset related to the Company’s pension plans. The net deferred tax liability relating to the Company’s accumulated OCI balance as of December 31, 2014 consisted of a $141.3 million deferred tax liability related to the Company’s net unrealized gain from hedging transactions, a $5.4 million deferred tax asset related to other post-retirement benefits, and a $5.1 million deferred tax asset related to the Company’s pension plans. The Company is subject to the AMT if the computed AMT liability exceeds the regular tax liability for the year. As a result of certain AMT preference items related to IDCs, the Company has generated AMT carryforwards. Because AMT taxes paid can be credited against regular tax and have an indefinite carryforward period, this item is reflected as a deferred tax asset on the Company’s Consolidated Balance Sheets. As of December 31, 2015 , the Company had a deferred tax asset of $90.3 million , net of valuation allowances of $156.1 million , related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2018 to 2035. As of December 31, 2014 , the Company had a deferred tax asset of $116.0 million , net of valuation allowances of $65.0 million , related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2018 to 2034 . The deferred tax asset has been reduced for uncertain tax positions of approximately $31.7 million and $0.3 million during the years ended December 31, 2015 and 2014 , respectively. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that could materially impact net income. Historically, excess tax benefits were not recorded in the Company’s financial statements as an addition to common stockholders’ equity due to the Company’s NOL position. As the Company generated taxable income in the years ended December 31, 2015 and 2014, resulting in a corresponding ability to realize a benefit from these amounts, the Company recorded tax benefits of $13.1 million and $26.6 million as of December 31, 2015 and 2014, respectively, in the financial statements as an addition to common stockholders’ equity as these tax benefits reduced taxes payable in the current year. In 2015, the Company also recorded tax benefits of $8.1 million for the 2012 excess tax benefits previously not recorded since the Company fully utilized the 2012 NOL during 2015. In 2014, the Company recorded tax benefits of $6.6 million for the 2011 excess tax benefits previously not recorded since the Company fully utilized the 2011 NOL during 2014. The Company uses tax law ordering when determining when excess tax benefits have been realized.

Equity in Nonconsolidated Inves

Equity in Nonconsolidated Investments	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity in Nonconsolidated Investments	Equity in Nonconsolidated Investments The Company, through its ownership interest in EQM, has an ownership interest in a nonconsolidated investment that is accounted for under the equity method of accounting. The following table summarizes the Company's equity in the nonconsolidated investments: Interest Ownership as of As of December 31, Investees Location Type December 31, 2015 (a) 2015 2014 (Thousands) MVP Joint Venture USA Joint 54% $ 77,025 $ — (a) As of February 11, 2016, EQM owned a 45.5% ownership interest in the MVP Joint Venture. See Note 4. The Company’s ownership share of the earnings for 2015, 2014 and 2013 related to the total investments accounted for under the equity method was $2.6 million , $3.4 million and $7.6 million , respectively, reported in other income on the Statements of Consolidated Income. For the year ended December 31, 2015, the Company's ownership share of the earnings included equity earnings related to the Company's equity investment in the MVP Joint Venture. For the years ended December 31, 2014 and 2013, the Company's ownership share of the earnings included equity earnings related to the Company's equity investment in Nora LLC. See Note 8 for further details regarding the Company's disposition of its interest in Nora LLC. EQM's equity investment in the MVP Joint Venture represented a 54% ownership interest as of December 31, 2015. In the first quarter of 2015, the Company assigned 100% of the membership interests in MVP Holdco, an indirect wholly owned subsidiary of the Company that owns an interest in the MVP Joint Venture, to EQM. The MVP Joint Venture plans to construct the MVP, an estimated 300 -mile natural gas interstate pipeline spanning from northern West Virginia to southern Virginia. The MVP Joint Venture has been determined to be a variable interest entity because the MVP Joint Venture has insufficient equity to finance activities during the construction stage of the project. EQM is not the primary beneficiary because it does not have the power to direct the activities of the MVP Joint Venture that most significantly impact its economic performance. Certain business decisions, including, but not limited to, decisions with respect to operating and construction budgets, project construction schedule, material contracts or precedent agreements, indebtedness, significant acquisitions or dispositions, material regulatory filings and strategic decisions require the approval of owners holding more than a 66 2/3% interest in the MVP Joint Venture and no one member owns more than a 66 2/3% interest. Beginning on the date it was assumed from the Company, EQM accounted for the MVP Interest as an equity method investment as EQM has the ability to exercise significant influence over operating and financial policies of the MVP Joint Venture. As of December 31, 2015, the Company’s interest in the MVP Joint Venture was recorded in other assets on the Consolidated Balance Sheets. On January 21, 2016, affiliates of ConEd acquired a 12.5% interest in the MVP Joint Venture, 8.5% of which was purchased from EQM. EQM received cash payments of $12.5 million which was equal to EQM's proportional capital contributions to the MVP Joint Venture through the date of the transaction. As of February 11, 2016, EQM owned a 45.5% ownership interest in the MVP Joint Venture. ConEd has the right to terminate its purchase of the interest in the MVP Joint Venture and be reimbursed for the purchase price and all capital contributions made to the MVP Joint Venture for a period ending no later than December 31, 2016. As of December 31, 2015, EQM had issued a $108 million performance guarantee in favor of the MVP Joint Venture to provide performance assurances for MVP Holdco's obligations to fund its proportionate share of the construction budget for the MVP. Upon the FERC’s initial release to begin construction of the MVP, EQM's guarantee will terminate, and EQM will be obligated to issue a new guarantee in an amount equal to 33% of MVP Holdco’s remaining obligations to make capital contributions to the MVP Joint Venture in connection with the then remaining construction budget, less any credit assurances issued by any affiliate of EQM under such affiliate's precedent agreement with the MVP Joint Venture. As a result of the ConEd Transaction, the amount of the Initial EQM Guarantee decreased to $91 million as of February 11, 2016. EQM's maximum financial statement exposure related to the MVP Joint Venture was approximately $185 million , which includes the investment balance of $77 million on the Consolidated Balance Sheet as of December 31, 2015 and amounts which could have become due under the performance guarantee as of that date. The following table summarizes the unaudited condensed financial statements for nonconsolidated investments accounted for under the equity method of accounting for the periods noted (including MVP Joint Venture for 2015 and Nora LLC for 2014 and 2013): Summarized Statements of Income Years Ended December 31, 2015 2014 2013 (Thousands) Revenues $ — $ 19,924 $ 45,040 Operating expenses — 13,257 29,892 Other income 2,566 102 82 Net income $ 2,566 $ 6,769 $ 15,230

Revolving Credit Facilities

Revolving Credit Facilities	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Revolving Credit Facilities	Revolving Credit Facilities The Company has a $1.5 billion unsecured revolving credit facility that expires in February 2019. The Company may request two one year extensions of the expiration date, the approval of which is subject to satisfaction of certain conditions. The revolving credit facility may be used for working capital, capital expenditures, share repurchases and any other lawful corporate purposes. Subject to certain terms and conditions, the Company may, on a one-time basis, request that the lenders’ commitments be increased to an aggregate amount up to $2.0 billion . Each lender in the facility may decide if it will increase its commitment. The credit facility is underwritten by a syndicate of 18 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by the Company. The Company’s obligations under the credit facility are unsecured. Interest rates are based on prevailing market rates. The Company is not required to maintain compensating bank balances. The Company’s debt issuer credit ratings, as determined by S&P, Moody’s or Fitch Ratings Service on its non-credit-enhanced, senior unsecured long-term debt, determine the level of fees associated with its lines of credit in addition to the interest rate charged by the counterparties on any amounts borrowed against the lines of credit; the lower the Company’s debt credit rating, the higher the level of fees and borrowing rate. EQM has a $750 million credit facility that expires in February 2019. The credit facility is available to fund working capital requirements and capital expenditures, to purchase assets, to pay distributions and repurchase units and for general partnership purposes. Provided there exists no default, and subject to certain terms and conditions, EQM may request that the lenders’ commitments be increased to an aggregate amount up to $1.0 billion . Each lender in the facility may decide if it will increase its commitment. The credit facility is underwritten by a syndicate of 18 financial institutions, each of which is obligated to fund its pro-rata portion of any borrowings by EQM. The Company is not a guarantor of EQM’s obligations under the credit facility. EQM’s obligations under the revolving portion of the credit facility are unsecured. EQM’s obligations under the credit facility were unconditionally guaranteed by each of EQM’s subsidiaries. In January 2015, EQM amended its credit facility to, among other things, release its subsidiaries from their guarantee obligations under the credit facility. The Company had no borrowings or letters of credit outstanding under its revolving credit facility as of December 31, 2015 or 2014 or at any time during the years ended December 31, 2015 or 2014. The Company incurred commitment fees averaging approximately 23 basis points for the years ended December 31, 2015 and 2014 to maintain credit availability under its credit facility. As of December 31, 2015 , EQM had $299 million of borrowings and no letters of credit outstanding under its revolving credit facility. As of December 31, 2014, EQM had no borrowings or letters of credit outstanding under its revolving credit facility. The maximum amount of outstanding borrowings under EQM's revolving credit facility at any time during the years ended December 31, 2015 and 2014 was $404 million and $450 million , respectively. The average daily balance of loans outstanding under EQM's credit facility was $261 million and $119 million during the years ended December 31, 2015 and 2014, respectively. Interest was incurred on the borrowings at a weighted average annual interest rate of approximately 1.7% for the years ended December 31, 2015 and 2014, respectively. EQM incurred commitment fees averaging approximately 23 basis points and 24 basis points for the years ended December 31, 2015 and 2014 , respectively, to maintain credit availability under its credit facility. The $299 million of borrowings under EQM's credit facility at December 31, 2015 were repaid on February 8, 2016. The Company’s credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The most significant covenants and events of default under the Company’s credit facility relate to maintenance of a debt-to-total capitalization ratio and limitations on transactions with affiliates. The Company’s credit facility contains financial covenants that require a total debt-to-total capitalization ratio of no greater than 65% . The calculation of this ratio excludes the effects of accumulated OCI. As of December 31, 2015 , the Company was in compliance with all debt provisions and covenants. EQM’s credit facility contains various provisions that, if not complied with, could result in termination of the credit facility, require early payment of amounts outstanding or similar actions. The covenants and events of default under the credit facility relate to maintenance of permitted leverage ratio, limitations on transactions with affiliates, limitations on restricted payments, insolvency events, nonpayment of scheduled principal or interest payments, acceleration of and certain other defaults under other financial obligations and change of control provisions. Under EQM's credit facility, EQM is required to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions). As of December 31, 2015 , EQM was in compliance with all debt provisions and covenants.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt December 31, 2015 December 31, 2014 Principal Value Carrying Value (a) Fair Value (b) Principal Value Carrying Value (a) Fair (Thousands) 7.76% notes, due 2015 through 2016 $ — $ — $ — $ 10,700 $ 10,700 $ 10,700 5.00% notes, due October 1, 2015 — — — 150,000 149,865 154,692 5.15% notes, due March 1, 2018 200,000 199,156 203,490 200,000 198,766 214,626 6.50% notes, due April 1, 2018 500,000 498,360 520,175 500,000 497,630 559,900 8.13% notes, due June 1, 2019 700,000 697,295 760,837 700,000 696,483 843,864 4.88% notes, due November 15, 2021 750,000 742,270 728,063 750,000 740,945 812,558 4.00% EQM notes, due August 1, 2024 500,000 493,401 414,125 500,000 492,633 495,685 7.75% debentures, due July 15, 2026 115,000 109,738 119,372 115,000 109,240 147,036 Medium-term notes: 7.3% to 7.6% Series B, due 2015 through 2023 10,000 9,991 10,241 20,000 19,985 22,279 7.6% Series C, due 2018 8,000 7,983 8,366 8,000 7,975 8,950 8.7% to 9.0% Series A, due 2020 through 2021 35,200 35,149 38,598 35,200 35,131 43,912 2,818,200 2,793,343 2,803,267 2,988,900 2,959,353 3,314,202 Less debt payable within one year — — — 166,011 165,874 171,081 Total long-term debt $ 2,818,200 $ 2,793,343 $ 2,803,267 $ 2,822,889 $ 2,793,479 $ 3,143,121 (a) Carrying value represents principal value less unamortized debt issuance costs and debt discounts. (b) Fair value is measured using Level 2 inputs. The indentures governing the Company’s and EQM’s long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict, among other things, the Company’s or EQM's ability to incur, as applicable, indebtedness, incur liens, enter into sale and leaseback transactions, complete acquisitions, merge, sell assets and perform certain other corporate actions. The covenants do not contain a rating trigger. Therefore, a change in the Company’s or EQM’s debt rating would not trigger a default under the indentures governing the indebtedness. Aggregate maturities of long-term debt are zero in 2016 , zero in 2017 , $708.0 million in 2018 , $700.0 million in 2019 , and $11.2 million in 2020 .

Pension and Other Post-Retireme

Pension and Other Post-Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Pension and Other Post-Retirement Benefit Plans	Pension and Other Post-Retirement Benefit Plans The Company, as sponsor of the EQT Corporation Retirement Plan for Employees (Retirement Plan), a defined benefit pension plan, terminated the Retirement Plan effective December 31, 2014. Distribution of plan assets pursuant to the termination will not be made until the plan termination satisfies all regulatory requirements, including required filings with the IRS and the Pension Benefit Guaranty Corporation (PBGC). On May 12, 2015, a determination letter request for the Retirement Plan was filed with the IRS. On January 4, 2016, the Company received a letter from the IRS, dated December 29, 2015, requesting additional information in connection with the determination letter filing, which the Company responded to on January 25, 2016. On June 5, 2015 (received by the PBGC on June 8, 2015), the Retirement Plan termination was filed for review by the PBGC. The PBGC 60-day review period expired without further response from the PBGC on August 8, 2015. Accordingly, the Company may proceed with the termination. The termination process is expected to be complete by the end of 2016. The Company will fully fund the Retirement Plan and then satisfy all of the benefit obligations under the Retirement Plan by purchasing one or more annuities for participants from an insurance company or other financial institution. All assets of the Retirement Plan are expected to be liquidated and used to purchase annuities, and all non-cash unrecognized losses are expected to be recognized, by the end of 2016. The following table sets forth the defined benefit pension and other post-retirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets. Refer to Note 2 for further information related to the Equitable Gas Transaction. For the Years Ended December 31, 2015 2014 2015 2014 Pension Benefits Other Benefits (Thousands) Change in benefit obligation: Benefit obligation at beginning of year $ 21,704 $ 21,828 $ 18,741 $ 18,253 Service cost 350 350 762 669 Interest cost 746 820 634 693 Amendments — — — 227 Actuarial loss (gain) 2,770 2,412 (361 ) 1,190 Benefits paid (1,981 ) (1,988 ) (2,141 ) (2,291 ) Expenses paid (367 ) (262 ) — — Settlements (177 ) (1,456 ) — — Benefit obligation at end of year $ 23,045 $ 21,704 $ 17,635 $ 18,741 Change in plan assets: Fair value of plan assets at beginning of year $ 18,323 $ 20,089 $ 823 $ 493 Actual (loss) gain on plan assets (32 ) 1,217 — — Contributions 1,175 723 287 330 Benefits paid (1,981 ) (1,988 ) — — Expenses paid (367 ) (262 ) — — Settlements (177 ) (1,456 ) — — Fair value of plan assets at end of year 16,941 18,323 1,110 823 Funded status at end of year $ (6,104 ) $ (3,381 ) $ (16,525 ) $ (17,918 ) Amounts recognized in the statement of financial position consist of: Current liabilities $ (6,104 ) $ — $ (1,376 ) $ (924 ) Noncurrent liabilities — (3,381 ) (15,149 ) (16,994 ) Net amounts recognized $ (6,104 ) $ (3,381 ) $ (16,525 ) $ (17,918 ) Amounts recognized in accumulated OCI, net of tax, consist of: Net loss $ 9,674 $ 8,082 $ 7,610 $ 8,273 Net prior service — — 257 285 Net amount recognized $ 9,674 $ 8,082 $ 7,867 $ 8,558 The accumulated benefit obligation for the Company’s defined benefit pension plan was approximately $23.0 million and $21.7 million at December 31, 2015 and 2014 , respectively. The Company uses a December 31 measurement date for its defined benefit pension and other post-retirement benefit plans. The Company’s costs related to its defined benefit pension and other post-retirement benefit plans were as follows: For the Years Ended December 31, 2015 2014 2013 2015 2014 2013 Pension Benefits Other Benefits (Thousands) Components of net periodic benefit cost: Service cost $ 350 $ 350 $ 500 $ 762 $ 669 $ 905 Interest cost 746 820 1,935 634 693 1,110 Expected return on plan assets (627 ) (1,377 ) (3,323 ) — — — Amortization of prior service cost — — — (306 ) (446 ) (845 ) Recognized net actuarial loss 746 709 2,306 793 879 1,760 Settlement loss and special termination benefits 122 879 381 — — — Subtotal 1,337 1,381 1,799 1,883 1,795 2,930 Net periodic benefit cost of discontinued operations — — 1,552 — — 1,356 Net periodic benefit cost $ 1,337 $ 1,381 $ 247 $ 1,883 $ 1,795 $ 1,574 Currently, the Company recognizes expense for on-going post-retirement benefits other than pensions, a portion of which expense is subject to recovery in the approved rates of its rate-regulated EQT Midstream business. For the Years Ended December 31, 2015 2014 2013 2015 2014 2013 Pension Benefits Other Benefits (Thousands) Other changes in plan assets and benefit obligations recognized in OCI, net of tax: Net loss (gain) $ 1,592 $ 558 $ 712 $ (663 ) $ 39 $ 2,147 Net prior service (credit) cost — — — (28 ) 179 416 Total recognized in OCI, net of tax $ 1,592 $ 558 $ 712 $ (691 ) $ 218 $ 2,563 Total recognized in net periodic benefit cost and OCI, net of tax $ 2,929 $ 1,939 $ 959 $ 1,192 $ 2,013 $ 4,137 The net loss and prior service cost associated with the disposal group of the Equitable Gas Transaction totaled $17.3 million , net of tax, at the closing date of the Equitable Gas Transaction. The Company recognized the full amount in income from discontinued operations in the Statements of Consolidated Income for the year ended December 31, 2013. The estimated net loss for the defined benefit pension plan that will be amortized from accumulated OCI, net of tax, into net periodic benefit cost during 2016 is $0.1 million ; in addition, the remaining $9.5 million will be recognized upon final settlement of the plan. The estimated net loss and net prior service (credit) for the other post-retirement benefit plans that will be amortized from accumulated OCI, net of tax, into net periodic benefit cost during 2016 are $0.4 million and $ (0.2) million , respectively. The following weighted average assumptions were used to determine the benefit obligations for the Company’s defined benefit pension and other post-retirement benefit plans: December 31, 2015 2014 2015 2014 Pension Benefits Other Benefits Discount rate 2.20% 3.60% 3.95% 3.60% Rate of compensation increase N/A N/A N/A N/A The following weighted average assumptions were used to determine the net periodic benefit cost for the Company’s defined benefit pension and other post-retirement benefit plans: For the Years Ended December 31, 2015 2014 2015 2014 Pension Benefits Other Benefits Discount rate 3.60 % 4.00 % 3.60 % 4.00 % Expected return on plan assets 3.75 % 7.75 % N/A N/A Rate of compensation increase N/A N/A N/A N/A The expected rate of return on plan assets is established by the Company at the beginning of the fiscal year to which it relates based upon information available to the Company at that time, including the plans’ investment mix and the historical and forecasted rates of return on the types of securities held. Any differences between actual experience and assumed (expected) experience are deferred as an unrecognized actuarial gain or loss. The unrecognized actuarial gains or losses are amortized into the Company’s net periodic benefit cost. The expected rate of return on plan assets determined as of January 1, 2016 is 3.75% . This assumption will be used to derive the Company’s 2016 net periodic benefit cost. The rate of compensation increase is not applicable in determining future benefit obligations as a result of plan design. Pension expense increases or decreases as the expected rate of return on plan assets or discount rate changes. For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2015 was 7.00% for both the Pre -65 and Post-65 medical charges. The rates were assumed to decrease gradually to ultimate rates of 5.00% in 2025. Assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have had the following effects: One-Percentage-Point Increase One-Percentage-Point Decrease 2015 2014 2013 2015 2014 2013 (Thousands) Increase (decrease) to total of service and interest cost components $ 10 $ 13 $ 25 $ (11 ) $ (14 ) $ (26 ) Increase (decrease) to post-retirement benefit obligation $ 268 $ 228 $ 220 $ (278 ) $ (229 ) $ (223 ) The Company’s asset allocation for the Retirement Plan at December 31, 2015 and 2014 and target allocation for 2016 by asset category are as follows: Target Percentage of Plan Assets at December 31, Asset Category Allocation 2016 2015 2014 Domestic broadly diversified equity securities 0% - 10% — % 26 % Fixed income securities 80% - 100% 99 % 63 % International broadly diversified equity securities 0% — % 8 % Cash and equivalent investments 0% - 20% 1 % 3 % 100 % 100 % The investment activities of the Retirement Plan are supervised and monitored by the Benefits Investment Committee (BIC). The BIC reports to the Management Development and Compensation Committee (the Compensation Committee) of the Board of Directors and consists of the chief financial officer and other officers and employees of the Company. Prior to the Company’s determination to terminate the Retirement Plan in 2014, the BIC had developed an investment strategy that focused on asset allocation, diversification and quality guidelines. The investment goals of the BIC were to minimize high levels of risk at the total pension investment fund level. In October 2014 in anticipation of the termination of the Retirement Plan, the BIC modified the investment allocations for the Retirement Plan by allocating a greater portion of the plan assets to fixed income securities to prepare for the expected liquidation of plan assets. As a result of the modification of the investment allocations, at December 31, 2014 the fixed income securities and domestic diversified equity securities categories were outside of the previously established target allocations but consistent with the BIC’s October 2014 determination. In February 2015, the BIC decided to sell the remaining equity investments and invested the funds in fixed-income investments with similar duration to the plan liabilities. The reallocation was completed by March 31, 2015, and the Retirement Plan’s assets now consist of only fixed-income investments and cash and cash equivalents. The BIC monitors the asset allocation on a quarterly basis and makes adjustments, as needed, to rebalance the assets to the desired allocation. Comparative market and peer group benchmarks are utilized to ensure that each of the investment managers is performing satisfactorily. The Company made cash contributions to the Retirement Plan of approximately $1.2 million , $0.7 million and $2.6 million during 2015 , 2014 and 2013 , respectively, to meet certain funding targets. Assuming the termination process for the Retirement Plan is completed in 2016 as anticipated, the Company expects to make cash payments of $6.1 million during 2016 to fully fund the Retirement Plan and purchase the required annuities, make other cash settlements and pay any administrative expenses of the termination. The Company does not expect its cash contributions to have a significant effect on its financial position, results of operations or liquidity. All assets of the Retirement Plan are expected to be liquidated in the termination and used, together with the Company's 2016 cash contribution to purchase annuities for participants of approximately $22.9 million from an insurance company or other financial institution. The following benefit payments for post-retirement benefits other than pensions, which reflect expected future service, are expected to be paid by the Company during each of the next five years and the five years thereafter: $1.7 million in 2016 ; $1.7 million in 2017 ; $1.6 million in 2018 ; $1.6 million in 2019 ; $1.6 million in 2020 ; and $7.1 million in the five years thereafter. Expense recognized by the Company related to its defined contribution plan totaled $15.7 million in 2015 , $13.7 million in 2014 and $14.6 million in 2013 . The Company reports defined benefit plan assets at fair value which is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. The disclosure below categorizes the assets by a fair value hierarchy. Assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. The three levels of the hierarchy are defined as follows: Level 1 – Observable inputs based on quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 – Observable inputs, other than those included in Level 1, based on quoted prices for similar assets or liabilities in active markets or quoted prices for identical assets and liabilities in inactive markets. Level 3 – Unobservable inputs that reflect an entity’s own assumptions about what inputs a market participant would use in pricing the asset or liability based on the best information available in the circumstances. Defined benefit plan asset investments included cash equivalents and fixed income securities with a fair value of $5.4 million and $5.7 million as of December 31, 2015 and 2014 , respectively. These investments are based upon daily unadjusted quoted prices and therefore are considered Level 1. Defined benefit plan asset investments also include common/collective trusts and fixed income securities with a fair value of $11.3 million and $12.6 million as of December 31, 2015 and 2014 , respectively. These investments are valued at current market value of the underlying assets of the fund and therefore are considered Level 2. As of December 31, 2015 and 2014 , the Retirement Plan did not hold any assets whose fair value was determined using unobservable inputs and therefore would be considered Level 3.

Changes in Accumulated Other Co

Changes in Accumulated Other Comprehensive Income by Component	12 Months Ended
	Dec. 31, 2015
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Changes in Accumulated Other Comprehensive Income by Component	Changes in Accumulated Other Comprehensive Income by Component The following tables explain the changes in accumulated OCI by component for the years ended December 31, 2015 , 2014 , and 2013 : Year Ended December 31, 2015 Natural gas cash flow hedges, net of tax Interest rate cash flow hedges, net of tax Pension and other post- retirement benefits liability adjustment, net of tax Accumulated OCI (loss), net of tax (Thousands) Accumulated OCI (loss), net of tax, as of January 1, 2015 $ 217,121 $ (987 ) $ (16,640 ) $ 199,494 (Gains) losses reclassified from accumulated OCI, net of tax (152,359 ) (a) 144 (a) (901 ) (b) (153,116 ) Accumulated OCI (loss), net of tax, as of December 31, 2015 $ 64,762 $ (843 ) $ (17,541 ) $ 46,378 Year Ended December 31, 2014 Natural gas cash flow hedges, net of tax Interest rate cash flow hedges, net of tax Pension and other post- retirement benefits liability adjustment, net of tax Accumulated OCI (loss), net of tax (Thousands) Accumulated OCI (loss), net of tax, as of January 1, 2014 $ 61,699 $ (1,132 ) $ (15,864 ) $ 44,703 Gains recognized in accumulated OCI, net of tax 156,207 (a) — — 156,207 Gain reclassified from accumulated OCI, net of tax, into gain on sale/exchange of assets (16,735 ) (a) — — (16,735 ) Losses (gains) reclassified from accumulated OCI, net of tax 15,950 (a) 145 (a) (776 ) (b) 15,319 Change in accumulated OCI, net of tax 155,422 145 (776 ) 154,791 Accumulated OCI (loss), net of tax, as of December 31, 2014 $ 217,121 $ (987 ) $ (16,640 ) $ 199,494 Year Ended December 31, 2013 Natural gas cash Interest rate Pension and Accumulated (Thousands) Accumulated OCI (loss), net of tax, as of January 1, 2013 $ 138,188 $ (1,276 ) $ (37,365 ) $ 99,547 Gains recognized in accumulated OCI, net of tax 10,669 (a) — 2,081 12,750 (Gains) losses reclassified from accumulated OCI, net of tax (87,158 ) (a) 144 (a) 19,420 (b) (67,594 ) Change in accumulated OCI, net of tax (76,489 ) 144 21,501 (54,844 ) Accumulated OCI (loss), net of tax, as of December 31, 2013 $ 61,699 $ (1,132 ) $ (15,864 ) $ 44,703 (a) See Note 6 for additional information. (b) This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 14 for additional information.

Common Stock and Earnings Per S

Common Stock and Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Common Stock, Treasury Stock and Earnings Per Share	Common Stock, Treasury Stock and Earnings Per Share Common Stock At December 31, 2015 , shares of EQT’s authorized and unissued common stock were reserved as follows: (Thousands) Possible future acquisitions 20,457 Stock compensation plans 13,394 Total 33,851 Treasury Stock Effective as of December 31, 2015, the Company transferred 17.0 million shares of treasury stock from issued to authorized but unissued shares. Additionally, during the year ended December 31, 2015, the Company funded 291,919 shares of treasury stock into a rabbi trust for the 2005 Directors’ Deferred Compensation Plan and the 1999 Directors' Deferred Compensation Plan. Shares of the Company's common stock held by the rabbi trust are accounted for as treasury stock in the Company's financial statements. Earnings Per Share The computation of basic and diluted earnings per share of common stock attributable to EQT Corporation is shown in the table below: Years Ended December 31, 2015 2014 2013 (Thousands except per share amounts) Basic earnings per common share: Net income attributable to EQT Corporation $ 85,171 $ 386,965 $ 390,572 Average common shares outstanding 152,398 151,553 150,574 Basic earnings per common share $ 0.56 $ 2.55 $ 2.59 Diluted earnings per common share: Net income attributable to EQT Corporation $ 85,171 $ 386,965 $ 390,572 Average common shares outstanding 152,398 151,553 150,574 Potentially dilutive securities: Stock options and awards (a) 541 960 1,213 Total 152,939 152,513 151,787 Diluted earnings per common share $ 0.56 $ 2.54 $ 2.57 (a) Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 291,700 shares for the year ended December 31, 2015 . There were no options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive for the years ended December 31, 2014 and 2013. The impact of EQM’s and EQGP's dilutive units did not have a material impact on the Company’s earnings per share calculations for any of the periods presented.

Share-Based Compensation Plans

Share-Based Compensation Plans	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation Plans	Share-Based Compensation Plans Share-based compensation expense recorded by the Company was as follows: Years Ended December 31, 2015 2014 2013 (Thousands) 2012 Executive Performance Incentive Program $ — $ 7,743 $ 6,739 2013 Executive Performance Incentive Program 6,834 8,208 6,602 2014 Executive Performance Incentive Program 12,865 9,104 — 2015 Executive Performance Incentive Program 12,051 — — 2011 Volume and Efficiency Program — — 13,834 2012 EQT Value Driver Award Program — — 2,327 2013 EQT Value Driver Award Program — 4,403 13,050 2014 EQT Value Driver Award Program 1,116 11,510 — 2014 EQM Value Driver Award Program 622 2,378 — 2015 EQT Value Driver Award Program 14,574 — — Restricted stock awards 7,031 4,688 3,033 Non-qualified stock options 1,938 3,002 3,805 Other programs, including non-employee director awards (2,339 ) (409 ) 9,154 Total share-based compensation expense $ 54,692 $ 50,627 $ 58,544 The Company typically uses treasury stock to fund awards that are paid in stock, but the awards may be funded by stock acquired by the Company in the open market or from any other person, issued directly by the Company or any combination of the foregoing. When an award has graduated vesting, the Company records the expense equal to the vesting percentage on the vesting date. A portion of the expense related to share-based compensation plans is included as an unallocated expense in deriving total operating income for segment reporting purposes. See Note 5. Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2015 , 2014 and 2013 was $14.0 million , $19.2 million and $32.9 million , respectively. During the years ended December 31, 2015 , 2014 and 2013 , share-based payment arrangements paid in stock generated tax benefits of $43.1 million , $45.9 million and $14.4 million , respectively. Executive Performance Incentive Programs Effective in 2012, the Management Development and Compensation Committee of the Board of Directors (the Compensation Committee) adopted the 2012 Executive Performance Incentive Plan (2012 Incentive PSU Program) under the 2009 Long-Term Incentive Plan. The 2012 Incentive PSU Program was established to provide long-term incentive opportunities to key employees to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. The vesting of the units under the 2012 Incentive PSU Program occurred upon payment in the first quarter of 2015, following the expiration of the performance period. Awards granted were earned based on a combination of the level of total shareholder return relative to a predefined peer group and the level of cumulative operating cash flow per share over the period January 1, 2012 through December 31, 2014. The Company accounted for these awards as equity awards using the $123.37 grant date fair value as determined using a Monte Carlo simulation. The Monte Carlo simulation projected the share price, for the Company and its peers, at the ending point of the performance period. The prices were generated using each company’s annual volatility for the expected term and the commensurate three -year risk-free rate of 0.36% . Based on the Company’s performance relative to the conditions discussed above, 307,323 shares of common stock, valued at $37.9 million based on the Monte Carlo value on the grant date, were distributed during the first quarter of 2015. The total compensation cost capitalized in 2014 and 2013 related to the 2012 Incentive PSU Program was $2.6 million and $8.1 million , respectively. Effective in 2013, the Compensation Committee adopted the 2013 Executive Performance Incentive Plan (2013 Incentive PSU Program) under the 2009 Long-Term Incentive Plan. The 2013 Incentive PSU Program was established to provide long-term incentive opportunities to key employees to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. The vesting of the units under the 2013 Incentive PSU Program will occur upon payment in the first quarter of 2016, following the expiration of the performance period. Awards granted will be earned based on a combination of the level of total shareholder return relative to a predefined peer group and the level of cumulative operating cash flow per share over the period of January 1, 2013 through December 31, 2015. The Company accounted for these awards as equity awards using the $140.00 grant date fair value as determined using a Monte Carlo simulation. The Monte Carlo simulation projected the share price, for the Company and its peers, at the ending point of the performance period. The prices were generated using each company’s annual volatility for the expected term and the commensurate three -year risk-free rate of 0.36% . Based on the Company's performance relative to the conditions discussed above, 261,073 shares of common stock, valued at $36.6 million based on the Monte Carlo value on the grant date, are expected to be distributed during the first quarter of 2016. The total compensation cost capitalized in 2015 , 2014 and 2013 related to the 2013 Incentive PSU Program was $4.4 million , $5.5 million , and $5.0 million , respectively. The peer companies for the 2013 Incentive PSU Program are as follows: Cabot Oil & Gas Corp. MDU Resources Group, Inc. Sempra Energy Chesapeake Energy Corp. National Fuel Gas Company SM Energy Company Cimarex Energy Co. Newfield Exploration Company Southwestern Energy Company Concho Resources, Inc ONEOK, Inc. Spectra Energy Corp CONSOL Energy Inc. Pioneer Natural Resources Company Ultra Petroleum Corp. Energen Corp. Plains Exploration & Production Co. Whiting Petroleum Corp. EOG Resources, Inc. Questar Corp. The Williams Companies, Inc. EXCO Resources, Inc. Quicksilver Resources Inc. MarkWest Energy Partners, L.P. Range Resources Corp. Effective in 2014, the Compensation Committee adopted the 2014 Executive Performance Incentive Plan (2014 Incentive PSU Program) under the 2009 Long-Term Incentive Plan. The 2014 Incentive PSU Program was established to provide long-term incentive opportunities to key employees to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. A total of 259,230 units were outstanding at January 1, 2015. Adjusting for 10,420 forfeitures, there were 248,810 outstanding units as of December 31, 2015 . The vesting of the units under the 2014 Incentive PSU Program will occur upon payment after December 31, 2016 (the end of the performance period). The payout factor will vary between zero and 300% of the number of outstanding units contingent upon a combination of the level of total shareholder return relative to a predefined peer group and the level of production sales volume growth over the period January 1, 2014 through December 31, 2016. The Company accounted for these awards as equity awards using the grant date fair value as determined using a Monte Carlo simulation. The Monte Carlo simulation projected the share price, for the Company and its peers, at the ending point of the performance period. The prices were generated using each company’s annual volatility for the expected term and the commensurate three -year risk-free rate of 0.78% . As the program includes a performance condition that affects the number of shares that will ultimately vest (the cumulative total sales volume growth performance condition), in accordance with ASC Topic 718, the Monte Carlo simulation computed a grant date fair value for each possible performance condition outcome on the grant date. The Company reevaluates the then-probable outcome at each reporting period, in order to record expense at the probable outcome grant date fair value. As of December 31, 2015 , the compensation expense was recorded using a grant date fair value of $189.68 per unit, which was the grant date fair value computed for the outcome which management estimated to be most probable. The total compensation cost capitalized in 2015 and 2014 related to the 2014 Incentive PSU Program was $4.9 million and $4.6 million , respectively. As of December 31, 2015 , $15.7 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2014 Incentive PSU Program was expected to be recognized by December 31, 2016. The peer companies for the 2014 Incentive PSU Program are as follows: Cabot Oil & Gas Corp. MarkWest Energy Partners, L.P. Range Resources Corp. Chesapeake Energy Corp. National Fuel Gas Company SM Energy Company Cimarex Energy Co. Newfield Exploration Company Southwestern Energy Company Concho Resources, Inc. Noble Energy, Inc. Spectra Energy Corp CONSOL Energy Inc. ONEOK, Inc. Ultra Petroleum Corp. Continental Resources, Inc. Pioneer Natural Resources Company Whiting Petroleum Corp. Energen Corp. QEP Resources, Inc. The Williams Companies, Inc. EOG Resources, Inc. Questar Corp. EXCO Resources, Inc. Quicksilver Resources, Inc. Effective in 2015, the Compensation Committee adopted the 2015 Executive Performance Incentive Plan (2015 Incentive PSU Program) under the 2014 Long-Term Incentive Plan. The 2015 Incentive PSU Program was established to provide long-term incentive opportunities to key employees to further align their interests with those of the Company’s shareholders and with the strategic objectives of the Company. A total of 369,290 units were granted in 2015 and no additional units may be granted. Adjusting for 12,890 forfeitures, there were 356,400 outstanding units as of December 31, 2015 . The vesting of the units under the 2015 Incentive PSU Program will occur upon payment after December 31, 2017 (the end of the performance period). The payout factor will vary between zero and 300% of the number of outstanding units contingent upon a combination of the level of total shareholder return relative to a predefined peer group and the level of production sales volume growth over the period January 1, 2015 through December 31, 2017. The Company accounted for these awards as equity awards using the grant date fair value as determined using a Monte Carlo simulation. The Monte Carlo simulation projected the share price, for the Company and its peers, at the ending point of the performance period. The prices were generated using each company’s annual volatility for the expected term and the commensurate three -year risk-free rate of 1.10% . As the program includes a performance condition that affects the number of shares that will ultimately vest (the cumulative total sales volume growth performance condition), in accordance with ASC Topic 718, the Monte Carlo simulation computed a grant date fair value for each possible performance condition outcome on the grant date. The Company reevaluates the then-probable outcome at each reporting period, in order to record expense at the probable outcome grant date fair value. As of December 31, 2015 , the compensation expense was recorded using a grant date fair value of $160.13 per unit, which was the grant date fair value computed for the outcome which management estimated to be most probable. The total compensation cost capitalized in 2015 related to the 2015 Incentive PSU Program was $4.9 million . As of December 31, 2015 , $33.9 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2015 Incentive PSU Program was expected to be recognized over the next two years. The peer companies for the 2015 Incentive PSU Program are as follows: Cabot Oil & Gas Corp. MarkWest Energy Partners, L.P. Range Resources Corp. Chesapeake Energy Corp. National Fuel Gas Company SM Energy Company Cimarex Energy Co. Newfield Exploration Company Southwestern Energy Company Concho Resources, Inc. Noble Energy, Inc. Spectra Energy Corp CONSOL Energy Inc. ONEOK, Inc. Ultra Petroleum Corp. Continental Resources, Inc. Pioneer Natural Resources Company Whiting Petroleum Corp. Energen Corp. QEP Resources, Inc. The Williams Companies, Inc. EOG Resources, Inc. Questar Corp. EXCO Resources, Inc. Quicksilver Resources, Inc. Value Driver Award Programs Effective in 2012, the Compensation Committee adopted the 2012 Value Driver Award Program (2012 EQT VDPSU) under the 2009 Long-Term Incentive Plan. The 2012 EQT VDPSU was established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under the 2012 EQT VDPSU, 50% of the units confirmed vested upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed vested upon the payment date following the second anniversary of the grant date. The payments were contingent upon adjusted 2012 EBITDA performance as compared to the Company’s annual business plan and individual, business unit and Company value driver performance over the period January 1, 2012 through December 31, 2012. The two tranches of awards vested and 204,679 awards including accrued dividends were distributed in Company common stock in January 2013 and 194,943 awards including accrued dividends were distributed in February 2014. The Company accounted for these awards as equity awards using the $54.79 grant date fair value per unit which was equal to the Company’s common stock price on the date prior to the date of grant. Due to the graded vesting of the award, the Company recognized compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards. The total compensation cost capitalized related to the 2012 EQT VDPSU was $2.6 million in 2013. Effective in 2013, the Compensation Committee adopted the 2013 Value Driver Award Program (2013 EQT VDPSU) under the 2009 Long-Term Incentive Plan. The 2013 EQT VDPSU was established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under the 2013 EQT VDPSU, 50% of the units confirmed vested upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed vested upon the payment date following the second anniversary of the grant date. The payments were contingent upon adjusted 2013 EBITDA performance as compared to the Company’s annual business plan and individual, business unit and Company value driver performance over the period January 1, 2013 through December 31, 2013. The two tranches of awards vested and 306,076 awards including accrued dividends were distributed in Company common stock in February 2014 and 279,475 awards including accrued dividends were distributed in February 2015. The Company accounts for these awards as equity awards using the $58.98 grant date fair value per unit which was equal to the Company’s common stock price on the date prior to the date of grant. Due to the graded vesting of the award, the Company recognized compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards. The total compensation cost capitalized related to the 2013 EQT VDPSU was $2.9 million and $14.1 million in 2014 and 2013, respectively. Effective in 2014, the Compensation Committee adopted the 2014 Value Driver Award Program (2014 EQT VDPSU) under the 2009 Long-Term Incentive Plan. The 2014 EQT VDPSU was established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under the 2014 EQT VDPSU, 50% of the units confirmed vested upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed will vest upon the payment date following the second anniversary of the grant date. The payments were contingent upon adjusted 2014 EBITDA performance as compared to the Company’s annual business plan and individual, business unit and Company value driver performance over the period of January 1, 2014 through December 31, 2014. As of January 1, 2015, 375,426 awards including accrued dividends were outstanding under the 2014 EQT VDPSU. The first tranche of the confirmed awards vested and $14.2 million was paid in cash in February 2015. The remainder of the confirmed awards are expected to vest and be paid in cash in the first quarter of 2016. As of December 31, 2015, 181,928 awards including accrued dividends were outstanding under the 2014 EQT VDPSU. The Company accounts for these awards as liability awards and as such, records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. Due to the graded vesting of the awards, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards. The total compensation cost capitalized related to the 2014 EQT VDPSU was $1.3 million and $9.8 million in 2015 and 2014, respectively. The total liability recorded for the 2014 EQT VDPSU was $9.5 million and $21.3 million as of December 31, 2015 and 2014, respectively. Effective in 2015, the Compensation Committee adopted the 2015 Value Driver Award Program (2015 EQT VDPSU) under the 2014 Long-Term Incentive Plan. The 2015 EQT VDPSU was established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. Under the 2015 EQT VDPSU, 50% of the units confirmed will vest upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed will vest upon the payment date following the second anniversary of the grant date. The payments are contingent upon adjusted 2015 EBITDA performance as compared to the Company’s annual business plan and individual, business unit and Company value driver performance over the period January 1, 2015 through December 31, 2015. As of December 31, 2015, 448,487 awards including accrued dividends were outstanding under the 2015 EQT VDPSU. The first tranche of the confirmed awards are expected to vest and be distributed in Company common stock in the first quarter 2016. The remainder of the confirmed awards is expected to vest and be paid in Company common stock in the first quarter of 2017. The Company accounts for these awards as equity awards using the $75.70 grant date fair value per unit which was equal to the Company’s common stock price on the date prior to the date of grant. Due to the graded vesting of the award, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards. The total compensation cost capitalized related to the 2015 EQT VDPSU was $10.9 million in 2015. As of December 31, 2015, $8.4 million of unrecognized compensation cost related to the 2015 EQT VDPSU was expected to be fully recognized by December 31, 2016. 2011 Volume and Efficiency Program Effective in 2011, the Compensation Committee adopted the 2011 Volume and Efficiency Program (2011 VEP) under the 2009 Long-Term Incentive Plan. The 2011 VEP was established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. The vesting of the stock units granted under the 2011 VEP occurred upon payment in February 2014 following the expiration of the performance period on December 31, 2013. The vesting resulted in approximately 663,350 awards including accrued dividends being distributed in Company common stock in February 2014. The Company accounted for these awards as equity awards using the $48.06 grant date fair value per unit which was equal to the Company’s common stock price on the grant date. The total compensation cost capitalized related to the 2011 VEP was $2.8 million in 2013. Restricted Stock Awards The Company granted 158,360 , 89,500 and 101,510 restricted stock awards during the years ended December 31, 2015 , 2014 and 2013 , respectively, to key employees of the Company. The restricted shares granted will be fully vested at the end of the three -year period commencing with the date of grant, assuming continued employment. The weighted average fair value of these restricted stock grants, based on the grant date fair value of the Company’s common stock, was approximately $75 , $95 and $71 for the years ended December 31, 2015 , 2014 and 2013 , respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2015 , 2014 and 2013 was $3.8 million , $1.5 million and $4.3 million , respectively. As of December 31, 2015 , $13.2 million of unrecognized compensation cost related to nonvested restricted stock awards was expected to be recognized over a remaining weighted average vesting term of approximately 1.7 years. A summary of restricted stock activity as of December 31, 2015 , and changes during the year then ended, is presented below: Restricted Stock Non- Vested Shares Weighted Average Fair Value Aggregate Fair Value Outstanding at January 1, 2015 229,990 $ 74.90 $ 17,225,411 Granted 158,360 $ 75.46 11,949,751 Vested (71,100 ) $ 53.56 (3,808,262 ) Forfeited (17,130 ) $ 80.92 (1,386,273 ) Outstanding at December 31, 2015 300,120 $ 79.90 $ 23,980,627 Non-Qualified Stock Options The fair value of the Company’s option grants was estimated at the dates of grant using a Black-Scholes option-pricing model with the assumptions indicated in the table below for the years ended December 31, 2015 , 2014 and 2013 . The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the date of grant. The dividend yield is based on the dividend yield of the Company’s common stock at the time of grant. Expected volatilities are based on historical volatility of the Company’s common stock. The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. Years Ended December 31, 2015 2014 2013 Risk-free interest rate 1.61% 1.72% 0.76% Dividend yield 0.12% 0.15% 0.22% Volatility factor 26.80% 24.80% 31.69% Expected term 5 years 5 years 5 years The Company granted 158,200 , 133,500 and 259,600 stock options during the years ended December 31, 2015 , 2014 and 2013 , respectively. The weighted average grant date fair value of the options was $19.90 , $22.25 and $16.72 for the years ended December 31, 2015 , 2014 and 2013 , respectively. The total intrinsic value of options exercised during the years ended December 31, 2015 , 2014 and 2013 was $15.1 million , $14.4 million and $22.8 million , respectively. As of December 31, 2015 , $2.9 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2017. A summary of option activity as of December 31, 2015 , and changes during the year then ended, is presented below: Non-qualified Stock Options Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2015 1,338,468 $54.08 Granted 158,200 $75.70 Exercised (405,526 ) $46.00 Forfeited — — Expired (10,900 ) $48.91 Outstanding at December 31, 2015 1,080,242 $60.33 6.53 years $2,261,513 Exercisable at December 31, 2015 788,542 $52.25 5.78 years $2,261,513 Non-employee Directors’ Share-Based Awards The Company has historically granted to non-employee directors share-based awards which vest upon grant of the awards. The value of the share-based awards will be paid in cash or Company common stock upon the directors’ termination of service on the Company’s Board of Directors. For awards which will be paid in cash, the Company accounts for these awards as liability awards and as such records compensation expense for the remeasurement of the fair value of the awards at the end of each reporting period. For awards which will be settled in Company common stock, the Company accounts for these awards as equity awards. A total of 222,251 non-employee director share-based awards including accrued dividends were outstanding as of December 31, 2015 . A total of 24,110 , 17,900 and 25,500 share-based awards were granted to non-employee directors during the years ended December 31, 2015 , 2014 and 2013 , respectively. The weighted average fair value of these grants, based on the Company’s common stock price on the grant date, was $75.52 , $89.78 and $58.98 for the years ended December 31, 2015 , 2014 and 2013 , respectively. EQM Awards At the closing of EQM’s IPO in July 2012, the Compensation Committee and the Board of Directors of EQM's general partner granted certain key Company employees performance awards under the EQM Total Return Program representing 146,490 common units of EQM. The performance condition related to the performance awards was satisfied on December 31, 2015 as the total unitholder return realized on EQM’s common units from the date of grant was at least 10% . The Company accounted for the EQM Total Return Program awards as equity awards using a $20.02 grant date fair value per unit as determined using a fair value model. The model projected the unit price for EQM common units at the ending point of the performance period. The price was generated using annual historical volatilities of peer group companies for the expected term of the awards, which was based upon the performance period. The range of expected volatilities calculated by the valuation model was 27% - 72% , and the weighted-average expected volatility was approximately 38% . Additional assumptions included the risk-free rate for periods within the contractual life of the awards based on the U.S. Treasury yield curve in effect at the time of grant and the expected EQM distribution growth rate of 10% . As of January 1, 2015, 139,980 of these performance awards were outstanding. Adjusting for 2,350 forfeitures, there were 137,630 awards outstanding as of December 31, 2015 . These awards are expected to vest and be paid in common units of EQM in the first quarter of 2016. Additionally, the general partner of EQM has granted EQM common unit-based phantom awards to its independent directors, which vested upon grant. The value of the phantom awards will be paid in EQM common units upon the director’s termination of service on the general partner’s Board of Directors. The Company accounts for these awards as equity awards and as such recorded compensation expense for the fair value of the awards at the grant date fair value. A total of 14,433 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2015 . A total of 2,220 , 2,580 and 3,790 unit-based awards were granted to independent directors during the years ended December 31, 2015 , 2014 and 2013 , respectively. The weighted average fair value of these grants, based on EQM’s common unit price on the grant date, was $88.00 , $58.79 and $37.92 for the years ended December 31, 2015 , 2014 and 2013 , respectively. Effective in 2014, the Compensation Committee and the Board of Directors of EQM’s general partner adopted the 2014 EQM Value Driver Award Program (2014 EQM VDPSU) under the 2009 Long-Term Incentive Plan and EQM’s 2012 Long-Term Incentive Plan. The 2014 EQM VDPSU was established to align the interests of key employees with the interests of EQM unitholders and customers and the strategic objectives of EQM. Under the 2014 EQM VDPSU, 50% of the units confirmed vested upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed will vest upon the payment date following the second anniversary of the grant date. The performance metrics are EQM’s 2014 adjusted EBITDA performance as compared to EQM’s annual business plan and individual, business unit and value driver performance over the period of January 1, 2014 through December 31, 2014. As of January 1, 2015, 62,845 awards including accrued dividends were outstanding under the 2014 EQM VDPSU. The first tranche of the confirmed awards vested and 31,629 units including accrued dividends were distributed in EQM common units in February 2015. The remainder of the confirmed awards are expected to vest and be paid in EQM common units in the first quarter of 2016. As of December 31, 2015, 28,696 awards including accrued dividends were outstanding under the 2014 EQM VDPSU. EQM accounted for these awards as equity awards using the $58.79 grant date fair value per unit which was equal to EQM’s common unit price on the date prior to the date of grant. Due to the graded vesting of the awards, EQM recognized compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards. The total compensation cost capitalized related to the 2014 EQM VDPSU was less than $0.1 million and $0.3 million in 2015 and 2014, respectively. EQGP Awards The general partner of EQGP has granted EQGP common unit-based phantom awards to its independent directors, which vested upon grant. The value of the phantom awards will be paid in EQGP common units upon the director’s termination of service on the general partner’s Board of Directors. The Company accounts for these awards as equity awards and as such recorded compensation expense for the fair value of the awards at the grant date fair value. A total of 2,928 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2015. The weighted average fair value of these grants, based on EQGP’s common unit price on the grant date, was $28.77 for the year ended December 31, 2015. 2016 Value Driver Performance Share Unit Award Program and 2016 Incentive Performance Share Unit Program Effective in 2016, the Compensation Committee of the Board of Directors adopted the 2016 EQT Value Driver Performance Share Unit Award Program (2016 EQT VDPSU) and the 2016 Incentive Performance Share Unit Program (2016 Incentive PSU Program) under the 2014 Long-Term Incentive Plan. The 2016 EQT VDPSU and 2016 Incentive PSU Program were established to align the interests of key employees with the interests of shareholders and customers and the strategic objectives of the Company. A total of 377,330 units were granted under the 2016 EQT VDPSU. Fifty percent of the units confirmed under the 2016 EQT VDPSU will vest upon the payment date following the first anniversary of the grant date; the remaining 50% of the confirmed units under the 2016 EQT VDPSU will vest upon the payment date following the second anniversary of the grant date. The payout will vary between zero and 300% of the number of outstanding units contingent upon adjusted 2016 EBITDA performance as compared to the Company’s annual business plan and individual, business unit and Company value driver performance over the period January 1, 2016 through December 31, 2016. If earned, the 2016 EQT VDPSU units are expected to be paid in cash. The Company did not record any obligation or expense related to the 2016 EQT VDPSU as of December 31, 2015. A total of 468,710 units were granted under the 2016 Incentive PSU Program. The vesting of the units under the 2016 Incentive PSU Program will occur upon payment after December 31, 2018 (the end of the three -year performance period). The payout will vary between zero and 300% of the number of outstanding units contingent upon a combination of the level of total shareholder return relative to a predefined peer group and the level of production sales volume growth over the period January 1, 2016 through December 31, 2018. If earned, the 2016 Incentive PSU Program units are expected to be distributed in Company common stock. The Company did not record any expense related to the 2016 Incentive PSU Program as of December 31, 2015. 2016 Stock Options Effective January 1, 2016, the Compensation Committee granted 188,600 non-qualified stock options to key employees of the Company. The 2016 options are ten -year options, with an exercise price of $52.13 , and are subject to three -year cliff vesting. The Company did not record any expense related to 2016 stock options as of December 31, 2015 .

Concentrations of Credit Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Concentrations of Credit Risk	Concentrations of Credit Risk Revenues and related accounts receivable from the EQT Production segment’s operations are generated primarily from the sale of produced natural gas, NGLs and crude oil to marketers, utility and industrial customers located mainly in the Appalachian Basin and Northeastern United States and a gas processor in Kentucky and West Virginia. Additionally, a significant amount of revenues and related accounts receivable from EQT Midstream are generated from the gathering of natural gas in Kentucky, Virginia, Pennsylvania and West Virginia. The Company had one customer within the EQT Production segment that accounted for approximately 10% , 12% and 11% of revenues in 2015 , 2014 and 2013, respectively. Approximately 79% and 87% of the Company’s accounts receivable balance as of December 31, 2015 and 2014 , respectively, represented amounts due from marketers. The Company manages the credit risk of sales to marketers by limiting its dealings to those marketers that meet the Company’s criteria for credit and liquidity strength and by regularly monitoring these accounts. The Company may require letters of credit, guarantees, performance bonds or other credit enhancements from a marketer in order for that marketer to meet the Company’s credit criteria. As a result, the Company did not experience any significant defaults on sales of natural gas to marketers during the years ended December 31, 2015 , 2014 or 2013 . The Company is exposed to credit loss in the event of nonperformance by counterparties to derivative contracts. This credit exposure is limited to derivative contracts with a positive fair value, which may change as market prices change. The Company believes that NYMEX-traded future contracts have limited credit risk because Commodity Futures Trading Commission (CFTC) regulations are in place to protect exchange participants, including the Company, from any potential financial instability of the exchange members. The Company’s OTC swap and collar derivative instruments are primarily with financial institutions and, thus, are subject to events that would impact those companies individually as well as that industry as a whole. The Company utilizes various processes and analyses to monitor and evaluate its credit risk exposures. These include monitoring current market conditions, counterparty credit fundamentals and credit default swap rates. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals. To manage the level of credit risk, the Company enters into transactions with financial counterparties that are of investment grade or better, enters into netting agreements whenever possible and may obtain collateral or other security. As of December 31, 2015 , the Company was not in default under any derivative contracts and had no knowledge of default by any counterparty to its derivative contracts. The Company made no adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment included in the Company’s established fair value procedure. The Company monitors market conditions that may impact the fair value of derivative contracts reported in the Consolidated Balance Sheets.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The Company has commitments for demand charges under existing long-term contracts and binding precedent agreements with various unconsolidated pipelines as well as commitments with third parties for processing capacity. Future payments for these items as of December 31, 2015 totaled $11.7 billion ( 2016 - $314.2 million , 2017 - $392.7 million , 2018 - $447.6 million , 2019 - $741.2 million , 2020 - $736.1 million and thereafter - $9,040.2 million ). The Company has entered into agreements to release some of its capacity to various third parties. The Company's commitments for demand charges under existing long-term contracts and binding precedent agreements with EQM totaled $5.7 billion as of December 31, 2015. If Moody's or another credit rating agency downgrades the ratings, particularly below investment grade, the Company's or EQM's access to the capital markets may be limited, borrowing costs and margin deposits on the Company’s derivative contracts would increase, the Company may be required to provide additional credit assurances in support of commercial agreements, such as pipeline capacity contracts, joint venture arrangements and subsidiary construction contracts, the amount of which may be substantial, and the potential pool of investors and funding sources may decrease. The Company has agreements with drilling contractors to provide drilling equipment and services to the Company. These obligations totaled approximately $63.2 million as of December 31, 2015 . Operating lease rentals for drilling contractors, office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $85.2 million in 2015 , $65.6 million in 2014 and $56.0 million in 2013 . Future lease payments under non-cancelable operating leases as of December 31, 2015 totaled $155.5 million ( 2016 - $41.5 million , 2017 - $31.5 million , 2018 - $19.7 million , 2019 – $11.9 million , 2020 - $9.8 million and thereafter - $41.1 million ). During 2014, EQM announced that it will construct and own the Ohio Valley Connector (OVC) pipeline. The OVC includes a 37 -mile pipeline that will extend EQM’s transmission and storage system from northern West Virginia to Clarington, Ohio, at which point it will interconnect with the Rockies Express Pipeline and may interconnect with other pipelines and liquidity points. The Company has entered into a 20 years precedent agreement for a total of 650 BBtu per day of firm transmission capacity on the OVC. EQM received its FERC certificate to construct and operate the OVC on December 30, 2015 and construction began in January 2016. EQM expects the OVC to be in-service by year-end 2016. During 2015, the Company assigned its interest in the MVP Joint Venture to EQM. The MVP Joint Venture plans to construct the MVP, an estimated 300 -mile natural gas interstate pipeline spanning from northern West Virginia to southern Virginia. The MVP Joint Venture has secured a total of 2.0 Bcf per day of 20 -year firm capacity commitments, including a 1.29 Bcf per day firm capacity commitment by the Company. The MVP Joint Venture submitted the MVP certificate application to the FERC in October 2015 and anticipates receiving the certificate in the fourth quarter of 2016. Subject to FERC approval, construction is scheduled to begin shortly thereafter and the pipeline is expected to be in-service during the fourth quarter of 2018. The Company is subject to various federal, state and local environmental and environmentally-related laws and regulations. These laws and regulations, which are constantly changing, can require expenditures for remediation and may in certain instances result in assessment of fines. The Company has established procedures for ongoing evaluation of its operations to identify potential environmental exposures and to assure compliance with regulatory policies and procedures. The estimated costs associated with identified situations that require remedial action are accrued. However, certain costs are deferred as regulatory assets when recoverable through regulated rates. Ongoing expenditures for compliance with environmental laws and regulations, including investments in plant and facilities to meet environmental requirements, have not been material. Management believes that any such required expenditures will not be significantly different in either their nature or amount in the future and does not know of any environmental liabilities that will have a material effect on the Company’s financial position, results of operations or liquidity. The Company has identified situations that require remedial action for which approximately $1.0 million is included in other liabilities and credits in the Consolidated Balance Sheets as of December 31, 2015 . In the ordinary course of business, various legal and regulatory claims and proceedings are pending or threatened against the Company. While the amounts claimed may be substantial, the Company is unable to predict with certainty the ultimate outcome of such claims and proceedings. The Company accrues legal or other direct costs related to loss contingencies when actually incurred. The Company has established reserves it believes to be appropriate for pending matters and, after consultation with counsel and giving appropriate consideration to available insurance, the Company believes that the ultimate outcome of any matter currently pending against the Company will not materially affect the financial position, results of operations or liquidity of the Company.

Guarantees

Guarantees	12 Months Ended
	Dec. 31, 2015
Guarantees [Abstract]
Guarantees	Guarantees In connection with the sale of its NORESCO domestic operations in December 2005, the Company agreed to maintain in place guarantees of certain warranty obligations of NORESCO. The savings guarantees provided that once the energy-efficiency construction was completed by NORESCO, the customer would experience a certain dollar amount of energy savings over a period of years. The undiscounted maximum aggregate payments that may be due related to these guarantees were approximately $134 million as of December 31, 2015 , extending at a decreasing amount for approximately 12 years . In December 2014, the Company issued a performance guarantee (the EQT MVP Guarantee) in connection with the obligations of MVP Holdco to fund its proportionate share of the construction budget for the MVP. Upon the transfer of the MVP Interest to EQM on March 30, 2015, EQM entered into a performance guarantee (the Initial EQM Guarantee) on terms and conditions similar to the EQT MVP Guarantee, and the EQT MVP Guarantee was concurrently terminated. Upon the FERC’s initial release to begin construction of the MVP, the Initial EQM Guarantee will terminate, and EQM will be obligated to issue a new guarantee in an amount equal to 33% of MVP Holdco’s remaining obligations to make capital contributions to the MVP Joint Venture in connection with the then remaining construction budget, less any credit assurances issued by any affiliate of EQM under such affiliate's precedent agreement with the MVP Joint Venture. As of December 31, 2015, the Initial EQM Guarantee was in the amount of $108 million . As a result of the ConEd Transaction, the amount of the Initial EQM Guarantee decreased to $91 million as of February 11, 2016.

Interim Financial Information (

Interim Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Interim Financial Information (Unaudited)	Interim Financial Information (Unaudited) The following quarterly summary of operating results reflects variations due primarily to the volatility of natural gas commodity prices, including recognition of impairment expense on long-lived assets, and the seasonal nature of the Company’s storage business. Three Months Ended March 31 June 30 September 30 December 31 (Thousands, except per share amounts) 2015 (a) Total operating revenues (b) $ 714,815 $ 439,589 $ 583,978 $ 601,380 Operating income 314,759 33,034 170,055 45,291 Net income (loss) attributable to EQT Corporation 173,427 5,536 40,787 (134,579 ) Earnings per share of common stock attributable to EQT Corporation: Basic: Net income (loss) $ 1.14 $ 0.04 $ 0.27 $ (0.88 ) Diluted: Net income (loss) $ 1.14 $ 0.04 $ 0.27 $ (0.88 ) 2014 (a) Total operating revenues $ 661,625 $ 526,168 $ 578,723 $ 703,194 Operating income 356,791 224,771 231,503 40,330 Amounts attributable to EQT Corporation: Income (loss) from continuing operations 192,297 109,045 98,555 (14,303 ) (Loss) income from discontinued operations (104 ) 1,876 — (401 ) Net income (loss) attributable to EQT Corporation $ 192,193 $ 110,921 $ 98,555 $ (14,704 ) Earnings per share of common stock attributable to EQT Corporation: Basic: Income (loss) from continuing operations $ 1.27 $ 0.72 $ 0.65 $ (0.10 ) Income from discontinued operations — 0.01 — — Net income (loss) $ 1.27 $ 0.73 $ 0.65 $ (0.10 ) Diluted: Income (loss) from continuing operations $ 1.26 $ 0.72 $ 0.65 $ (0.10 ) Income from discontinued operations — 0.01 — — Net income (loss) $ 1.26 $ 0.73 $ 0.65 $ (0.10 ) (a) The sum of the quarterly data in some cases may not equal the yearly total due to rounding. (b) Differences between the amounts in the above table and those previously reported in the Company's 2015 Form 10-Qs are attributable to a current year reclassification of NGL processing costs which were previously reported as a reduction of operating revenues. The reclassification was immaterial to the amounts previously reported in the Company's 2015 Form 10-Qs.

Natural Gas Producing Activitie

Natural Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Natural Gas Producing Activities (Unaudited)	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, NGL and oil production activities (a): For the Years Ended December 31, 2015 2014 2013 (Thousands) At December 31: Capitalized Costs: Proved properties $ 10,918,499 $ 9,258,298 $ 7,702,724 Unproved properties 898,270 824,527 450,227 Total capitalized costs 11,816,769 10,082,825 8,152,951 Accumulated depreciation and depletion 3,425,618 2,693,535 2,134,953 Net capitalized costs $ 8,391,151 $ 7,389,290 $ 6,017,998 For the Years Ended December 31, 2015 2014 2013 (Thousands) Costs incurred: Property acquisition: Proved properties (b) $ 23,890 $ 231,322 $ 90,390 Unproved properties (c) 158,405 493,067 95,861 Exploration (d) 53,463 16,023 4,285 Development 1,633,498 1,697,501 1,230,301 (a) Amounts exclude capital expenditures for facilities and information technology. (b) Amounts include $198.2 million and $1.1 million for the purchase of Permian wells and leases, respectively, acquired in the Range transaction in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake transaction in 2013. (c) Amounts include $317.2 million for the purchase of Permian leases acquired in the Range transaction in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake transaction in 2013. (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 years ended December 31, 2015 and 2014, the Company recorded unproved property impairments of $19.7 million and $86.6 million , respectively, which are included in the impairment of long-lived assets in the Statements of Consolidated Income. In addition, unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling of $37.4 million , $14.6 million and $14.2 million are included in exploration expense for the years ended December 31, 2015, 2014 and 2013, respectively. Unproved properties had a net book value of $898.3 million and $824.5 million at December 31, 2015 and 2014 , respectively. 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, 2015 2014 2013 (Thousands) Revenues: Affiliated $ 1,412 $ 4,761 $ 5,912 Nonaffiliated 1,154,422 1,724,771 1,305,026 Production costs 398,044 334,050 250,372 Exploration costs 61,970 21,665 18,483 Depreciation, depletion and accretion 723,448 592,855 578,641 Impairment of long-lived assets 118,268 267,339 — Income tax (benefit) expense (58,603 ) 202,881 183,060 Results of operations from producing activities (excluding corporate overhead) $ (87,293 ) $ 310,742 $ 280,382 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 Chemical Engineering from the Pennsylvania State University and has 18 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. In the course of its audit, Ryder Scott reviewed 100% of the total net natural gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2015 . Ryder Scott conducted a detailed, well by well, audit of the Company’s largest properties. This audit covered 80% of the Company’s proved developed reserves. Ryder Scott’s audit of the remaining 20% of the Company’s proved developed properties consisted of an audit of aggregated groups not exceeding 200 wells per case for operated wells and 230 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, 2015 2014 2013 (Millions of Cubic Feet) Total - Natural Gas, Oil, and NGLs (a) Proved developed and undeveloped reserves: Beginning of year 10,738,948 8,348,269 6,004,952 Revision of previous estimates (2,194,675 ) (301,351 ) 191,509 Purchase of hydrocarbons in place — 102,713 472,798 Sale of hydrocarbons in place (61 ) (198,657 ) (455 ) Extensions, discoveries and other additions 2,051,071 3,276,054 2,046,578 Production (618,686 ) (488,080 ) (367,113 ) End of year 9,976,597 10,738,948 8,348,269 Proved developed reserves: Beginning of year 4,826,387 3,985,687 2,798,381 End of year 6,279,557 4,826,387 3,985,687 Proved undeveloped reserves: Beginning of year 5,912,561 4,362,582 3,206,571 End of year 3,697,040 5,912,561 4,362,582 (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, 2015 2014 2013 (Millions of Cubic Feet) Natural Gas Proved developed and undeveloped reserves: Beginning of year 9,775,954 7,561,561 5,985,758 Revision of previous estimates (2,059,531 ) (228,085 ) (375,887 ) Purchase of natural gas in place — 44,867 472,798 Sale of natural gas in place (61 ) (198,531 ) (455 ) Extensions, discoveries and other additions 1,955,935 3,040,938 1,844,840 Production (561,986 ) (444,796 ) (365,493 ) End of year 9,110,311 9,775,954 7,561,561 Proved developed reserves: Beginning of year 4,257,377 3,567,313 2,779,187 End of year 5,652,989 4,257,377 3,567,313 Proved undeveloped reserves: Beginning of year 5,518,577 3,994,248 3,206,571 End of year 3,457,322 5,518,577 3,994,248 Years Ended December 31, 2015 2014 2013 (Thousands of Bbls) Oil (a) Proved developed and undeveloped reserves: Beginning of year 5,005 3,956 3,199 Revision of previous estimates 1,219 (905 ) 270 Purchase of oil in place — 2,165 — Sale of oil in place — (3 ) — Extensions, discoveries and other additions 419 241 757 Production (743 ) (449 ) (270 ) End of year 5,900 5,005 3,956 Proved developed reserves: Beginning of year 5,005 3,892 3,199 End of year 5,900 5,005 3,892 Proved undeveloped reserves: Beginning of year — 64 — End of year — — 64 (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). Years Ended December 31, 2015 2014 2013 (Thousands of Bbls) NGLs (a) Proved developed and undeveloped reserves: Beginning of year 155,494 127,162 — Revision of previous estimates (23,743 ) (11,306 ) 94,296 Purchase of NGLs in place — 7,476 — Sale of NGLs in place — (18 ) — Extensions, discoveries and other additions 15,437 38,945 32,866 Production (8,707 ) (6,765 ) — End of year 138,481 155,494 127,162 Proved developed reserves: Beginning of year 89,830 65,837 — End of year 98,528 89,830 65,837 Proved undeveloped reserves: Beginning of year 65,664 61,325 — End of year 39,953 65,664 61,325 (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). During 2015, the Company recorded net downward revisions of 2,195 Bcfe to the December 31, 2014 estimates of its reserves due primarily to the removal of 2,168 Bcfe associated with undeveloped locations that are not currently planned to be drilled within 5 years of initial booking. The majority of these locations are no longer economic as determined in accordance with SEC pricing requirements, while 342 Bcfe of proved undeveloped reserves were removed for economic locations that the Company no longer intends to develop within 5 years of booking. Additional downward revisions of 259 Bcfe were associated with previously booked locations whose economic lives have been shortened due to reduced commodity prices. These decreases were partially offset by 386 Bcfe of increased proved developed reserves primarily due to improved performance of producing locations. The Company’s 2015 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 2,051 Bcfe exceeded the 2015 production of 619 Bcfe. These reserve extensions and discoveries were mainly due to the addition of proved undeveloped locations in the Company’s Pennsylvania and West Virginia Marcellus fields, the extension of lateral lengths associated with existing proved undeveloped locations, and the development of locations not previously booked as proved. During 2015, the Company revised its approach utilized to determine the gathering cost assumption within our 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 and EQM. Had the approach used in 2015 been used by the Company in 2014, the reserve estimates for 2014 would not have materially changed. 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. During 2014, the Company recorded net downward revisions of 301.4 Bcfe to the December 31, 2013 estimates of its reserves due primarily to the removal of 1,047.2 Bcfe associated with undeveloped locations that would not be drilled within 5 years of initial booking. This total included locations that were no longer economic in accordance with SEC pricing requirements as well as the remainder of proved undeveloped Huron locations that were no longer planned for development following the Company’s decision to suspend development of this play. This decrease was partially offset by 845.1 Bcfe of increased reserves primarily due to improved performance of proved developed producing locations and increased lateral lengths for previously booked undeveloped Marcellus locations. The Company’s 2014 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 3,276.1 Bcfe exceeded the 2014 production of 488.1 Bcfe. These reserve extensions and discoveries were mainly due to the addition of proved undeveloped locations in the Company’s Pennsylvania and West Virginia Marcellus fields and the development of locations not previously booked as proved. 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 included NGL reserves for the first time in 2013. This caused a one-time decrease in gas reserves and an increase in equivalent NGL 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. 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: 2015 2014 2013 (Thousands) Future cash inflows (a) $ 10,071,465 $ 30,428,815 $ 25,912,542 Future production costs (3,415,715 ) (4,868,079 ) (4,180,136 ) Future development costs (2,377,650 ) (5,052,195 ) (4,199,722 ) Future income tax expenses (1,333,989 ) (7,718,407 ) (6,533,817 ) Future net cash flow 2,944,111 12,790,134 10,998,867 10% annual discount for estimated timing of cash flows (1,966,557 ) (7,980,106 ) (7,047,588 ) Standardized measure of discounted future net cash flows $ 977,554 $ 4,810,028 $ 3,951,279 (a) 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 West Texas Intermediate (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, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Utica reserves, and $17.51 per Bbl for Permian reserves. For 2014, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2014 of $94.99 per Bbl of oil (first day of each month closing price for WTI less regional adjustments), $4.278 per Dth for Columbia Gas Transmission Corp., $3.191 per Dth for Dominion Transmission, Inc., $4.350 per Dth for the East Tennessee Natural Gas Pipeline, $3.258 per Dth for Texas Eastern Transmission Corp., $2.286 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $4.170 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $4.152 per Dth for Waha, and $4.243 per Dth for Houston Ship Channel. For 2014, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2014 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $49.22 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $49.47 per Bbl of NGLs from certain Kentucky reserves, $47.11 per Bbl for Utica reserves, and $31.92 per Bbl for Permian reserves. 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 regional adjustments), $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 2013, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2013 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $51.91 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $49.38 per Bbl of NGLs from certain Kentucky reserves, and $48.14 per Bbl for Utica 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, 2015 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $788.6 million , $26.0 million and $533.8 million , respectively. Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31: 2015 2014 2013 (Thousands) Sales and transfers of natural gas and oil produced – net $ (757,789 ) $ (1,479,242 ) $ (1,060,566 ) Net changes in prices, production and development costs (5,566,232 ) (1,525,944 ) (292,533 ) Extensions, discoveries and improved recovery, less related costs 264,735 2,300,923 1,509,002 Development costs incurred 971,186 1,023,075 1,319,135 Purchase of minerals in place – net — 72,139 348,608 Sale of minerals in place – net (43 ) (146,476 ) (252 ) Revisions of previous quantity estimates (1,541,419 ) (222,195 ) 106,170 Accretion of discount 600,099 578,676 343,502 Net change in income taxes 2,424,200 (529,337 ) (1,031,105 ) Timing and other (227,211 ) 787,130 554,159 Net (decrease) increase (3,832,474 ) 858,749 1,796,120 Beginning of year 4,810,028 3,951,279 2,155,159 End of year $ 977,554 $ 4,810,028 $ 3,951,279

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation: The Consolidated Financial Statements include the accounts of EQT Corporation and all subsidiaries, ventures and partnerships in which a controlling interest is held (EQT or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. The results of EQT GP Holdings, LP (EQGP) and EQT Midstream Partners, LP (EQM) are both consolidated in the Company’s financial statements. The Company records the noncontrolling interests of the public limited partners in its financial statements.
Segments	Segments: Operating segments are revenue-producing components of the enterprise for which separate financial information is produced internally and which are subject to evaluation by the Company’s chief operating decision maker in deciding how to allocate resources. The Company reports its operations in two segments, which reflect its lines of business. The EQT Production segment includes the Company’s exploration for, and development and production of, natural gas, natural gas liquids (NGLs) and a limited amount of crude oil, primarily in the Appalachian Basin. EQT Midstream’s operations include the natural gas gathering, transmission, storage and marketing activities of the Company, including ownership and operation of EQGP and EQM. Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in the United States.
Reclassification	Reclassification: Certain previously reported amounts have been reclassified to conform to the current year presentation.
Use of Estimates	Use of Estimates: The preparation of financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and accompanying notes. Actual results could differ from those estimates.
Cash Equivalents	Cash Equivalents: The Company considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. These investments are accounted for at cost. Interest earned on cash equivalents is included as a reduction of interest expense.
Inventories	Inventories: Generally, the Company’s inventory balance consists of natural gas stored underground or in pipelines and materials and supplies recorded at the lower of average cost or market.
Property, Plant and Equipment	Property, Plant and Equipment: The Company’s property, plant and equipment consist of the following: As of December 31, 2015 2014 (Thousands) Oil and gas producing properties, successful efforts method $ 11,816,769 $ 10,082,825 Accumulated depreciation and depletion (3,425,618 ) (2,693,535 ) Net oil and gas producing properties 8,391,151 7,389,290 Midstream plant 3,703,994 3,234,370 Accumulated depreciation and amortization (685,398 ) (606,998 ) Net midstream plant 3,018,596 2,627,372 Other properties, at cost less accumulated depreciation 62,274 60,152 Net property, plant and equipment $ 11,472,021 $ 10,076,814 The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, the cost of productive wells, wells and related equipment, development dry holes, as well as productive acreage, including productive mineral interest, are capitalized and depleted using the unit-of-production method. These capitalized costs include salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized internal costs of $114.4 million , $108.5 million and $93.5 million in 2015 , 2014 and 2013 , respectively. The Company capitalized $35.8 million , $35.0 million and $22.9 million of interest relative to Marcellus and Utica well development in 2015 , 2014 and 2013 , respectively. Depletion expense is calculated based on the actual production multiplied by the applicable depletion rate per unit. The depletion rates are derived by dividing the net capitalized costs by the number of units expected to be produced over the life of the reserves for lease costs and well costs separately. Costs of exploratory dry holes, exploratory geological and geophysical activities, delay rentals and other property carrying costs are charged to expense. The majority of the Company’s producing oil and gas properties consist of producing gas properties which were depleted at an overall average rate of $1.18 per Mcfe, $1.22 per Mcfe and $1.50 per Mcfe for the years ended December 31, 2015 , 2014 and 2013 , respectively. The carrying values of the Company’s proved oil and gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. In order to determine whether impairment has occurred, the Company estimates the expected future cash flows (on an undiscounted basis) from its oil and gas properties and compares these estimates to the carrying values of the properties. The estimated future cash flows used to test those properties for recoverability are based on proved and, if determined reasonable by management, risk-adjusted probable and possible reserves, utilizing assumptions generally consistent with the assumptions utilized by the Company's management for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas, NGLs and oil, adjusted accordingly for basis differentials, future operating costs and inflation, some of which are interdependent. Proved oil and gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rate and other assumptions that marketplace participants would use in their estimates of fair value. Due to the decline in commodity prices during 2015 and 2014, there were indications that the carrying values of certain of the Company’s oil and gas producing properties were impaired and future undiscounted cash flows attributed to these assets indicated their carrying amounts were not expected to be fully recovered. Their fair value was measured using an income approach based upon estimates of future production levels, commodity prices, operating costs and discount rates. The future production levels, future commodity prices, which were inflated for periods after the five -year forward price curve and included observed basis differentials and contractual transportation costs, future operating costs, which were inflated consistent with price assumptions, as well as the assumed market participant discount rate, which was estimated to be a rate of 12% , were considered to be significant unobservable inputs in the Company's calculation of fair value. As a result, valuation of the impaired assets was considered to be a Level 3 fair value measurement. For the years ended December 31, 2015 and 2014, EQT Production recognized pretax impairment charges on proved oil and gas properties of $98.6 million and $180.7 million , respectively, which are included in impairment of long-lived assets in the Statements of Consolidated Income. The 2015 impairment included a charge of $94.3 million to record the proved properties in the Permian Basin of Texas at a fair value of $44.8 million and a charge of $4.3 million to record the proved properties in the Utica Shale of Ohio at a fair value of $5.7 million . After this charge to the Permian assets, the carrying value of Permian properties as of December 31, 2015 was approximately $345 million , including approximately $300 million of undeveloped properties. Because the estimated future undiscounted cash flows from the Company’s proved oil and gas properties in the Marcellus play and the non-core Huron and Coalbed Methane plays exceeded the carrying values of the respective properties, the Company did not recognize an impairment charge in 2015 related to these oil and gas properties. The 2014 impairment included charges of $105.2 million to record the proved properties in the Permian Basin of Texas at a fair value of $109.2 million and $75.5 million to record the proved properties in the Utica Shale of Ohio at a fair value of $7.4 million . The 2015 and 2014 impairments on proved properties in the Permian Basin of Texas were due to a decline in commodity prices. The 2015 and 2014 impairments in the Utica Shale of Ohio were a result of insufficient recovery of hydrocarbons to support continued development, along with the decline in commodity prices. For the year ended December 31, 2013, the Company did not recognize impairment charges on proved oil and gas properties. 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 brought about by 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, the related costs are expensed in the period in which that determination is made. For the years ended December 31, 2015 and 2014, EQT Production recorded unproved property impairments of $19.7 million and $86.6 million , respectively, which are included in impairment of long-lived assets in the Statements of Consolidated Income. For the year ended December 31, 2013, the Company did not recognize impairment charges on unproved oil and gas properties. The unproved property impairment in 2015 related to the Company’s non-core Marcellus acreage, based on the Company’s decision to focus near-term development on its core Marcellus and deep Utica acreage. The unproved property impairment in 2014 related to the Company’s decision to stop development of properties in its Utica Shale of Ohio. In addition, unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling of $37.4 million , $14.6 million and $14.2 million are included in exploration expense of EQT Production for the years ended December 31, 2015, 2014 and 2013, respectively. Unproved properties had a net book value of $898.3 million and $824.5 million at December 31, 2015 and 2014 , respectively. At December 31, 2014, the Company had $9.0 million of capitalized exploratory well costs that were pending the determination of proved reserves. These exploratory well costs were reclassified to wells, equipment and facilities during the third quarter of 2015 upon the successful completion of the Company’s first deep Utica well in Pennsylvania. During 2015, the Company drilled one exploratory dry hole within its non-core acreage and the related expenditures have been included within exploration expense in the Statements of Consolidated Income as of December 31, 2015. There were no capitalized exploratory wells costs at December 31, 2015 and 2013. Midstream property, plant and equipment is carried at cost. Depreciation is calculated using the straight-line method based on estimated service lives. Midstream property consists largely of gathering and transmission systems ( 25 - 60 year estimated service life), buildings ( 35 year estimated service life), office equipment ( 3 - 7 year estimated service life), vehicles ( 5 year estimated service life), and computer and telecommunications equipment and systems ( 3 - 7 year estimated service life). Major maintenance projects that do not increase the overall life of the related assets are expensed. When major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. When events or changes in circumstances indicate that the carrying amount of any long-lived asset other than proved and unproved oil and gas properties may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company records an impairment loss equal to the difference between the carrying value and fair value of the assets. During the year ended December 31, 2015, EQT Midstream recorded an impairment of long-lived assets of approximately $4.2 million related to an asset that will not be utilized in Midstream operations. No impairment of any long-lived asset other than proved and unproved oil and gas properties was recorded in 2014 or 2013.
Sales and Retirements Policies	Sales and Retirements Policies: No gain or loss is recognized on the partial sale of proved developed oil and gas reserves unless non-recognition would significantly alter the relationship between capitalized costs and remaining proved reserves for the affected amortization base. When gain or loss is not recognized, the amortization base is reduced by the amount of the proceeds.
Regulatory Accounting	Regulatory Accounting: EQT Midstream’s regulated operations include interstate pipeline operations subject to regulation by the Federal Energy Regulatory Commission (FERC) and certain FERC-regulated gathering operations. The application of regulatory accounting allows the Company to defer expenses and income on its Consolidated Balance Sheets as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the Statements of Consolidated Income for a non-regulated company. The deferred regulatory assets and liabilities are then recognized in the Statements of Consolidated Income in the period in which the same amounts are reflected in rates. The following table presents the total regulated net revenues and operating expenses included in the operations of EQT Midstream: Years Ended December 31, 2015 2014 2013 (Thousands) Net revenues $ 309,984 $ 267,997 $ 184,767 Operating expenses $ 109,954 $ 89,617 $ 71,517 The following table presents the regulated net property, plant and equipment included in EQT Midstream: As of December 31, 2015 2014 (Thousands) Property, plant & equipment $ 1,356,206 $ 1,160,696 Accumulated depreciation and amortization (193,349 ) (188,884 ) Net property, plant & equipment $ 1,162,857 $ 971,812 The regulatory assets associated with deferred taxes of $73.1 million and $15.2 million as of December 31, 2015 and 2014 , respectively, are included in other assets in the Consolidated Balance Sheets and primarily represent deferred income taxes recoverable through future rates related to a historical deferred tax position and the equity component of allowance for funds used during construction (AFUDC). The Company expects to recover the amortization of the deferred tax position ratably over the corresponding life of the underlying assets that created the difference. The deferred tax regulatory asset associated with AFUDC represents the offset to the deferred taxes associated with the equity component of AFUDC of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes will be collected through rates over the depreciable lives of the long-lived assets to which they relate.
Derivative Instruments	Derivative Instruments: Derivatives are held as part of a formally documented risk management program. The Company’s use of derivative instruments is implemented under a set of policies approved by the Company’s Hedge and Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Company's Board of Directors. The HFRC is composed of the chief executive officer, the president, the chief financial officer and other officers of the Company. In regards to commodity price risk, the financial instruments currently utilized by the Company are primarily fixed price swap agreements and collar agreements which may require payments to or receipt of payments from counterparties based on the differential between two prices for the commodity. The Company also uses a limited number of other contractual agreements in implementing its commodity hedging strategy. The Company may execute interest rate swap agreements to hedge exposures to fluctuations in interest rates. The Company does not enter into derivative instruments for trading purposes. The accounting for the changes in fair value of the Company’s derivative instruments depends on the use of the derivative instruments. To the extent that a derivative instrument has been designated and qualifies as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of accumulated other comprehensive income (OCI), net of tax, and is subsequently reclassified into the Statements of Consolidated Income in the same period or periods during which the hedged forecasted transaction affects earnings. The Company assesses the effectiveness of hedging relationships, as determined by the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, both at the inception of the hedge and on an on-going basis. If the gain (loss) for the hedging instrument is greater than the loss (gain) on the hedged item, the ineffective portion of the cash flow hedge is immediately recognized in operating revenues in the Statements of Consolidated Income. Effective December 31, 2014, the Company elected to de-designate all derivative commodity instruments that were designated and qualified as cash flow hedges. If a cash flow hedge was terminated or de-designated as a hedge before the settlement date of the hedged item, the amount of deferred gain or loss within accumulated OCI recorded up to that date remained deferred, provided that the forecasted transaction remained probable of occurring. Subsequent changes in fair value of a de-designated derivative instrument are recorded in earnings. The amount recorded in accumulated OCI is primarily related to instruments that were previously designated as cash flow hedges. Any changes in fair value of derivative instruments that have not been designated as hedges are recognized within operating revenues in the Statements of Consolidated Income each period. The Company reports all gains and losses on its natural gas derivative commodity instruments net as operating revenues on its Statements of Consolidated Income.
AFUDC	AFUDC: Carrying costs for the construction of certain long-term assets are capitalized by the Company and amortized over the related assets’ estimated useful lives. The capitalized amount for construction of regulated assets includes interest cost and a designated cost of equity for financing the construction of these assets which are subject to regulation by the FERC. The debt portion of AFUDC is calculated based on the average cost of debt and is included as a reduction of interest expense in the Statements of Consolidated Income. AFUDC interest costs capitalized were $1.6 million , $1.0 million and $0.5 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. The equity portion of AFUDC is calculated using the most recent equity rate of return approved by the applicable regulator. Equity amounts capitalized are included in other income in the Statements of Consolidated Income. The AFUDC equity amounts capitalized were $6.3 million , $3.2 million and $1.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.
Revenue Recognition	Revenue Recognition: Revenue is recognized for production and gathering activities when deliveries of natural gas, NGLs and crude oil occur. Revenues from natural gas transmission and storage activities are recognized in the period the service is provided. Reservation revenues on firm contracted capacity are recognized over the contract period based on the contracted volume regardless of the amount of natural gas that is transported. The Company reports revenue from all energy trading contracts net in the Statements of Consolidated Income, regardless of whether the contracts are physically or financially settled. Contracts which result in physical delivery of a commodity expected to be used or sold by the Company in the normal course of business are considered normal purchases and sales and are not subject to derivative accounting. Revenues from these contracts are recognized at contract value when delivered and are reported in operating revenues. The Company reports all gains and losses on its derivative commodity instruments net as operating revenues on its Statements of Consolidated Income. The Company accounts for gas-balancing arrangements under the entitlement method. The Company uses the gross method to account for overhead cost reimbursements from joint operating partners. During periods in which rates are subject to refund as a result of a pending rate case, the Company records revenue at the rates which are pending approval but reserves these revenues to the level of previously approved rates until the final settlement of the rate case.
Investments in Consolidated Affiliates and Nonconsolidated Affiliates	Investments in Consolidated Affiliates : In January 2015, the Company formed EQGP to own the Company's partnership interests in EQM. On May 15, 2015, EQGP completed an initial public offering (IPO) of 26,450,000 common units representing limited partner interests in EQGP, which represented 9.9% of EQGP's outstanding limited partner interests. The Company retained 239,715,000 common units, which represented a 90.1% limited partner interest, and the entire non-economic general partner interest, in EQGP. As of December 31, 2015, EQGP owned 21,811,643 EQM common units, representing a 27.6% limited partner interest in EQM; 1,443,015 EQM general partner units, representing a 1.8% general partner interest in EQM; and all of EQM's incentive distribution rights. EQGP and EQM are both consolidated in the Company's consolidated financial statements and the Company records the noncontrolling interests of the public limited partners in its financial statements. See Notes 3 and 4. Investments in Nonconsolidated Affiliates: Investments in companies in which the Company has the ability to exert significant influence over operating and financial policies (generally 20% to 50% ownership), but which the Company does not control, are accounted for using the equity method. Under the equity method, investments are initially recorded at cost and adjusted for dividends and undistributed earnings and losses. The Company evaluates its investments in nonconsolidated affiliates for impairment whenever events or changes in circumstances indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in value that is other than temporary, the Company compares the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred. If the estimated fair value is less than the carrying value, the excess of the carrying value over the estimated fair value is recognized as an impairment loss. See Note 11.
Unamortized Debt Discount and Issuance Expense	Unamortized Debt Discount and Issuance Expense: Discounts and expenses incurred with the issuance of long-term debt are amortized over the term of the debt. These amounts are presented as a reduction of long-term debt on the accompanying Consolidated Balance Sheets. See Note 13.
Transportation and Processing	Transportation and Processing: Third-party costs incurred to gather, process and transport gas produced by EQT Production to market sales points are recorded as a portion of transportation and processing costs in the Statements of Consolidated Income. The Company markets some transportation for resale and the related costs are not incurred to transport gas produced by EQT Production. These transportation costs are reflected as a deduction from operating revenues.
Income Taxes	Income Taxes: The Company files a consolidated federal income tax return and utilizes the asset and liability method to account for income taxes. The provision for income taxes represents amounts paid or estimated to be payable, net of amounts refunded or estimated to be refunded, for the current year and the change in deferred taxes, exclusive of amounts recorded in OCI. Any refinements to prior years’ taxes made due to subsequent information are reflected as adjustments in the current period. Separate income taxes are calculated for income from continuing operations, income from discontinued operations and items charged or credited directly to stockholders’ equity. Deferred income tax assets and liabilities are determined based on temporary differences between the financial reporting and tax bases of assets and liabilities and are recognized using enacted tax rates for the effect of such temporary differences. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In accounting for uncertainty in income taxes of a tax position taken or expected to be taken in a tax return, the Company utilizes a recognition threshold and measurement attribute for the financial statement recognition and measurement. The recognition threshold requires the Company to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If it is more likely than not that a tax position will be sustained, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The Company recognizes interest and penalties accrued related to unrecognized tax benefits in income tax expense.
Provision For Doubtful Accounts	Provision for Doubtful Accounts: Judgment is required to assess the ultimate realization of the Company’s accounts receivable, including assessing the probability of collection and the creditworthiness of certain customers. Reserves for uncollectible accounts are recorded as part of selling, general and administrative expense in the Statements of Consolidated Income. The reserves are based on historical experience, current and expected economic trends and specific information about customer accounts.
Earnings Per Share (EPS)	Earnings Per Share (EPS): Basic EPS are computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares outstanding during the period, without considering any dilutive items. Diluted EPS are computed by dividing net income attributable to EQT Corporation by the weighted average number of common shares and potentially dilutive securities, net of shares assumed to be repurchased using the treasury stock method. Purchases of treasury shares are calculated using the average share price for the Company’s common stock during the period. Potentially dilutive securities arise from the assumed conversion of outstanding stock options and other share-based awards. See Note 16.
Asset Retirement Obligations	Asset Retirement Obligations : The Company accrues a liability for legal asset retirement obligations based on an estimate of the timing and amount of settlement. For oil and gas wells, the fair value of the Company’s plugging and abandonment obligations is required to be recorded at the time the obligations are incurred, which is typically at the time the wells are spud. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value, through charges to depreciation, depletion and amortization, and the initial capitalized costs are depleted over the useful lives of the related assets. The Company is required to operate and maintain its natural gas pipeline and storage systems, and intends to do so as long as supply and demand for natural gas exists, which the Company expects for the foreseeable future. Therefore, the Company believes that the substantial majority of its natural gas pipeline and storage system assets have indeterminate lives.
Self-Insurance	Self-Insurance: The Company is self-insured for certain losses related to workers’ compensation and maintains a self-insured retention for general liability, automobile liability, environmental liability and other casualty coverage. The Company maintains stop loss coverage with third-party insurers to limit the total exposure for general liability, automobile liability, environmental liability and workers’ compensation. The recorded reserves represent estimates of the ultimate cost of claims incurred as of the balance sheet date. The estimated liabilities are based on analyses of historical data and actuarial estimates and are not discounted. The liabilities are reviewed by management quarterly and by independent actuaries annually to ensure that they are appropriate. While the Company believes these estimates are reasonable based on the information available, financial results could be impacted if actual trends, including the severity or frequency of claims, differ from estimates.
Noncontrolling interest	Noncontrolling interests: Noncontrolling interests represent third-party equity ownership in EQGP and EQM and are presented as a component of equity in the Consolidated Balance Sheets. In the Statements of Consolidated Income, noncontrolling interests reflect the allocation of earnings to third-party investors. See Notes 3 and 4 for further discussion of noncontrolling interests related to EQGP and EQM.
Recently Issued Accounting Standards	Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers . The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU No. 2014-09 will supersede most of the existing revenue recognition requirements in United States GAAP when it becomes effective and is required to be adopted using one of two retrospective application methods. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers - Deferral of the Effective Date which approved a one year deferral of ASU 2014-09 for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early application is permitted as of the original effective date for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures. In February 2015, the FASB issued ASU No. 2015-02, Consolidation . The standard changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The ASU will be effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. The Company has evaluated this standard and determined that the adoption of it will have no significant impact on reported results. In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest . The standard requires an entity to present the debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU No. 2015-15, Interest - Imputation of Interest. The standard added Securities and Exchange Commission (SEC) paragraphs to clarify the applicability of ASU No. 2015-03 to debt issuance costs related to line-of-credit arrangements. The guidance in ASU No. 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. The Company has early adopted these standards and all prior periods presented in this Annual Report have been recast to reflect the change in accounting principle. The Consolidated Balance Sheet as of December 31, 2014 has been adjusted to apply the change in accounting principle retrospectively, which resulted in a decrease in other assets of $29.5 million , a decrease in the current portion of long-term debt of $0.1 million , a decrease in long-term debt of $29.4 million and a decrease in total liabilities of $29.5 million as of December 31, 2014. There was no impact to the Statements of Consolidated Income as a result of the change in accounting principle. In April 2015, the FASB issued ASU No. 2015-05, Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement . The ASU adds guidance that will help entities evaluate the accounting for fees paid by a customer in a cloud computing arrangement. The ASU will be effective for annual reporting periods beginning after December 15, 2015. The Company has early adopted this standard which had no significant impact on reported results or related disclosures. In November 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740) . The ASU requires deferred liabilities and assets to be classified as noncurrent in a classified statement of financial position. The ASU is effective for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company has early adopted this standard prospectively as of January 1, 2015, which had no significant impact on reported results or related disclosures. Prior periods were not retrospectively adjusted as a result of the change in accounting principle.
Subsequent Events	Subsequent Events: The Company has evaluated subsequent events through the date of the financial statement issuance.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of property, plant and equipment	The Company’s property, plant and equipment consist of the following: As of December 31, 2015 2014 (Thousands) Oil and gas producing properties, successful efforts method $ 11,816,769 $ 10,082,825 Accumulated depreciation and depletion (3,425,618 ) (2,693,535 ) Net oil and gas producing properties 8,391,151 7,389,290 Midstream plant 3,703,994 3,234,370 Accumulated depreciation and amortization (685,398 ) (606,998 ) Net midstream plant 3,018,596 2,627,372 Other properties, at cost less accumulated depreciation 62,274 60,152 Net property, plant and equipment $ 11,472,021 $ 10,076,814
Schedule of regulated net revenues and operating expenses	The following table presents the total regulated net revenues and operating expenses included in the operations of EQT Midstream: Years Ended December 31, 2015 2014 2013 (Thousands) Net revenues $ 309,984 $ 267,997 $ 184,767 Operating expenses $ 109,954 $ 89,617 $ 71,517
Schedule of regulated net property, plant and equipment	The following table presents the regulated net property, plant and equipment included in EQT Midstream: As of December 31, 2015 2014 (Thousands) Property, plant & equipment $ 1,356,206 $ 1,160,696 Accumulated depreciation and amortization (193,349 ) (188,884 ) Net property, plant & equipment $ 1,162,857 $ 971,812
Schedule of other current liabilities	Other current liabilities as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 (Thousands) Incentive compensation $ 67,049 $ 70,826 Taxes other than income 44,925 52,035 Accrued interest payable 36,330 37,349 All other accrued liabilities 33,531 40,239 Total other current liabilities $ 181,835 $ 200,449
Reconciliation of the beginning and ending carrying amounts of asset retirement obligations	The Company does not have any assets that are legally restricted for purposes of settling these obligations. Years Ended December 31, 2015 2014 (Thousands) Asset retirement obligation as of beginning of period $ 140,086 $ 116,045 Accretion expense 10,646 9,420 Liabilities incurred 2,251 16,953 Liabilities settled (5,027 ) (14,025 ) Change in estimates 20,186 11,693 Asset retirement obligation as of end of period $ 168,142 $ 140,086
Schedule of components of accumulated OCI, net of tax	The components of accumulated OCI, net of tax, are as follows: As of December 31, 2015 2014 (Thousands) Net gain from natural gas hedging transactions $ 64,762 $ 217,121 Net loss from interest rate swaps (843 ) (987 ) Pension and other post-retirement benefits liability adjustment (17,541 ) (16,640 ) Accumulated OCI $ 46,378 $ 199,494

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Summary of the components of discontinued operations activity	The following table summarizes the components of discontinued operations activity: Years Ended December 31, 2015 2014 2013 (Thousands) Operating revenues $ — $ — $ 332,947 Income from discontinued operations before income taxes — 2,377 251,378 Income taxes — 1,006 159,535 Income from discontinued operations, net of tax $ — $ 1,371 $ 91,843

Financial Information by Busi35

Financial Information by Business Segment (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of revenue from external customers, operating income and reconciliation of operating income to income from continuing operations	Years Ended December 31, 2015 2014 2013 (Thousands) Revenues from external customers, including affiliates: EQT Production $ 1,540,889 $ 1,813,292 $ 1,310,938 EQT Midstream 807,904 699,083 614,042 Less intersegment revenues, net (a) (9,031 ) (42,665 ) (62,969 ) Total $ 2,339,762 $ 2,469,710 $ 1,862,011 Operating income: EQT Production (b) $ 104,865 $ 505,950 $ 371,245 EQT Midstream (b) 473,378 384,309 328,782 Unallocated expenses (c) (15,104 ) (36,864 ) (45,423 ) Total operating income $ 563,139 $ 853,395 $ 654,604 Reconciliation of operating income to income from continuing operations: Other income $ 9,953 $ 6,853 $ 9,242 Interest expense 146,531 136,537 142,688 Income tax expense 104,675 214,092 175,186 Income from continuing operations $ 321,886 $ 509,619 $ 345,972 (a) Eliminates intercompany natural gas sales from EQT Production to EQT Midstream. (b) Gains on sales / exchanges of assets of $27.4 million and $6.8 million are included in EQT Production and EQT Midstream operating income, respectively, for 2014. See Note 8. Impairment of long-lived assets of $118.3 million and $267.3 million are included in EQT Production operating income for 2015 and 2014, respectively. Impairment of long-lived assets of $4.2 million is included in EQT Midstream operating income for 2015. See Note 1 for a discussion of impairment of long-lived assets. (c) Unallocated expenses consist primarily of a $20.0 million contribution to the EQT Foundation in 2014, incentive compensation expense, and administrative costs.
Schedule of segment assets	As of December 31, 2015 2014 2013 (Thousands) Segment assets: EQT Production $ 8,995,853 $ 8,153,199 $ 6,359,065 EQT Midstream 3,226,138 2,709,052 2,514,429 Total operating segments 12,221,991 10,862,251 8,873,494 Headquarters assets, including cash and short-term investments 1,754,181 1,173,102 892,413 Total assets $ 13,976,172 $ 12,035,353 $ 9,765,907
Schedule of depreciation, depletion and amortization and expenditures for segment assets	Years Ended December 31, 2015 2014 2013 (Thousands) Depreciation, depletion and amortization: EQT Production $ 723,448 $ 592,855 $ 578,641 EQT Midstream 95,280 87,034 75,032 Other 488 (591 ) (541 ) Total $ 819,216 $ 679,298 $ 653,132 Expenditures for segment assets: (d) EQT Production (e) $ 1,852,100 $ 2,441,486 $ 1,423,185 EQT Midstream 486,809 455,359 369,399 Other 5,505 3,341 4,292 Total $ 2,344,414 $ 2,900,186 $ 1,796,876 (d) Includes a portion of non-cash stock-based compensation expense and the impact of capital accruals. (e) Expenditures for segment assets in the EQT Production segment included $182.3 million , $724.4 million and $186.2 million for property acquisitions in 2015 , 2014 and 2013 , respectively. Included within the $724.4 million of property acquisitions for the year ended December 31, 2014 was $349.2 million of non-cash capital expenditures for the exchange of assets with Range (described in Note 8).

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivatives designated and not designated as hedging instruments	Years Ended December 31, 2015 2014 2013 (Thousands) Commodity derivatives designated as cash flow hedges Amount of gain recognized in OCI (effective portion), net of tax $ — $ 156,207 $ 10,669 Amount of gain reclassified from accumulated OCI, net of tax, into gain on sale / exchange of assets and dispositions due to forecasted transactions probable to not occur — 16,735 — Amount of gain (loss) reclassified from accumulated OCI, net of tax, into operating revenues (effective portion) 152,359 (15,950 ) 87,158 Amount of gain (loss) recognized in operating revenues (ineffective portion) (a) — 24,774 (21,335 ) Interest rate derivatives designated as cash flow hedges Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion) $ (144 ) $ (145 ) $ (144 ) Commodity derivatives designated as fair value hedges (b) Amount of loss recognized in operating revenues for fair value commodity contracts $ — $ — $ (1,341 ) Fair value gain recognized in operating revenues for inventory designated as hedged item — — 386 Derivatives not designated as hedging instruments Amount of gain recognized in operating revenues $ 385,762 $ 80,942 $ 2,834 (a) No amounts were excluded from effectiveness testing of cash flow hedges. (b) For the year ended December 31, 2013, the net impact on operating revenues consisted of a $0.5 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $1.5 million loss due to changes in basis.
Schedule of impact of netting agreements and margin deposits on gross derivative assets and liabilities	The table below reflects the impact of netting agreements and margin deposits on gross derivative assets and liabilities as of December 31, 2015 and 2014 . As of December 31, 2015 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 417,397 $ (19,909 ) $ — $ 397,488 Liability derivatives: Derivative instruments, at fair value $ 23,434 $ (19,909 ) $ — $ 3,525 As of December 31, 2014 Derivative instruments, recorded in the Consolidated Balance Sheet, gross Derivative instruments subject to master netting agreements Margin deposits remitted to counterparties Derivative instruments, net (Thousands) Asset derivatives: Derivative instruments, at fair value $ 458,460 $ (22,810 ) $ — $ 435,650 Liability derivatives: Derivative instruments, at fair value $ 22,942 $ (22,810 ) $ (132 ) $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of assets and liabilities measured at fair value on a recurring basis	The following assets and liabilities were measured at fair value on a recurring basis during the applicable period: Fair value measurements at reporting date using Description December 31, 2015 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 417,397 $ — $ 417,397 $ — Liabilities Derivative instruments, at fair value $ 23,434 $ — $ 23,434 $ — Fair value measurements at reporting date using Description December 31, 2014 Quoted prices in active markets for identical assets (Level 1) Significant other observable inputs (Level 2) Significant unobservable inputs (Level 3) (Thousands) Assets Derivative instruments, at fair value $ 458,460 $ — $ 458,460 $ — Liabilities Derivative instruments, at fair value $ 22,942 $ 132 $ 22,810 $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of income tax expense (benefit) from continuing operations	Income tax expense (benefit) from continuing operations is summarized as follows: Years Ended December 31, 2015 2014 2013 (Thousands) Current: Federal $ 85,696 $ 164,935 $ 100,796 State 1,103 17,136 46,758 Subtotal 86,799 182,071 147,554 Deferred: Federal (109,642 ) 38,357 51,767 State 127,518 (6,336 ) (23,940 ) Subtotal 17,876 32,021 27,827 Amortization of deferred investment tax credit — — (195 ) Total income taxes $ 104,675 $ 214,092 $ 175,186
Schedule of reconciliation of income tax expense to amount computed at the federal statutory rate	Income tax expense differed from amounts computed at the federal statutory rate of 35% on pre-tax income as follows: Years Ended December 31, 2015 2014 2013 (Thousands) Tax at statutory rate $ 149,296 $ 253,299 $ 182,406 State income taxes (7,566 ) (2,992 ) 26,012 Valuation allowance 91,144 10,012 (9,832 ) Noncontrolling partners’ share of EQGP and EQM earnings (82,850 ) (43,409 ) (16,535 ) Regulatory asset (35,438 ) — — Research and experimentation credit (7,243 ) (468 ) (375 ) Other (2,668 ) (2,350 ) (6,490 ) Income tax expense $ 104,675 $ 214,092 $ 175,186 Effective tax rate 24.5 % 29.6 % 33.6 %
Schedule of reconciliation of the beginning and ending amount of reserve for uncertain tax positions(excluding interest and penalties)	The following table reconciles the beginning and ending amount of reserve for uncertain tax positions (excluding interest and penalties): 2015 2014 2013 (Thousands) Balance at January 1 $ 56,957 $ 57,087 $ 17,858 Additions based on tax positions related to current year 152,983 1,195 49,289 Additions for tax positions of prior years 50,688 93 — Reductions for tax positions of prior years (1,327 ) (1,418 ) (790 ) Lapse of statute of limitations — — (9,270 ) Balance at December 31 $ 259,301 $ 56,957 $ 57,087
Summary of source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities	The following table summarizes the source and tax effects of temporary differences between financial reporting and tax bases of assets and liabilities: As of December 31, 2015 2014 (Thousands) Deferred income taxes: Total deferred income tax assets $ (827,161 ) $ (971,531 ) Total deferred income tax liabilities 2,799,331 2,700,467 Total net deferred income tax liabilities 1,972,170 1,728,936 Total deferred income tax liabilities (assets) Drilling and development costs expensed for income tax reporting 1,421,581 1,391,156 Tax depreciation in excess of book depreciation 1,224,377 1,154,082 Accumulated OCI 29,154 130,770 Post-retirement benefits 3,326 3,146 Incentive compensation and deferred compensation plans (75,143 ) (65,086 ) Net operating loss carryforwards (214,714 ) (212,718 ) Investment in EQGP and EQM (426,343 ) (336,394 ) Alternative minimum tax credit carryforward (267,045 ) (412,345 ) Unrealized hedge gains 107,854 21,314 Other 13,039 (9,976 ) Total excluding valuation allowances 1,816,086 1,663,949 Valuation allowance 156,084 64,987 Total (including amounts classified as current assets of $21,934 in 2014) $ 1,972,170 $ 1,728,936

Equity in Nonconsolidated Inv39

Equity in Nonconsolidated Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Schedule of equity in the nonconsolidated investments	The following table summarizes the Company's equity in the nonconsolidated investments: Interest Ownership as of As of December 31, Investees Location Type December 31, 2015 (a) 2015 2014 (Thousands) MVP Joint Venture USA Joint 54% $ 77,025 $ — (a) As of February 11, 2016, EQM owned a 45.5% ownership interest in the MVP Joint Venture. See Note 4.
Schedule of condensed financial statements for nonconsolidated investments	The following table summarizes the unaudited condensed financial statements for nonconsolidated investments accounted for under the equity method of accounting for the periods noted (including MVP Joint Venture for 2015 and Nora LLC for 2014 and 2013): Summarized Statements of Income Years Ended December 31, 2015 2014 2013 (Thousands) Revenues $ — $ 19,924 $ 45,040 Operating expenses — 13,257 29,892 Other income 2,566 102 82 Net income $ 2,566 $ 6,769 $ 15,230

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of long-term debt	December 31, 2015 December 31, 2014 Principal Value Carrying Value (a) Fair Value (b) Principal Value Carrying Value (a) Fair (Thousands) 7.76% notes, due 2015 through 2016 $ — $ — $ — $ 10,700 $ 10,700 $ 10,700 5.00% notes, due October 1, 2015 — — — 150,000 149,865 154,692 5.15% notes, due March 1, 2018 200,000 199,156 203,490 200,000 198,766 214,626 6.50% notes, due April 1, 2018 500,000 498,360 520,175 500,000 497,630 559,900 8.13% notes, due June 1, 2019 700,000 697,295 760,837 700,000 696,483 843,864 4.88% notes, due November 15, 2021 750,000 742,270 728,063 750,000 740,945 812,558 4.00% EQM notes, due August 1, 2024 500,000 493,401 414,125 500,000 492,633 495,685 7.75% debentures, due July 15, 2026 115,000 109,738 119,372 115,000 109,240 147,036 Medium-term notes: 7.3% to 7.6% Series B, due 2015 through 2023 10,000 9,991 10,241 20,000 19,985 22,279 7.6% Series C, due 2018 8,000 7,983 8,366 8,000 7,975 8,950 8.7% to 9.0% Series A, due 2020 through 2021 35,200 35,149 38,598 35,200 35,131 43,912 2,818,200 2,793,343 2,803,267 2,988,900 2,959,353 3,314,202 Less debt payable within one year — — — 166,011 165,874 171,081 Total long-term debt $ 2,818,200 $ 2,793,343 $ 2,803,267 $ 2,822,889 $ 2,793,479 $ 3,143,121 (a) Carrying value represents principal value less unamortized debt issuance costs and debt discounts. (b) Fair value is measured using Level 2 inputs.

Pension and Other Post-Retire41

Pension and Other Post-Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of funded status and amounts recognized for defined benefit pension and other post-retirement benefit plans	The following table sets forth the defined benefit pension and other post-retirement benefit plans’ funded status and amounts recognized for those plans in the Company’s Consolidated Balance Sheets. Refer to Note 2 for further information related to the Equitable Gas Transaction. For the Years Ended December 31, 2015 2014 2015 2014 Pension Benefits Other Benefits (Thousands) Change in benefit obligation: Benefit obligation at beginning of year $ 21,704 $ 21,828 $ 18,741 $ 18,253 Service cost 350 350 762 669 Interest cost 746 820 634 693 Amendments — — — 227 Actuarial loss (gain) 2,770 2,412 (361 ) 1,190 Benefits paid (1,981 ) (1,988 ) (2,141 ) (2,291 ) Expenses paid (367 ) (262 ) — — Settlements (177 ) (1,456 ) — — Benefit obligation at end of year $ 23,045 $ 21,704 $ 17,635 $ 18,741 Change in plan assets: Fair value of plan assets at beginning of year $ 18,323 $ 20,089 $ 823 $ 493 Actual (loss) gain on plan assets (32 ) 1,217 — — Contributions 1,175 723 287 330 Benefits paid (1,981 ) (1,988 ) — — Expenses paid (367 ) (262 ) — — Settlements (177 ) (1,456 ) — — Fair value of plan assets at end of year 16,941 18,323 1,110 823 Funded status at end of year $ (6,104 ) $ (3,381 ) $ (16,525 ) $ (17,918 )
Schedule of amounts recognized in statement of financial position	Amounts recognized in the statement of financial position consist of: Current liabilities $ (6,104 ) $ — $ (1,376 ) $ (924 ) Noncurrent liabilities — (3,381 ) (15,149 ) (16,994 ) Net amounts recognized $ (6,104 ) $ (3,381 ) $ (16,525 ) $ (17,918 ) Amounts recognized in accumulated OCI, net of tax, consist of: Net loss $ 9,674 $ 8,082 $ 7,610 $ 8,273 Net prior service — — 257 285 Net amount recognized $ 9,674 $ 8,082 $ 7,867 $ 8,558
Schedule of components of net periodic benefit cost	The Company’s costs related to its defined benefit pension and other post-retirement benefit plans were as follows: For the Years Ended December 31, 2015 2014 2013 2015 2014 2013 Pension Benefits Other Benefits (Thousands) Components of net periodic benefit cost: Service cost $ 350 $ 350 $ 500 $ 762 $ 669 $ 905 Interest cost 746 820 1,935 634 693 1,110 Expected return on plan assets (627 ) (1,377 ) (3,323 ) — — — Amortization of prior service cost — — — (306 ) (446 ) (845 ) Recognized net actuarial loss 746 709 2,306 793 879 1,760 Settlement loss and special termination benefits 122 879 381 — — — Subtotal 1,337 1,381 1,799 1,883 1,795 2,930 Net periodic benefit cost of discontinued operations — — 1,552 — — 1,356 Net periodic benefit cost $ 1,337 $ 1,381 $ 247 $ 1,883 $ 1,795 $ 1,574
Schedule of amount recognized in other comprehensive income	Currently, the Company recognizes expense for on-going post-retirement benefits other than pensions, a portion of which expense is subject to recovery in the approved rates of its rate-regulated EQT Midstream business. For the Years Ended December 31, 2015 2014 2013 2015 2014 2013 Pension Benefits Other Benefits (Thousands) Other changes in plan assets and benefit obligations recognized in OCI, net of tax: Net loss (gain) $ 1,592 $ 558 $ 712 $ (663 ) $ 39 $ 2,147 Net prior service (credit) cost — — — (28 ) 179 416 Total recognized in OCI, net of tax $ 1,592 $ 558 $ 712 $ (691 ) $ 218 $ 2,563 Total recognized in net periodic benefit cost and OCI, net of tax $ 2,929 $ 1,939 $ 959 $ 1,192 $ 2,013 $ 4,137
Schedule of weighted average assumption used to determine the benefit obligations	The following weighted average assumptions were used to determine the benefit obligations for the Company’s defined benefit pension and other post-retirement benefit plans: December 31, 2015 2014 2015 2014 Pension Benefits Other Benefits Discount rate 2.20% 3.60% 3.95% 3.60% Rate of compensation increase N/A N/A N/A N/A
Schedule of weighted average assumption used to determine the net periodic benefit cost	The following weighted average assumptions were used to determine the net periodic benefit cost for the Company’s defined benefit pension and other post-retirement benefit plans: For the Years Ended December 31, 2015 2014 2015 2014 Pension Benefits Other Benefits Discount rate 3.60 % 4.00 % 3.60 % 4.00 % Expected return on plan assets 3.75 % 7.75 % N/A N/A Rate of compensation increase N/A N/A N/A N/A
Schedule of impact of one-percentage-point change in assumed health care cost trend rates	A one-percentage-point change in assumed health care cost trend rates would have had the following effects: One-Percentage-Point Increase One-Percentage-Point Decrease 2015 2014 2013 2015 2014 2013 (Thousands) Increase (decrease) to total of service and interest cost components $ 10 $ 13 $ 25 $ (11 ) $ (14 ) $ (26 ) Increase (decrease) to post-retirement benefit obligation $ 268 $ 228 $ 220 $ (278 ) $ (229 ) $ (223 )
Schedule of the entity's asset allocation	The Company’s asset allocation for the Retirement Plan at December 31, 2015 and 2014 and target allocation for 2016 by asset category are as follows: Target Percentage of Plan Assets at December 31, Asset Category Allocation 2016 2015 2014 Domestic broadly diversified equity securities 0% - 10% — % 26 % Fixed income securities 80% - 100% 99 % 63 % International broadly diversified equity securities 0% — % 8 % Cash and equivalent investments 0% - 20% 1 % 3 % 100 % 100 %

Changes in Accumulated Other 42

Changes in Accumulated Other Comprehensive Income by Component (Tables)	12 Months Ended
	Dec. 31, 2015
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of the changes in accumulated OCI by component	The following tables explain the changes in accumulated OCI by component for the years ended December 31, 2015 , 2014 , and 2013 : Year Ended December 31, 2015 Natural gas cash flow hedges, net of tax Interest rate cash flow hedges, net of tax Pension and other post- retirement benefits liability adjustment, net of tax Accumulated OCI (loss), net of tax (Thousands) Accumulated OCI (loss), net of tax, as of January 1, 2015 $ 217,121 $ (987 ) $ (16,640 ) $ 199,494 (Gains) losses reclassified from accumulated OCI, net of tax (152,359 ) (a) 144 (a) (901 ) (b) (153,116 ) Accumulated OCI (loss), net of tax, as of December 31, 2015 $ 64,762 $ (843 ) $ (17,541 ) $ 46,378 Year Ended December 31, 2014 Natural gas cash flow hedges, net of tax Interest rate cash flow hedges, net of tax Pension and other post- retirement benefits liability adjustment, net of tax Accumulated OCI (loss), net of tax (Thousands) Accumulated OCI (loss), net of tax, as of January 1, 2014 $ 61,699 $ (1,132 ) $ (15,864 ) $ 44,703 Gains recognized in accumulated OCI, net of tax 156,207 (a) — — 156,207 Gain reclassified from accumulated OCI, net of tax, into gain on sale/exchange of assets (16,735 ) (a) — — (16,735 ) Losses (gains) reclassified from accumulated OCI, net of tax 15,950 (a) 145 (a) (776 ) (b) 15,319 Change in accumulated OCI, net of tax 155,422 145 (776 ) 154,791 Accumulated OCI (loss), net of tax, as of December 31, 2014 $ 217,121 $ (987 ) $ (16,640 ) $ 199,494 Year Ended December 31, 2013 Natural gas cash Interest rate Pension and Accumulated (Thousands) Accumulated OCI (loss), net of tax, as of January 1, 2013 $ 138,188 $ (1,276 ) $ (37,365 ) $ 99,547 Gains recognized in accumulated OCI, net of tax 10,669 (a) — 2,081 12,750 (Gains) losses reclassified from accumulated OCI, net of tax (87,158 ) (a) 144 (a) 19,420 (b) (67,594 ) Change in accumulated OCI, net of tax (76,489 ) 144 21,501 (54,844 ) Accumulated OCI (loss), net of tax, as of December 31, 2013 $ 61,699 $ (1,132 ) $ (15,864 ) $ 44,703 (a) See Note 6 for additional information. (b) This accumulated OCI reclassification is attributable to the net actuarial loss and net prior service cost related to the Company’s defined benefit pension plans and other post-retirement benefit plans. See Note 14 for additional information.

Common Stock and Earnings Per43

Common Stock and Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of shares of authorized and unissued common stock	At December 31, 2015 , shares of EQT’s authorized and unissued common stock were reserved as follows: (Thousands) Possible future acquisitions 20,457 Stock compensation plans 13,394 Total 33,851
Schedule of earnings per share, basic and diluted	The computation of basic and diluted earnings per share of common stock attributable to EQT Corporation is shown in the table below: Years Ended December 31, 2015 2014 2013 (Thousands except per share amounts) Basic earnings per common share: Net income attributable to EQT Corporation $ 85,171 $ 386,965 $ 390,572 Average common shares outstanding 152,398 151,553 150,574 Basic earnings per common share $ 0.56 $ 2.55 $ 2.59 Diluted earnings per common share: Net income attributable to EQT Corporation $ 85,171 $ 386,965 $ 390,572 Average common shares outstanding 152,398 151,553 150,574 Potentially dilutive securities: Stock options and awards (a) 541 960 1,213 Total 152,939 152,513 151,787 Diluted earnings per common share $ 0.56 $ 2.54 $ 2.57 (a) Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 291,700 shares for the year ended December 31, 2015 . There were no options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive for the years ended December 31, 2014 and 2013.

Share-Based Compensation Plans

Share-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of share-based compensation expense	Share-based compensation expense recorded by the Company was as follows: Years Ended December 31, 2015 2014 2013 (Thousands) 2012 Executive Performance Incentive Program $ — $ 7,743 $ 6,739 2013 Executive Performance Incentive Program 6,834 8,208 6,602 2014 Executive Performance Incentive Program 12,865 9,104 — 2015 Executive Performance Incentive Program 12,051 — — 2011 Volume and Efficiency Program — — 13,834 2012 EQT Value Driver Award Program — — 2,327 2013 EQT Value Driver Award Program — 4,403 13,050 2014 EQT Value Driver Award Program 1,116 11,510 — 2014 EQM Value Driver Award Program 622 2,378 — 2015 EQT Value Driver Award Program 14,574 — — Restricted stock awards 7,031 4,688 3,033 Non-qualified stock options 1,938 3,002 3,805 Other programs, including non-employee director awards (2,339 ) (409 ) 9,154 Total share-based compensation expense $ 54,692 $ 50,627 $ 58,544
Summary of restricted stock awards activity	A summary of restricted stock activity as of December 31, 2015 , and changes during the year then ended, is presented below: Restricted Stock Non- Vested Shares Weighted Average Fair Value Aggregate Fair Value Outstanding at January 1, 2015 229,990 $ 74.90 $ 17,225,411 Granted 158,360 $ 75.46 11,949,751 Vested (71,100 ) $ 53.56 (3,808,262 ) Forfeited (17,130 ) $ 80.92 (1,386,273 ) Outstanding at December 31, 2015 300,120 $ 79.90 $ 23,980,627
Non-qualified stock options, assumptions used to value share-based compensation	The expected term of options granted represents the period of time that options granted are expected to be outstanding based on historical option exercise experience. Years Ended December 31, 2015 2014 2013 Risk-free interest rate 1.61% 1.72% 0.76% Dividend yield 0.12% 0.15% 0.22% Volatility factor 26.80% 24.80% 31.69% Expected term 5 years 5 years 5 years
Summary of option activity	A summary of option activity as of December 31, 2015 , and changes during the year then ended, is presented below: Non-qualified Stock Options Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Term Aggregate Intrinsic Value Outstanding at January 1, 2015 1,338,468 $54.08 Granted 158,200 $75.70 Exercised (405,526 ) $46.00 Forfeited — — Expired (10,900 ) $48.91 Outstanding at December 31, 2015 1,080,242 $60.33 6.53 years $2,261,513 Exercisable at December 31, 2015 788,542 $52.25 5.78 years $2,261,513
2013 Executive Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of incentive PSU program	The peer companies for the 2013 Incentive PSU Program are as follows: Cabot Oil & Gas Corp. MDU Resources Group, Inc. Sempra Energy Chesapeake Energy Corp. National Fuel Gas Company SM Energy Company Cimarex Energy Co. Newfield Exploration Company Southwestern Energy Company Concho Resources, Inc ONEOK, Inc. Spectra Energy Corp CONSOL Energy Inc. Pioneer Natural Resources Company Ultra Petroleum Corp. Energen Corp. Plains Exploration & Production Co. Whiting Petroleum Corp. EOG Resources, Inc. Questar Corp. The Williams Companies, Inc. EXCO Resources, Inc. Quicksilver Resources Inc. MarkWest Energy Partners, L.P. Range Resources Corp.
2014 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of incentive PSU program	The peer companies for the 2014 Incentive PSU Program are as follows: Cabot Oil & Gas Corp. MarkWest Energy Partners, L.P. Range Resources Corp. Chesapeake Energy Corp. National Fuel Gas Company SM Energy Company Cimarex Energy Co. Newfield Exploration Company Southwestern Energy Company Concho Resources, Inc. Noble Energy, Inc. Spectra Energy Corp CONSOL Energy Inc. ONEOK, Inc. Ultra Petroleum Corp. Continental Resources, Inc. Pioneer Natural Resources Company Whiting Petroleum Corp. Energen Corp. QEP Resources, Inc. The Williams Companies, Inc. EOG Resources, Inc. Questar Corp. EXCO Resources, Inc. Quicksilver Resources, Inc.
2015 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of incentive PSU program	The peer companies for the 2015 Incentive PSU Program are as follows: Cabot Oil & Gas Corp. MarkWest Energy Partners, L.P. Range Resources Corp. Chesapeake Energy Corp. National Fuel Gas Company SM Energy Company Cimarex Energy Co. Newfield Exploration Company Southwestern Energy Company Concho Resources, Inc. Noble Energy, Inc. Spectra Energy Corp CONSOL Energy Inc. ONEOK, Inc. Ultra Petroleum Corp. Continental Resources, Inc. Pioneer Natural Resources Company Whiting Petroleum Corp. Energen Corp. QEP Resources, Inc. The Williams Companies, Inc. EOG Resources, Inc. Questar Corp. EXCO Resources, Inc. Quicksilver Resources, Inc.

Interim Financial Information45

Interim Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Interim Financial Information (Unaudited)	The following quarterly summary of operating results reflects variations due primarily to the volatility of natural gas commodity prices, including recognition of impairment expense on long-lived assets, and the seasonal nature of the Company’s storage business. Three Months Ended March 31 June 30 September 30 December 31 (Thousands, except per share amounts) 2015 (a) Total operating revenues (b) $ 714,815 $ 439,589 $ 583,978 $ 601,380 Operating income 314,759 33,034 170,055 45,291 Net income (loss) attributable to EQT Corporation 173,427 5,536 40,787 (134,579 ) Earnings per share of common stock attributable to EQT Corporation: Basic: Net income (loss) $ 1.14 $ 0.04 $ 0.27 $ (0.88 ) Diluted: Net income (loss) $ 1.14 $ 0.04 $ 0.27 $ (0.88 ) 2014 (a) Total operating revenues $ 661,625 $ 526,168 $ 578,723 $ 703,194 Operating income 356,791 224,771 231,503 40,330 Amounts attributable to EQT Corporation: Income (loss) from continuing operations 192,297 109,045 98,555 (14,303 ) (Loss) income from discontinued operations (104 ) 1,876 — (401 ) Net income (loss) attributable to EQT Corporation $ 192,193 $ 110,921 $ 98,555 $ (14,704 ) Earnings per share of common stock attributable to EQT Corporation: Basic: Income (loss) from continuing operations $ 1.27 $ 0.72 $ 0.65 $ (0.10 ) Income from discontinued operations — 0.01 — — Net income (loss) $ 1.27 $ 0.73 $ 0.65 $ (0.10 ) Diluted: Income (loss) from continuing operations $ 1.26 $ 0.72 $ 0.65 $ (0.10 ) Income from discontinued operations — 0.01 — — Net income (loss) $ 1.26 $ 0.73 $ 0.65 $ (0.10 ) (a) The sum of the quarterly data in some cases may not equal the yearly total due to rounding. (b) Differences between the amounts in the above table and those previously reported in the Company's 2015 Form 10-Qs are attributable to a current year reclassification of NGL processing costs which were previously reported as a reduction of operating revenues. The reclassification was immaterial to the amounts previously reported in the Company's 2015 Form 10-Qs.

Natural Gas Producing Activit46

Natural Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of cost incurred relating to property acquisition, exploration and development	The following tables present the total aggregate capitalized costs and the costs incurred relating to natural gas, NGL and oil production activities (a): For the Years Ended December 31, 2015 2014 2013 (Thousands) At December 31: Capitalized Costs: Proved properties $ 10,918,499 $ 9,258,298 $ 7,702,724 Unproved properties 898,270 824,527 450,227 Total capitalized costs 11,816,769 10,082,825 8,152,951 Accumulated depreciation and depletion 3,425,618 2,693,535 2,134,953 Net capitalized costs $ 8,391,151 $ 7,389,290 $ 6,017,998 For the Years Ended December 31, 2015 2014 2013 (Thousands) Costs incurred: Property acquisition: Proved properties (b) $ 23,890 $ 231,322 $ 90,390 Unproved properties (c) 158,405 493,067 95,861 Exploration (d) 53,463 16,023 4,285 Development 1,633,498 1,697,501 1,230,301 (a) Amounts exclude capital expenditures for facilities and information technology. (b) Amounts include $198.2 million and $1.1 million for the purchase of Permian wells and leases, respectively, acquired in the Range transaction in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake transaction in 2013. (c) Amounts include $317.2 million for the purchase of Permian leases acquired in the Range transaction in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake transaction in 2013. (d) Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.
Results of operations related to natural gas, NGL and oil producing Activities	The following table presents the results of operations related to natural gas, NGL and oil production: For the Years Ended December 31, 2015 2014 2013 (Thousands) Revenues: Affiliated $ 1,412 $ 4,761 $ 5,912 Nonaffiliated 1,154,422 1,724,771 1,305,026 Production costs 398,044 334,050 250,372 Exploration costs 61,970 21,665 18,483 Depreciation, depletion and accretion 723,448 592,855 578,641 Impairment of long-lived assets 118,268 267,339 — Income tax (benefit) expense (58,603 ) 202,881 183,060 Results of operations from producing activities (excluding corporate overhead) $ (87,293 ) $ 310,742 $ 280,382
Schedule of the entity's proved reserves	Years Ended December 31, 2015 2014 2013 (Millions of Cubic Feet) Total - Natural Gas, Oil, and NGLs (a) Proved developed and undeveloped reserves: Beginning of year 10,738,948 8,348,269 6,004,952 Revision of previous estimates (2,194,675 ) (301,351 ) 191,509 Purchase of hydrocarbons in place — 102,713 472,798 Sale of hydrocarbons in place (61 ) (198,657 ) (455 ) Extensions, discoveries and other additions 2,051,071 3,276,054 2,046,578 Production (618,686 ) (488,080 ) (367,113 ) End of year 9,976,597 10,738,948 8,348,269 Proved developed reserves: Beginning of year 4,826,387 3,985,687 2,798,381 End of year 6,279,557 4,826,387 3,985,687 Proved undeveloped reserves: Beginning of year 5,912,561 4,362,582 3,206,571 End of year 3,697,040 5,912,561 4,362,582 (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, 2015 2014 2013 (Millions of Cubic Feet) Natural Gas Proved developed and undeveloped reserves: Beginning of year 9,775,954 7,561,561 5,985,758 Revision of previous estimates (2,059,531 ) (228,085 ) (375,887 ) Purchase of natural gas in place — 44,867 472,798 Sale of natural gas in place (61 ) (198,531 ) (455 ) Extensions, discoveries and other additions 1,955,935 3,040,938 1,844,840 Production (561,986 ) (444,796 ) (365,493 ) End of year 9,110,311 9,775,954 7,561,561 Proved developed reserves: Beginning of year 4,257,377 3,567,313 2,779,187 End of year 5,652,989 4,257,377 3,567,313 Proved undeveloped reserves: Beginning of year 5,518,577 3,994,248 3,206,571 End of year 3,457,322 5,518,577 3,994,248 Years Ended December 31, 2015 2014 2013 (Thousands of Bbls) Oil (a) Proved developed and undeveloped reserves: Beginning of year 5,005 3,956 3,199 Revision of previous estimates 1,219 (905 ) 270 Purchase of oil in place — 2,165 — Sale of oil in place — (3 ) — Extensions, discoveries and other additions 419 241 757 Production (743 ) (449 ) (270 ) End of year 5,900 5,005 3,956 Proved developed reserves: Beginning of year 5,005 3,892 3,199 End of year 5,900 5,005 3,892 Proved undeveloped reserves: Beginning of year — 64 — End of year — — 64 (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf). Years Ended December 31, 2015 2014 2013 (Thousands of Bbls) NGLs (a) Proved developed and undeveloped reserves: Beginning of year 155,494 127,162 — Revision of previous estimates (23,743 ) (11,306 ) 94,296 Purchase of NGLs in place — 7,476 — Sale of NGLs in place — (18 ) — Extensions, discoveries and other additions 15,437 38,945 32,866 Production (8,707 ) (6,765 ) — End of year 138,481 155,494 127,162 Proved developed reserves: Beginning of year 89,830 65,837 — End of year 98,528 89,830 65,837 Proved undeveloped reserves: Beginning of year 65,664 61,325 — End of year 39,953 65,664 61,325 (a) One thousand Bbl equals approximately 6 million cubic feet (MMcf).
Schedule of estimated future net cash flows from natural gas and oil reserves	Estimated future net cash flows from natural gas and oil reserves are as follows at December 31: 2015 2014 2013 (Thousands) Future cash inflows (a) $ 10,071,465 $ 30,428,815 $ 25,912,542 Future production costs (3,415,715 ) (4,868,079 ) (4,180,136 ) Future development costs (2,377,650 ) (5,052,195 ) (4,199,722 ) Future income tax expenses (1,333,989 ) (7,718,407 ) (6,533,817 ) Future net cash flow 2,944,111 12,790,134 10,998,867 10% annual discount for estimated timing of cash flows (1,966,557 ) (7,980,106 ) (7,047,588 ) Standardized measure of discounted future net cash flows $ 977,554 $ 4,810,028 $ 3,951,279 (a) 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 West Texas Intermediate (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, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2015 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $17.60 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $21.69 per Bbl of NGLs from certain Kentucky reserves, $16.84 per Bbl for Utica reserves, and $17.51 per Bbl for Permian reserves. For 2014, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2014 of $94.99 per Bbl of oil (first day of each month closing price for WTI less regional adjustments), $4.278 per Dth for Columbia Gas Transmission Corp., $3.191 per Dth for Dominion Transmission, Inc., $4.350 per Dth for the East Tennessee Natural Gas Pipeline, $3.258 per Dth for Texas Eastern Transmission Corp., $2.286 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company, $4.170 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company, $4.152 per Dth for Waha, and $4.243 per Dth for Houston Ship Channel. For 2014, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2014 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $49.22 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $49.47 per Bbl of NGLs from certain Kentucky reserves, $47.11 per Bbl for Utica reserves, and $31.92 per Bbl for Permian reserves. 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 regional adjustments), $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 2013, NGL pricing using arithmetic averages of the closing prices on the first day of each month during 2013 for NGL components and adjusted using the regional component makeup of produced NGLs resulted in prices of $51.91 per Bbl of NGLs from West Virginia Marcellus reserves in Doddridge, Ritchie, and Wetzel counties, $49.38 per Bbl of NGLs from certain Kentucky reserves, and $48.14 per Bbl for Utica reserves.
Schedule of changes in the standardized measure of discounted net cash flows from natural gas and oil reserves	Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31: 2015 2014 2013 (Thousands) Sales and transfers of natural gas and oil produced – net $ (757,789 ) $ (1,479,242 ) $ (1,060,566 ) Net changes in prices, production and development costs (5,566,232 ) (1,525,944 ) (292,533 ) Extensions, discoveries and improved recovery, less related costs 264,735 2,300,923 1,509,002 Development costs incurred 971,186 1,023,075 1,319,135 Purchase of minerals in place – net — 72,139 348,608 Sale of minerals in place – net (43 ) (146,476 ) (252 ) Revisions of previous quantity estimates (1,541,419 ) (222,195 ) 106,170 Accretion of discount 600,099 578,676 343,502 Net change in income taxes 2,424,200 (529,337 ) (1,031,105 ) Timing and other (227,211 ) 787,130 554,159 Net (decrease) increase (3,832,474 ) 858,749 1,796,120 Beginning of year 4,810,028 3,951,279 2,155,159 End of year $ 977,554 $ 4,810,028 $ 3,951,279

Summary of Significant Accoun47

Summary of Significant Accounting Policies - Narrative (Details)	May. 15, 2015shares	Mar. 18, 2015shares	Dec. 31, 2015USD ($)$ / Mcfedry_holesegmentshares	Dec. 31, 2014USD ($)$ / Mcfe	Dec. 31, 2013USD ($)$ / Mcfe
Accounting Policies [Abstract]
Number of segments | segment			2
Maturity period			3 months
Losses for lower of cost or market adjustments			$ 0	$ 3,200,000	$ 400,000
Internal costs			114,400,000	108,500,000	93,500,000
Interest costs capitalized			$ 35,800,000	$ 35,000,000	$ 22,900,000
Overall average rate of depletion | $ / Mcfe			1.18	1.22	1.50
Forward price curve period			5 years
Market participant discount rate			12.00%
Property, Plant and Equipment [Line Items]
Unproved property impairments			$ 19,700,000	$ 86,600,000
Unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling			37,400,000	14,600,000	$ 14,200,000
Unproved properties			898,270,000	824,527,000	450,227,000
Capitalized exploratory well costs			$ 0	9,000,000	0
Number of exploratory dry holes | dry_hole			1
Impairment of long lived assets			$ 122,469,000	267,339,000	0
Regulatory assets associated with deferred taxes			73,100,000	15,200,000
AFUDC interest costs capitalized			1,600,000	1,000,000	500,000
AFUDC equity amounts capitalized			$ 6,300,000	3,200,000	1,200,000
Largest amount of benefit threshold, percentage (no greater than)			50.00%
Settlement of asset retirement obligation liabilities			$ 5,027,000	14,025,000
Asset retirement obligation liabilities incurred			$ 2,251,000	16,953,000
New Accounting Pronouncement, Early Adoption, Effect | Other Noncurrent Assets
Property, Plant and Equipment [Line Items]
Decrease in other assets, current portion of long-term debt, long-term debt, and total liabilities				(29,500,000)
New Accounting Pronouncement, Early Adoption, Effect | Long-term Debt, Current Maturities
Property, Plant and Equipment [Line Items]
Decrease in other assets, current portion of long-term debt, long-term debt, and total liabilities				100,000
New Accounting Pronouncement, Early Adoption, Effect | Long-term Debt
Property, Plant and Equipment [Line Items]
Decrease in other assets, current portion of long-term debt, long-term debt, and total liabilities				29,400,000
New Accounting Pronouncement, Early Adoption, Effect | Total Liability
Property, Plant and Equipment [Line Items]
Decrease in other assets, current portion of long-term debt, long-term debt, and total liabilities				29,500,000
Range Resources Corporation
Property, Plant and Equipment [Line Items]
Settlement of asset retirement obligation liabilities				7,700,000
Asset retirement obligation liabilities incurred				14,200,000
Limited Partner Common
Property, Plant and Equipment [Line Items]
Initial public offering (IPO) | shares		1,237,500
Limited partner interest (as a percent)	90.10%
Number of common units retained (in shares) | shares	239,715,000
EQGP | Limited Partner Common
Property, Plant and Equipment [Line Items]
Initial public offering (IPO) | shares	26,450,000
Limited partner interest (as a percent)	9.90%
EQGP | Limited Partner Common | Affiliated Entity
Property, Plant and Equipment [Line Items]
Limited partner interest (as a percent)			27.60%
Common units owned (in shares) | shares			21,811,643
EQGP | General Partner
Property, Plant and Equipment [Line Items]
General partner interest (as a percent)			1.80%
EQGP | General Partner | Affiliated Entity
Property, Plant and Equipment [Line Items]
Number of general partner units (in shares) | shares			1,443,015
EQT Midstream
Property, Plant and Equipment [Line Items]
Impairment of long lived assets			$ 4,200,000	0	$ 0
Building | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			35 years
Vehicles | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			5 years
Minimum
Property, Plant and Equipment [Line Items]
Ownership percentage			20.00%
Minimum | Gathering and Transmission Systems | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			25 years
Minimum | Office Equipment | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			3 years
Minimum | Computer Equipment | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			3 years
Maximum
Property, Plant and Equipment [Line Items]
Ownership percentage			50.00%
Maximum | Gathering and Transmission Systems | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			60 years
Maximum | Office Equipment | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			7 years
Maximum | Computer Equipment | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life			7 years
Permian Basin of Texas
Property, Plant and Equipment [Line Items]
Pretax impairment charges on proved oil and gas properties			$ 94,300,000	105,200,000
Fair value			44,800,000	109,200,000
Carrying value of properties			345,000,000
Carrying value of undeveloped properties			300,000,000
Utica
Property, Plant and Equipment [Line Items]
Pretax impairment charges on proved oil and gas properties			4,300,000	75,500,000
Fair value			5,700,000	7,400,000
Unproved property impairments				86,600,000
Marcellus and Deep Utica
Property, Plant and Equipment [Line Items]
Unproved property impairments			19,700,000
Impairment of Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Pretax impairment charges on proved oil and gas properties			$ 98,600,000	$ 180,700,000

Summary of Significant Accoun48

Summary of Significant Accounting Policies - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Oil and gas producing properties, successful efforts method	$ 11,816,769	$ 10,082,825	$ 8,152,951
Accumulated depreciation and depletion	(3,425,618)	(2,693,535)	(2,134,953)
Net capitalized costs	8,391,151	7,389,290	$ 6,017,998
Midstream plant	15,635,549	13,427,429
Accumulated depreciation and amortization	(4,163,528)	(3,350,615)
Net property, plant and equipment	11,472,021	10,076,814
EQT Midstream
Property, Plant and Equipment [Line Items]
Midstream plant	3,703,994	3,234,370
Accumulated depreciation and amortization	(685,398)	(606,998)
Net property, plant and equipment	3,018,596	2,627,372
Other Properties
Property, Plant and Equipment [Line Items]
Net property, plant and equipment	$ 62,274	$ 60,152

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Schedule of Regulated Net Revenues and Operating Expenses (Details) - EQT Midstream - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Net revenues	$ 309,984	$ 267,997	$ 184,767
Operating expenses	$ 109,954	$ 89,617	$ 71,517

Summary of Significant Accoun50

Summary of Significant Accounting Policies - Schedule of Regulated Net Property, Plant and Equipment (Details) - EQT Midstream - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant & equipment	$ 1,356,206	$ 1,160,696
Accumulated depreciation and amortization	(193,349)	(188,884)
Net property, plant & equipment	$ 1,162,857	$ 971,812

Summary of Significant Accoun51

Summary of Significant Accounting Policies - Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other Current Liabilities:
Incentive compensation	$ 67,049	$ 70,826
Taxes other than income	44,925	52,035
Accrued interest payable	36,330	37,349
All other accrued liabilities	33,531	40,239
Total other current liabilities	$ 181,835	$ 200,449

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset retirement obligations
Asset retirement obligation as of beginning of period	$ 140,086	$ 116,045
Accretion expense	10,646	9,420
Liabilities incurred	2,251	16,953
Liabilities settled	(5,027)	(14,025)
Change in estimates	20,186	11,693
Asset retirement obligation as of end of period	$ 168,142	$ 140,086

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Schedule of Components of Accumulated other comprehensive income (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income	$ 46,378	$ 199,494	$ 44,703	$ 99,547
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income	(17,541)	(16,640)	(15,864)	(37,365)
Commodity Contract | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income	64,762	217,121	61,699	138,188
Interest Rate Contract | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income	$ (843)	$ (987)	$ (1,132)	$ (1,276)

Discontinued Operations - Narra

Discontinued Operations - Narrative (Details) - Equitable Gas and Homeworks - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Discontinued operations
Additional cash proceeds	$ 7.4
Total cash proceeds	748
Fair value of select midstream assets	140.9
Fair value of other contractual assets	32.5
Gain on sale of business		$ 43.8
Transaction costs incurred		8.1
Write off of income tax related regulatory assets		51.6
Income from Discontinued Operations, Net of Tax
Discontinued operations
Additional gain	$ 2.9
Net of tax expense		$ 122.5

Discontinued Operations - Summa

Discontinued Operations - Summary of the Components of Discontinued Operations Activity (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]
Operating revenues					$ 0	$ 0	$ 332,947
Income from discontinued operations before income taxes					0	2,377	251,378
Income taxes					0	1,006	159,535
Income from discontinued operations, net of tax	$ (401)	$ 0	$ 1,876	$ (104)	$ 0	$ 1,371	$ 91,843

EQT GP Holdings, LP (Details)

EQT GP Holdings, LP (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 21, 2016	Nov. 16, 2015	May. 15, 2015	Mar. 18, 2015	Mar. 17, 2015	Apr. 30, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Net proceeds								$ 1,182,002	$ 902,467	$ 529,442
Increase to deferred tax liability		$ 31,300			$ 73,500		$ 7,400
Net income attributable to noncontrolling interests								$ 236,715	$ 124,025	$ 47,243
Limited Partner Common
Class of Stock [Line Items]
Limited partner interest (as a percent)			90.10%
Underwritten IPO (in shares)				1,237,500
Number of common units retained (in shares)			239,715,000
EQGP
Class of Stock [Line Items]
Percentage of outstanding limited liability interests						100.00%
Percentage of all incremental cash distributed (up to)							48.00%	48.00%
Net proceeds			$ 674,000
Increase to deferred tax liability			192,500
EQGP | Subsequent Event
Class of Stock [Line Items]
Cash distribution declared (in dollars per share)	$ 0.122
Cash distribution declared	$ 32,500
EQGP | Common Stock
Class of Stock [Line Items]
Increase (decrease) in ownership of EQT GP Holdings, LP			320,400
EQGP | Noncontrolling Interest
Class of Stock [Line Items]
Increase (decrease) in ownership of EQT GP Holdings, LP			$ (512,900)
EQGP | Limited Partner Common
Class of Stock [Line Items]
Limited partner interest (as a percent)			9.90%
Underwritten IPO (in shares)			26,450,000
Underwriter's discount			$ 37,500
Structuring fees			$ 2,700
EQGP | Limited Partner Common | Affiliated Entity
Class of Stock [Line Items]
Number of common units (in shares)							21,811,643	21,811,643
Limited partner interest (as a percent)								27.60%
EQGP | General Partner
Class of Stock [Line Items]
General partner interest (as a percent)								1.80%
EQGP | General Partner | Affiliated Entity
Class of Stock [Line Items]
Number of general partner units (in shares)							1,443,015	1,443,015
EQGP | General Partner Common
Class of Stock [Line Items]
Incentive distribution rights distributed in respect of each common unit and general partner unit (in dollars per share)								$ 0.525

EQT Midstream Partners, LP (Det

EQT Midstream Partners, LP (Details)

Feb. 12, 2016USD ($)

Jan. 21, 2016USD ($)Bcf / d$ / shares

Nov. 16, 2015USD ($)shares

May. 15, 2015USD ($)shares

Apr. 15, 2015USD ($)

Mar. 30, 2015USD ($)

Mar. 18, 2015shares

Mar. 17, 2015USD ($)shares

Feb. 17, 2015

May. 07, 2014USD ($)shares

Jul. 31, 2012shares

Mar. 31, 2015

Dec. 31, 2015USD ($)mi$ / sharesshares

Dec. 31, 2015USD ($)Bcf / dmi

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Feb. 11, 2016

Aug. 31, 2014USD ($)

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Net proceeds

$ 1,182,002,000

$ 902,467,000

$ 529,442,000

Principal value

$ 2,818,200,000

$ 2,818,200,000

$ 2,988,900,000

Increase to deferred tax liability

$ 31,300,000

$ 73,500,000

$ 7,400,000

Mountain Valley Pipeline

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Natural gas interstate pipeline (in miles) | mi

300

300

Common Stock

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Increase (decrease) in ownership of EQT Midstream Partners LP

52,100,000

122,300,000

$ 12,400,000

Noncontrolling Interest

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Increase (decrease) in ownership of EQT Midstream Partners LP

$ (83,500,000)

$ (195,800,000)

(19,800,000)

Limited Partner Common

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Subordinated units issued (in shares) | shares

1,237,500

Percentage of membership interest

90.10%

EQT Energy Supply, LLC

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Total consideration

$ 124,300,000

MVP Holdco

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Percentage of membership interest

100.00%

MVP Joint Venture

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Total consideration

$ 54,200,000

Percentage of capital contributions

100.00%

Firms capacity commitments per day (in Bcf per day) | Bcf / d

2

Duration of firm capacity commitments

20 years

EQM

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Subordinated units issued (in shares) | shares

5,650,000

8,250,000

12,362,500

17,339,718

Subordinated units, convertible, conversion, ratio

1

Net proceeds

$ 399,900,000

$ 696,600,000

$ 902,500,000

85,500,000

Discount and offering expenses

34,000,000

Underwriters discount and offering expenses

24,500,000

700,000

Percentage of membership interest

100.00%

Aggregate offering price (up to)

$ 750,000,000

$ 750,000,000

Common units issued (in shares) | shares

1,162,475

Average price per unit (in shares) | $ / shares

$ 74.92

Commissions

$ 900,000

EQM | Variable Interest Entity, Not Primary Beneficiary | MVP Joint Venture

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Ownership percentage

54.00%

54.00%

EQM | Subsequent Event

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Cash distribution declared (in dollars per share) | $ / shares

$ 0.71

EQM | Subsequent Event | Variable Interest Entity, Not Primary Beneficiary | MVP Joint Venture

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Ownership percentage

45.50%

EQM | Limited Partner Common

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Underwriters discount and offering expenses

$ 5,700,000

EQM | NWV Gathering

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Total consideration

925,700,000

Total consideration in cash

$ 873,200,000

EQM | NWV Gathering | Common Partner Units | Partnership Interest

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Total consideration, common units and general partner units (in shares) | shares

511,973

EQM | NWV Gathering | General Partner Units | Partnership Interest

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Total consideration, common units and general partner units (in shares) | shares

178,816

EQM | Senior Notes

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Interest rate

4.00%

Principal value

$ 500,000,000

EQT | MVP Joint Venture

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Firms capacity commitments per day (in Bcf per day) | Bcf / d

1.29

ConEd | MVP Joint Venture | Subsequent Event | Variable Interest Entity, Not Primary Beneficiary

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Total consideration in cash

$ 12,500,000

Firms capacity commitments per day (in Bcf per day) | Bcf / d

0.25

Duration of firm capacity commitments

20 years

Ownership interest (as a percent)

12.50%

Decrease in ownership interest (as a percent)

8.50%

EQT Gathering, LLC

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Payments for gathering system

$ 1,180,000,000

EQGP

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Net proceeds

$ 674,000,000

Increase to deferred tax liability

$ 192,500,000

EQGP | Scenario, Forecast

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Cash distribution declared

$ 33,000,000

EQGP | Subsequent Event

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Cash distribution declared in respect of limited partner and general partner interest

$ 32,500,000

EQGP | Limited Partner Common

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Subordinated units issued (in shares) | shares

26,450,000

Underwriters discount and offering expenses

$ 2,700,000

Percentage of membership interest

9.90%

EQGP | Limited Partner | Scenario, Forecast

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Cash distribution declared in respect of limited partner and general partner interest

15,500,000

EQGP | General Partner | Scenario, Forecast

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Cash distribution declared in respect of limited partner and general partner interest

1,300,000

Incentive distribution rights declared

$ 16,200,000

Financial Information by Busi58

Financial Information by Business Segment - Schedule of Revenues from External Customers, Operating Income and Reconciliation of Operating Income to Income from Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues from external customers, including affiliates:
Total	$ 601,380	$ 583,978	$ 439,589	$ 714,815	$ 703,194	$ 578,723	$ 526,168	$ 661,625	$ 2,339,762	$ 2,469,710	$ 1,862,011
Operating income:
Total operating income	$ 45,291	$ 170,055	$ 33,034	$ 314,759	$ 40,330	$ 231,503	$ 224,771	$ 356,791	563,139	853,395	654,604
Reconciliation of operating income to income from continuing operations:
Other income									9,953	6,853	9,242
Interest expense									146,531	136,537	142,688
Income tax expense									104,675	214,092	175,186
Income from continuing operations									321,886	509,619	345,972
Operating Segments | EQT Production
Revenues from external customers, including affiliates:
Total									1,540,889	1,813,292	1,310,938
Operating income:
Total operating income									104,865	505,950	371,245
Operating Segments | EQT Midstream
Revenues from external customers, including affiliates:
Total									807,904	699,083	614,042
Operating income:
Total operating income									473,378	384,309	328,782
Less intersegment revenues, net
Revenues from external customers, including affiliates:
Total									(9,031)	(42,665)	(62,969)
Unallocated expenses
Operating income:
Total operating income									$ (15,104)	$ (36,864)	$ (45,423)

Financial Information by Busi59

Financial Information by Business Segment - Schedule of Segment Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment assets:
Assets	$ 13,976,172	$ 12,035,353	$ 9,765,907
Total operating segments
Segment assets:
Assets	12,221,991	10,862,251	8,873,494
Total operating segments | EQT Production
Segment assets:
Assets	8,995,853	8,153,199	6,359,065
Total operating segments | EQT Midstream
Segment assets:
Assets	3,226,138	2,709,052	2,514,429
Headquarters assets, including cash and short-term investments
Segment assets:
Assets	$ 1,754,181	$ 1,173,102	$ 892,413

Financial Information by Busi60

Financial Information by Business Segment - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Gain on sales/exchanges of assets	$ 0	$ 34,146,000	$ 19,618,000
Impairment of long lived assets	122,469,000	267,339,000	0
Unallocated expenses
Segment Reporting Information [Line Items]
Amount of contribution to foundation		20,000,000
EQT Production
Segment Reporting Information [Line Items]
Gain on sales/exchanges of assets		27,400,000
Impairment of long lived assets	118,268,000	267,339,000	0
EQT Production | Total operating segments
Segment Reporting Information [Line Items]
Expenditures for property acquisitions	182,300,000	724,400,000	186,200,000
Non-cash capital expenditures		349,200,000
EQT Midstream
Segment Reporting Information [Line Items]
Gain on sales/exchanges of assets		6,800,000
Impairment of long lived assets	$ 4,200,000	$ 0	$ 0

Financial Information by Busi61

Financial Information by Business Segment - Schedule of Depreciation, Depletion, Amortization and Expenditures for Segment Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Depreciation, depletion and amortization:
Total	$ 819,216	$ 679,298	$ 653,132
Expenditures for segment assets:
Total	2,344,414	2,900,186	1,796,876
Total operating segments | EQT Production
Depreciation, depletion and amortization:
Total	723,448	592,855	578,641
Expenditures for segment assets:
Total	1,852,100	2,441,486	1,423,185
Total operating segments | EQT Midstream
Depreciation, depletion and amortization:
Total	95,280	87,034	75,032
Expenditures for segment assets:
Total	486,809	455,359	369,399
Other
Depreciation, depletion and amortization:
Total	488	(591)	(541)
Expenditures for segment assets:
Total	$ 5,505	$ 3,341	$ 4,292

Derivative Instruments - Narra

Derivative Instruments - Narrative (Details) MMcf in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014USD ($)MMcf	Dec. 31, 2013USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Deferred net gains	$ 64,800,000	$ 217,100,000
Net gains on derivative commodity instruments	54,700,000
Gain due to the exclusion of the spot/forward differential from the assessment of effectiveness			$ 500,000
Loss due to changes in basis			$ 1,500,000
Current assets	$ 0	100,000
Percentage of derivative liability (up to)	100.00%
Aggregate fair value of derivative instruments with credit-risk related contingencies	$ 4,800,000
Collateral posted	$ 0
Commodity Derivatives | Cash flow Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Pre-tax gain		$ 28,000,000
Absolute quantities of derivative commodity instruments (in MMcf) | MMcf	676	624

Derivative Instruments - Sched

Derivative Instruments - Schedule of Designated and Not Designated as Hedging Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commodity derivatives designated as cash flow hedges
Amount of gain reclassified from accumulated OCI, net of tax, into gain on sale / exchange of assets and dispositions due to forecasted transactions probable to not occur		$ (16,735)
Derivatives not designated as hedging instruments
Amount of gain recognized in operating revenues	$ 385,762	80,942	$ 2,834
Not designated as hedging instruments
Derivatives not designated as hedging instruments
Amount of gain recognized in operating revenues	385,762	80,942	2,834
Commodity Derivatives | Cash flow Hedges
Commodity derivatives designated as cash flow hedges
Amount of gain recognized in OCI (effective portion), net of tax	0	156,207	10,669
Amount of gain reclassified from accumulated OCI, net of tax, into gain on sale / exchange of assets and dispositions due to forecasted transactions probable to not occur	0	16,735	0
Amount of gain (loss) reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	152,359	(15,950)	87,158
Amount of gain (loss) recognized in operating revenues (ineffective portion)	0	24,774	(21,335)
Interest rate derivatives designated as cash flow hedges
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	152,359	(15,950)	87,158
Commodity Derivatives | Fair value hedges
Commodity derivatives designated as fair value hedges
Amount of loss recognized in operating revenues for fair value commodity contracts	0	0	(1,341)
Fair value gain recognized in operating revenues for inventory designated as hedged item	0	0	386
Interest Rate Derivatives | Cash flow Hedges
Commodity derivatives designated as cash flow hedges
Amount of gain (loss) reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	(144)	(145)	(144)
Interest rate derivatives designated as cash flow hedges
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	$ (144)	$ (145)	$ (144)

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Impact of Netting Agreements and Margin Deposits on Gross Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Asset derivatives:
Derivative instruments, recorded in the Consolidated Balance Sheet, gross	$ 417,397	$ 458,460
Commodity Contract | Derivative instruments, recorded in the Consolidated Balance Sheet, gross
Asset derivatives:
Derivative instruments, recorded in the Consolidated Balance Sheet, gross	417,397	458,460
Derivative instruments subject to master netting agreements	(19,909)	(22,810)
Margin deposits remitted to counterparties	0	0
Derivative instruments, net	397,488	435,650
Liability derivatives:
Derivative instruments, recorded in the Consolidated Balance Sheet, gross	23,434	22,942
Derivative instruments subject to master netting agreements	(19,909)	(22,810)
Margin deposits remitted to counterparties	0	(132)
Derivative instruments, at fair value	$ 3,525	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Estimated fair value of total debt	$ 2,803,267	$ 3,314,202
Carrying value of total debt	$ 2,793,343	$ 2,959,353

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets
Derivative instruments, at fair value	$ 417,397	$ 458,460
Fair Value, Measurements, Recurring | Quoted prices in active markets for identical assets (Level 1)
Assets
Derivative instruments, at fair value	0	0
Liabilities
Derivative instruments, at fair value	0	132
Fair Value, Measurements, Recurring | Significant other observable inputs (Level 2)
Assets
Derivative instruments, at fair value	417,397	458,460
Liabilities
Derivative instruments, at fair value	23,434	22,810
Fair Value, Measurements, Recurring | Significant unobservable inputs (Level 3)
Assets
Derivative instruments, at fair value	0	0
Liabilities
Derivative instruments, at fair value	0	0
Commodity Contract | Fair Value, Measurements, Recurring
Assets
Derivative instruments, at fair value	417,397	458,460
Liabilities
Derivative instruments, at fair value	$ 23,434	$ 22,942

Sales of Properties and Contr67

Sales of Properties and Contracts (Details) a in Thousands, MMcf in Thousands, $ in Thousands	Dec. 31, 2013USD ($)customer	Jun. 30, 2014USD ($)awell	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)customerMMcf	Dec. 17, 2013USD ($)customer
Schedule of Equity Method Investments [Line Items]
Proceeds from sale of energy marketing contracts in cash			$ 0	$ 0	$ 23,000
Pre-tax gain recorded			$ 0	34,146	19,618
Pre-tax gain on de-designation of derivative instruments		$ 28,000
Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage		50.00%
EQT Production
Schedule of Equity Method Investments [Line Items]
Pre-tax gain recorded				27,400
Range Resources Corporation
Schedule of Equity Method Investments [Line Items]
Approximate area of acquisition (in acres) | a		73
Number of producing wells acquired | well		900
Area of property transferred under asset exchange agreement (in acres) | a		138
Number of producing wells transferred under asset exchange agreement | well		2,000
Ownership interest transferred		50.00%
Fair value of assets		$ 516,500
Pre-tax gain recorded		34,100
Range Resources Corporation | Acreage
Schedule of Equity Method Investments [Line Items]
Fair value of assets		318,300
Range Resources Corporation | Wells
Schedule of Equity Method Investments [Line Items]
Fair value of assets		198,200
Range Resources Corporation | EQT Production
Schedule of Equity Method Investments [Line Items]
Amount of cash, subject to certain post-closing adjustments		$ 167,300
Equitable Gas and Homeworks
Schedule of Equity Method Investments [Line Items]
Sale of energy marketing contracts					$ 20,000
Number of customers with whom natural gas sale agreements are entered | customer	1,000				1,000
Sale volumes of energy marketing contracts (in MMcf) | MMcf					12
Proceeds from sale of energy marketing contracts in cash	$ 18,000
Amount expected to be collected				$ 2,000
Gain on sale of energy marketing contracts					$ 19,600
Number of customers with whom natural gas sale agreements are entered related to certain acquired assets | customer						50
Value of energy marketing contracts						$ 5,000
Sale of energy marketing contracts related to certain acquired assets	$ 5,000				$ 5,000

Acquisitions (Details)

Acquisitions (Details) a in Thousands, $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2013USD ($)awell	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Acquisitions
Purchase price of acquisition allocated to undeveloped acreage		$ 158,405	$ 493,067	$ 95,861
Purchase price of acquisition allocated to acquired wells		$ 23,890	$ 231,322	90,390
Chesapeake
Acquisitions
Approximate area of acquisition (in acres) | a	99
Purchase price of acquisition	$ 114,200
Purchase price of acquisition allocated to undeveloped acreage	$ 57,200
Chesapeake | Marcellus
Acquisitions
Approximate area of acquisition (in acres) | a	67
Number of wells acquired | well	10
Portion unlikely to be developed (in acres) | a	42
Purchase price of acquisition allocated to undeveloped acreage				$ 41,900
Purchase price of acquisition allocated to acquired wells	$ 57,000

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current:
Federal	$ 85,696	$ 164,935	$ 100,796
State	1,103	17,136	46,758
Subtotal	86,799	182,071	147,554
Deferred:
Federal	(109,642)	38,357	51,767
State	127,518	(6,336)	(23,940)
Subtotal	17,876	32,021	27,827
Amortization of deferred investment tax credit	0	0	(195)
Total income taxes	$ 104,675	$ 214,092	$ 175,186

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Tax Credit Carryforward [Line Items]
Federal statutory rate		35.00%
Effective tax rate		24.50%	29.60%	33.60%
Percentage of pre-tax income related to the noncontrolling limited partners' share of earnings		100.00%
Tax benefit in connection with recent IRS guidance		$ (104,675,000)	$ (214,092,000)	$ (175,186,000)
Amortization period		32 years
Effective tax rate, amount		$ 94,100,000	33,900,000	33,300,000
Tax positions for which the ultimate deductibility is highly certain	$ 6,400,000	6,400,000	6,900,000	7,600,000
Interest expense		1,600,000	1,900,000	(400,000)
Interests and penalties	3,600,000	3,600,000	2,000,000	200,000
Deferred tax liability related to net unrealized gain from hedging transactions	40,200,000	40,200,000	141,300,000
Deferred tax asset related to other post-retirement benefits	4,900,000	4,900,000	5,400,000
Deferred tax asset related to the Company’s pension plans	6,100,000	6,100,000	5,100,000
Deferred tax asset	90,300,000	90,300,000	116,000,000
Net of valuation allowances	156,100,000	156,100,000	65,000,000
Reduction of deferred tax assets for uncertain tax positions		31,700,000	300,000
Tax benefits as and addition to common stockholders' equity		13,100,000	26,600,000
Tax benefits for excess tax benefits previously not recorded		8,100,000	6,600,000
Deferred Tax Assets
Tax Credit Carryforward [Line Items]
Uncertain tax positions	114,200,000	114,200,000	$ 10,100,000	$ 9,800,000
Equitable Gas Company, LLC
Tax Credit Carryforward [Line Items]
Tax benefit in connection with recent IRS guidance		35,400,000
EQM
Tax Credit Carryforward [Line Items]
Aggregate offering price (up to)	$ 750,000,000	$ 750,000,000

- Schedule of Reconciliation of

- Schedule of Reconciliation of Income Tax Expense to Amount Computed at the Federal Statutory Rate (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Tax at statutory rate	$ 149,296	$ 253,299	$ 182,406
State income taxes	(7,566)	(2,992)	26,012
Valuation allowance	91,144	10,012	(9,832)
Noncontrolling partners’ share of EQGP and EQM earnings	(82,850)	(43,409)	(16,535)
Regulatory asset	(35,438)	0	0
Research and experimentation credit	(7,243)	(468)	(375)
Other	(2,668)	(2,350)	(6,490)
Total income taxes	$ 104,675	$ 214,092	$ 175,186
Effective tax rate	24.50%	29.60%	33.60%

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of the Beginning and Ending Amount of Reserve for Uncertain Tax Positions(Excluding Interest and Penalties) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of reserve for uncertain tax positions, Excluding Amounts Pertaining to Examined Tax Returns
Beginning Balance	$ 56,957	$ 57,087	$ 17,858
Additions based on tax positions related to current year	152,983	1,195	49,289
Additions for tax positions of prior years	50,688	93	0
Reductions for tax positions of prior years	(1,327)	(1,418)	(790)
Lapse of statute of limitations	0	0	(9,270)
Ending Balance	$ 259,301	$ 56,957	$ 57,087

Income Taxes - Summary of Sourc

Income Taxes - Summary of Source and Tax Effects of Temporary Differences between Financial Reporting and Tax Bases of Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred income taxes:
Total deferred income tax assets	$ (827,161)	$ (971,531)
Deferred Income Tax Liabilities, Net	2,799,331	2,700,467
Total deferred income tax liabilities	1,972,170	1,728,936
Total deferred income tax liabilities (assets)
Drilling and development costs expensed for income tax reporting	1,421,581	1,391,156
Tax depreciation in excess of book depreciation	1,224,377	1,154,082
Accumulated OCI	29,154	130,770
Post-retirement benefits	3,326	3,146
Incentive compensation and deferred compensation plans	(75,143)	(65,086)
Net operating loss carryforwards	(214,714)	(212,718)
Investment in EQGP and EQM	(426,343)	(336,394)
Alternative minimum tax credit carryforward	(267,045)	(412,345)
Unrealized hedge gains	107,854	21,314
Other	13,039	(9,976)
Total excluding valuation allowances	1,816,086	1,663,949
Valuation allowance	$ 156,084	64,987
Amounts classified as current assets		$ 21,934

Equity in Nonconsolidated Inv74

Equity in Nonconsolidated Investments - Schedule of Equity in Nonconsolidated Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Variable Interest Entity, Not Primary Beneficiary | MVP Joint Venture
Schedule of Equity Method Investments [Line Items]
Equity in nonconsolidated investments	$ 77,025	$ 0

Equity in Nonconsolidated Inv75

Equity in Nonconsolidated Investments - Narrative (Details)	Jan. 21, 2016USD ($)	Mar. 31, 2015	Dec. 31, 2015USD ($)mi	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 11, 2016USD ($)
Schedule of Equity Method Investments [Line Items]
Issuance of performance guarantee			$ 108,000,000
Mountain Valley Pipeline
Schedule of Equity Method Investments [Line Items]
Natural gas interstate pipeline (in miles) | mi			300
MVP Joint Venture | Beneficial Owner
Schedule of Equity Method Investments [Line Items]
Ownership percentage			66.67%
MVP Joint Venture | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Maximum financial statement exposure			$ 185,000,000
Investment balance			77,025,000	$ 0
MVP Joint Venture | Subsequent Event | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Decrease of initial guarantee						$ 91,000,000
EQM
Schedule of Equity Method Investments [Line Items]
Total investments			$ 2,600,000	$ 3,400,000	$ 7,600,000
Percentage of membership interest		100.00%
EQM | MVP Joint Venture | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Ownership percentage			54.00%
EQM | MVP Joint Venture | Subsequent Event | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Ownership percentage						45.50%
ConEd | Subsequent Event | Variable Interest Entity, Not Primary Beneficiary | MVP Joint Venture
Schedule of Equity Method Investments [Line Items]
Interest in joint venture (as a percent)	12.50%
Percentage of ownership purchased	8.50%
Cash payments	$ 12,500,000
Mountain Valley Pipeline | Variable Interest Entity, Not Primary Beneficiary | MVP Joint Venture
Schedule of Equity Method Investments [Line Items]
Percentage of remaining obligations			33.00%

Equity in Nonconsolidated Inv76

Equity in Nonconsolidated Investments - Schedule of Condensed Financial Statements for Nonconsolidated Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$ 0	$ 19,924	$ 45,040
Operating expenses	0	13,257	29,892
Other income	2,566	102	82
Net income	$ 2,566	$ 6,769	$ 15,230

Revolving Credit Facilities (De

Revolving Credit Facilities (Details)	12 Months Ended
	Dec. 31, 2015USD ($)extensionfinancial_institution	Dec. 31, 2014USD ($)
Debt Disclosure [Abstract]
Number of times the maturity date of the credit facility can be extended by one year | extension	2
Length of extension of line of credit	1 year
Number of financial institutions underwriting credit facility of the entity | financial_institution	18
Line of Credit Facility
Unsecured revolving credit facility	$ 1,500,000,000
Aggregate amount (up to)	$ 2,000,000,000
Debt-to-total capitalization ratio (no greater than)	65.00%
Revolving Credit Facility
Line of Credit Facility
Commitment fee paid to maintain credit facility	0.23%	23.00%
EQM
Line of Credit Facility
Unsecured revolving credit facility	$ 750,000,000
Aggregate amount (up to)	$ 1,000,000,000
EQM | Line of credit
Line of Credit Facility
Leverage ratio (not more than)	5
Leverage ratio for certain measurement periods (not more than)	5.50
EQM | Revolving Credit Facility
Line of Credit Facility
Commitment fee paid to maintain credit facility	0.23%	0.24%
Revolving credit facility outstanding amount at the end of period	$ 299,000,000
Maximum amount of outstanding borrowings	403,500,000	$ 450,000,000
Average daily balance of loans outstanding	$ 261,000,000	$ 119,000,000
Weighted average interest rates	1.70%	1.70%
Letters of credit outstanding	$ 0

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Principal Value	$ 2,818,200,000	$ 2,988,900,000
Carrying Value	2,793,343,000	2,959,353,000
Fair Value	2,803,267,000	3,314,202,000
Debt payable within one year, principal value	0	166,011,000
Debt payable within one year, carrying value	0	(165,874,000)
Debt payable within one year, fair value	0	(171,081,000)
Total long-term debt, principal value	2,818,200,000	2,822,889,000
Total long-term debt, carrying value	2,793,343,000	2,793,479,000
Total long-term debt, fair value	2,803,267,000	3,143,121,000
7.76% notes, due 2015 through 2016
Debt Instrument [Line Items]
Principal Value	0	10,700,000
Carrying Value	0	10,700,000
Fair Value	$ 0	10,700,000
Interest rate	7.76%
5.00% notes, due October 1, 2015
Debt Instrument [Line Items]
Principal Value	$ 0	150,000,000
Carrying Value	0	149,865,000
Fair Value	$ 0	154,692,000
Interest rate	5.00%
5.15% notes, due March 1, 2018
Debt Instrument [Line Items]
Principal Value	$ 200,000,000	200,000,000
Carrying Value	199,156,000	198,766,000
Fair Value	$ 203,490,000	214,626,000
Interest rate	5.15%
6.50% notes, due April 1, 2018
Debt Instrument [Line Items]
Principal Value	$ 500,000,000	500,000,000
Carrying Value	498,360,000	497,630,000
Fair Value	$ 520,175,000	559,900,000
Interest rate	6.50%
8.13% notes, due June 1, 2019
Debt Instrument [Line Items]
Principal Value	$ 700,000,000	700,000,000
Carrying Value	697,295,000	696,483,000
Fair Value	$ 760,837,000	843,864,000
Interest rate	8.13%
4.88% notes, due November 15, 2021
Debt Instrument [Line Items]
Principal Value	$ 750,000,000	750,000,000
Carrying Value	742,270,000	740,945,000
Fair Value	$ 728,063,000	812,558,000
Interest rate	4.88%
7.75% debentures, due July 15, 2026
Debt Instrument [Line Items]
Principal Value	$ 115,000,000	115,000,000
Carrying Value	109,738,000	109,240,000
Fair Value	$ 119,372,000	147,036,000
Interest rate	7.75%
Medium-term notes, 7.3% to 7.6% Series B, due 2015 thru 2023
Debt Instrument [Line Items]
Principal Value	$ 10,000,000	20,000,000
Carrying Value	9,991,000	19,985,000
Fair Value	$ 10,241,000	22,279,000
Interest rate, minimum	7.30%
Interest rate, maximum	7.60%
Medium-term notes, 7.6% Series C, due 2018
Debt Instrument [Line Items]
Principal Value	$ 8,000,000	8,000,000
Carrying Value	7,983,000	7,975,000
Fair Value	$ 8,366,000	8,950,000
Interest rate	7.60%
Medium-term notes, 8.7% to 9.0% Series A, due 2020 thru 2021
Debt Instrument [Line Items]
Principal Value	$ 35,200,000	35,200,000
Carrying Value	35,149,000	35,131,000
Fair Value	$ 38,598,000	43,912,000
Interest rate, minimum	8.70%
Interest rate, maximum	9.00%
EQT Midstream | 4.00% EQM notes, due August 1, 2024
Debt Instrument [Line Items]
Principal Value	$ 500,000,000	500,000,000
Carrying Value	493,401,000	492,633,000
Fair Value	$ 414,125,000	$ 495,685,000
Interest rate	4.00%

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details)	Dec. 31, 2015USD ($)
Debt Disclosure [Abstract]
Aggregate maturities in 2016	$ 0
Aggregate maturities in 2017	0
Aggregate maturities in 2018	708,000,000
Aggregate maturities in 2019	700,000,000
Aggregate maturities in 2020	$ 11,200,000

Pension and Other Post-Retire80

Pension and Other Post-Retirement Benefit Plans - Schedule of Funded Status and Amounts for Defined Benefit Pension and Other Post-Retirement Benefit Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	$ 21,704	$ 21,828
Service cost	350	350	$ 500
Interest cost	746	820	1,935
Amendments	0	0
Actuarial loss (gain)	2,770	2,412
Benefits paid	(1,981)	(1,988)
Expenses paid	(367)	(262)
Settlements	(177)	(1,456)
Benefit obligation at end of year	23,045	21,704	21,828
Change in plan assets:
Fair value of plan assets at beginning of year	18,323	20,089
Actual (loss) gain on plan assets	(32)	1,217
Contributions	1,175	723	2,600
Benefits paid	(1,981)	(1,988)
Expenses paid	(367)	(262)
Settlements	(177)	(1,456)
Fair value of plan assets at end of year	16,941	18,323	20,089
Funded status at end of year	(6,104)	(3,381)
Other Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	18,741	18,253
Service cost	762	669	905
Interest cost	634	693	1,110
Amendments	0	227
Actuarial loss (gain)	(361)	1,190
Benefits paid	(2,141)	(2,291)
Expenses paid	0	0
Settlements	0	0
Benefit obligation at end of year	17,635	18,741	18,253
Change in plan assets:
Fair value of plan assets at beginning of year	823	493
Actual (loss) gain on plan assets	0	0
Contributions	287	330
Benefits paid	0	0
Expenses paid	0	0
Settlements	0	0
Fair value of plan assets at end of year	1,110	823	$ 493
Funded status at end of year	$ (16,525)	$ (17,918)

Pension and Other Post-Retire81

Pension and Other Post-Retirement Benefit Plans - Schedule of Amounts Recognized in Statement of Financial Position (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Amounts recognized in the statement of financial position consist of:
Current liabilities	$ (6,104)	$ 0
Noncurrent liabilities	0	(3,381)
Net amounts recognized	(6,104)	(3,381)
Amounts recognized in accumulated OCI, net of tax, consist of:
Net loss	9,674	8,082
Net prior service	0	0
Net amount recognized	9,674	8,082
Other Benefits
Amounts recognized in the statement of financial position consist of:
Current liabilities	(1,376)	(924)
Noncurrent liabilities	(15,149)	(16,994)
Net amounts recognized	(16,525)	(17,918)
Amounts recognized in accumulated OCI, net of tax, consist of:
Net loss	7,610	8,273
Net prior service	257	285
Net amount recognized	$ 7,867	$ 8,558

Pension and Other Post-Retire82

Pension and Other Post-Retirement Benefit Plans - Narrative (Details) - USD ($) $ in Thousands	Jan. 01, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Accumulated benefit obligation for the defined benefit pension plan		$ 23,000	$ 21,700
Defined Benefit Plans costs
Annual rate of increase in Pre-65 medical charges		7.00%
Ultimate rates		5.00%
Expense recognized related to defined contribution plan		$ 15,700	13,700	$ 14,600
Mutual Funds | Quoted Prices in Active Markets for Identical Assets (Level 1)
Defined Benefit Plans costs
Fair value of plan assets		5,400	5,700
Common Collective Trusts | Significant Other Observable Inputs (Level 2)
Defined Benefit Plans costs
Fair value of plan assets		11,300	$ 12,600
Pension Benefits
Defined Benefit Plans costs
Net loss of defined benefit pension plans, amortized from accumulated OCI, net of tax, into net periodic benefit cost		100
Defined benefit plan recognized upon final settlement		$ 9,500
Expected return on plan assets		3.75%	7.75%
Cash contributions to pension plan		$ 1,175	$ 723	2,600
Expected cash payments related to its pensions		6,100
Defined benefit plan, expected future benefit payments in year 2016		22,900
Fair value of plan assets		16,941	18,323	20,089
Pension Benefits | Subsequent Event | Maximum
Defined Benefit Plans costs
Expected return on plan assets	3.75%
Other Benefits
Defined Benefit Plans costs
Net loss of defined benefit pension plans, amortized from accumulated OCI, net of tax, into net periodic benefit cost		400
Net prior service credit of other post-retirement benefit plans, amortized from accumulated OCI, net of tax, into net periodic benefit cost		(200)
Cash contributions to pension plan		287	330
Defined benefit plan, expected future benefit payments in year 2016		1,700
Defined benefit plan, expected future benefit payments in year 2017		1,700
Defined benefit plan, expected future benefit payments in year 2018		1,600
Defined benefit plan, expected future benefit payments in year 2019		1,600
Defined benefit plan, expected future benefit payments in year 2020		1,600
Defined benefit plan, expected future benefit payments in the five years thereafter		7,100
Fair value of plan assets		$ 1,110	$ 823	493
Equitable Gas and Homeworks
Defined Benefit Plans costs
Net loss and prior service cost				$ 17,300

Pension and Other Post-Retire83

Pension and Other Post-Retirement Benefit Plans - Schedule of Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Components of net periodic benefit cost:
Service cost	$ 350	$ 350	$ 500
Interest cost	746	820	1,935
Expected return on plan assets	(627)	(1,377)	(3,323)
Amortization of prior service cost	0	0	0
Recognized net actuarial loss	746	709	2,306
Settlement loss and special termination benefits	122	879	381
Subtotal	1,337	1,381	1,799
Net periodic benefit cost of discontinued operations	0	0	1,552
Net periodic benefit cost of discontinued operations	1,337	1,381	247
Other Benefits
Components of net periodic benefit cost:
Service cost	762	669	905
Interest cost	634	693	1,110
Expected return on plan assets	0	0	0
Amortization of prior service cost	(306)	(446)	(845)
Recognized net actuarial loss	793	879	1,760
Settlement loss and special termination benefits	0	0	0
Subtotal	1,883	1,795	2,930
Net periodic benefit cost of discontinued operations	0	0	1,356
Net periodic benefit cost of discontinued operations	$ 1,883	$ 1,795	$ 1,574

Pension and Other Post-Retire84

Pension and Other Post-Retirement Benefit Plans - Schedule of Amount Recognized in Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
Total recognized in OCI, net of tax	$ 901	$ 776	$ (21,501)
Pension Benefits
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
Net loss (gain)	1,592	558	712
Net prior service (credit) cost	0	0	0
Total recognized in OCI, net of tax	1,592	558	712
Total recognized in net periodic benefit cost and OCI, net of tax	2,929	1,939	959
Other Benefits
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
Net loss (gain)	(663)	39	2,147
Net prior service (credit) cost	(28)	179	416
Total recognized in OCI, net of tax	(691)	218	2,563
Total recognized in net periodic benefit cost and OCI, net of tax	$ 1,192	$ 2,013	$ 4,137

Pension and Other Post-Retire85

Pension and Other Post-Retirement Benefit Plans - Schedule of Assumption Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Components of net periodic benefit cost:
Benefit obligations, Discount rate	2.20%	3.60%
Net periodic benefit cost, Discount rate	3.60%	4.00%
Expected return on plan assets	3.75%	7.75%
Other Benefits
Components of net periodic benefit cost:
Benefit obligations, Discount rate	3.95%	3.60%
Net periodic benefit cost, Discount rate	3.60%	4.00%

Pension and Other Post-Retire86

Pension and Other Post-Retirement Benefit Plans - Schedule of Impact of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Increase to total of service and interest cost components, One-Percent-Point-Increase	$ 10	$ 13	$ 25
Decrease to total of service and interest cost components, One-Percentage-Point-Decrease	(11)	(14)	(26)
Increase to post-retirement benefit obligation, One-Percentage-Point-Increase	268	228	220
Decrease to post-retirement benefit obligation, One-Percentage-Point-Decrease	$ (278)	$ (229)	$ (223)

Pension and Other Post-Retire87

Pension and Other Post-Retirement Benefit Plans - Schedule of Entity's Asset Allocation (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Components of net periodic benefit cost:
Percentage of Plan Assets	100.00%	100.00%
Domestic broadly diversified equity securities
Components of net periodic benefit cost:
Percentage of Plan Assets	0.00%	26.00%
Fixed income securities
Components of net periodic benefit cost:
Percentage of Plan Assets	99.00%	63.00%
International broadly diversified equity securities
Components of net periodic benefit cost:
Percentage of Plan Assets	0.00%	8.00%
Target Allocation 2016	0.00%
Cash and equivalent investments
Components of net periodic benefit cost:
Percentage of Plan Assets	1.00%	3.00%
Minimum | Domestic broadly diversified equity securities
Components of net periodic benefit cost:
Target Allocation 2016	0.00%
Minimum | Fixed income securities
Components of net periodic benefit cost:
Target Allocation 2016	80.00%
Minimum | Cash and equivalent investments
Components of net periodic benefit cost:
Target Allocation 2016	0.00%
Maximum | Domestic broadly diversified equity securities
Components of net periodic benefit cost:
Target Allocation 2016	10.00%
Maximum | Fixed income securities
Components of net periodic benefit cost:
Target Allocation 2016	100.00%
Maximum | Cash and equivalent investments
Components of net periodic benefit cost:
Target Allocation 2016	20.00%

Changes in Accumulated Other 88

Changes in Accumulated Other Comprehensive Income by Component (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in accumulated other comprehensive income (loss) by component
Total	152,939	152,513	151,787
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at the beginning of the period	$ 199,494	$ 44,703	$ 99,547
Gains recognized in accumulated OCI, net of tax		156,207	12,750
Gain reclassified from accumulated OCI, net of tax, into gain on sale/exchange of assets		(16,735)
(Gains) losses reclassified from accumulated OCI, net of tax	(153,116)	15,319	(67,594)
Other comprehensive (loss) income	(153,116)	154,791	(54,844)
Balance at the end of the period	46,378	199,494	44,703
Cash flow hedge, net of tax | Natural gas cash flow hedges, net of tax
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at the beginning of the period	217,121	61,699	138,188
Gains recognized in accumulated OCI, net of tax		156,207	10,669
Gain reclassified from accumulated OCI, net of tax, into gain on sale/exchange of assets		(16,735)
(Gains) losses reclassified from accumulated OCI, net of tax	(152,359)	15,950	(87,158)
Other comprehensive (loss) income		155,422	(76,489)
Balance at the end of the period	64,762	217,121	61,699
Cash flow hedge, net of tax | Interest rate cash flow hedges, net of tax
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at the beginning of the period	(987)	(1,132)	(1,276)
Gains recognized in accumulated OCI, net of tax		0	0
Gain reclassified from accumulated OCI, net of tax, into gain on sale/exchange of assets		0
(Gains) losses reclassified from accumulated OCI, net of tax	144	145	144
Other comprehensive (loss) income		145	144
Balance at the end of the period	(843)	(987)	(1,132)
Pension and other post- retirement benefits liability adjustment, net of tax
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance at the beginning of the period	(16,640)	(15,864)	(37,365)
Gains recognized in accumulated OCI, net of tax		0	2,081
Gain reclassified from accumulated OCI, net of tax, into gain on sale/exchange of assets		0
(Gains) losses reclassified from accumulated OCI, net of tax	(901)	(776)	19,420
Other comprehensive (loss) income		(776)	21,501
Balance at the end of the period	$ (17,541)	$ (16,640)	$ (15,864)

Common Stock and Earnings Per89

Common Stock and Earnings Per Share - Schedule of Shares of Authorized and Unissued Common Stock (Details) shares in Thousands	Dec. 31, 2015shares
Earnings Per Share [Abstract]
Possible future acquisitions (in shares)	20,457
Stock compensation plans (in shares)	13,394
Total (in shares)	33,851

Common Stock and Earnings Per90

Common Stock and Earnings Per Share - Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Shares of treasury stock transferred	17,000,000
Shares of treasury stock into a rabbi trust	291,919
Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive	291,700	0	0

Common Stock and Earnings Per91

Common Stock and Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic earnings per common share:
Net income attributable to EQT Corporation									$ 85,171	$ 386,965	$ 390,572
Average common shares outstanding									152,398	151,553	150,574
Basic earnings per common share (in dollars per share)	$ (0.88)	$ 0.27	$ 0.04	$ 1.14	$ (0.10)	$ 0.65	$ 0.73	$ 1.27	$ 0.56	$ 2.55	$ 2.59
Net Income (Loss) Available to Common Stockholders, Diluted [Abstract]
Net income attributable to EQT Corporation									$ 85,171	$ 386,965	$ 390,572
Stock options and awards									541	960	1,213
Total									152,939	152,513	151,787
Diluted earnings per common share (in dollars per share)	$ (0.88)	$ 0.27	$ 0.04	$ 1.14	$ (0.10)	$ 0.65	$ 0.73	$ 1.26	$ 0.56	$ 2.54	$ 2.57

Share-Based Compensation Plan92

Share-Based Compensation Plans - Schedule of Share-Based Compensation Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 54,692	$ 50,627	$ 58,544
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	7,031	4,688	3,033
Non-qualified stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1,938	3,002	3,805
Other programs, including non-employee director awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	(2,339)	(409)	9,154
2012 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	7,743	6,739
2013 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	6,834	8,208	6,602
2014 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	12,865	9,104	0
2015 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	12,051	0	0
2011 Volume and Efficiency Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	0	13,834
2012 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	0	2,327
2013 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	4,403	13,050
2014 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	1,116	11,510	0
2014 EQM Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	622	2,378	0
2015 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$ 14,574	$ 0	$ 0

Share-Based Compensation Plan93

Share-Based Compensation Plans - Share-Based Compensation Expense (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Cash received from exercises of all share-based payment arrangements for employees and directors	$ 14	$ 19.2	$ 32.9
Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards	$ 43.1	$ 45.9	$ 14.4

Share-Based Compensation Plan94

Share-Based Compensation Plans - Executive Performance Incentive Programs (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 01, 2015	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
2012 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value, granted (in dollars per share)							$ 123.37
Expected term							3 years
Risk-free interest rate							0.36%
Shares of common stock			307,323
Value of shares of common stock			$ 37.9
Capitalized compensation cost					$ 2.6	$ 8.1
2013 Executive Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value, granted (in dollars per share)						$ 140
Expected term						3 years
Risk-free interest rate						0.36%
Capitalized compensation cost				$ 4.4	5.5	$ 5
2014 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value, granted (in dollars per share)				$ 189.68
Expected term				3 years
Risk-free interest rate				0.78%
Capitalized compensation cost				$ 4.9	$ 4.6
Number of shares granted	259,230
Non-vested shares, forfeited				10,420
Outstanding units (in shares)				248,810
Unrecognized compensation costs on non-vested awards				$ 15.7
2014 Executive Performance Incentive Program | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level				0.00%
2014 Executive Performance Incentive Program | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level				300.00%
2015 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value, granted (in dollars per share)				$ 160.13
Expected term				3 years
Risk-free interest rate				1.10%
Capitalized compensation cost				$ 4.9
Number of shares granted				369,290
Non-vested shares, forfeited				12,890
Outstanding units (in shares)				356,400
Unrecognized compensation costs on non-vested awards				$ 33.9
Unrecognized compensation costs on non-vested awards, weighted average period of recognition				2 years
2015 Executive Performance Incentive Program | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level				0.00%
2015 Executive Performance Incentive Program | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level				300.00%
Scenario, Forecast | 2013 Executive Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock		261,073
Value of shares of common stock		$ 36.6

Share-Based Compensation Plan95

Share-Based Compensation Plans - Value Driver Award Programs (Narrative) (Details) $ / shares in Units, $ in Millions	Jan. 01, 2015shares	Feb. 28, 2015shares	Feb. 28, 2014trancheshares	Jan. 31, 2013trancheshares	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012
2012 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one (as a percent)								50.00%
Award vested at end of year two (as a percent)								50.00%
Number of tranches | tranche				2
Number of units distributed (in shares) | shares			194,943	204,679
Weighted average fair value, granted (in dollars per share) | $ / shares					$ 54.79
Capitalized compensation cost							$ 2.6
2013 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one (as a percent)							50.00%
Award vested at end of year two (as a percent)							50.00%
Number of tranches | tranche			2
Number of units distributed (in shares) | shares		279,475	306,076
Weighted average fair value, granted (in dollars per share) | $ / shares					$ 58.98
Capitalized compensation cost						$ 2.9	$ 14.1
2014 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one (as a percent)						50.00%
Award vested at end of year two (as a percent)						50.00%
Number of units distributed (in shares) | shares	375,426				181,928
Cash paid					$ 14.2
Capitalized compensation cost					1.3	$ 9.8
Total liability					$ 9.5	$ 21.3
2015 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units distributed (in shares) | shares					448,487
Weighted average fair value, granted (in dollars per share) | $ / shares					$ 75.70
Capitalized compensation cost					$ 10.9
Unrecognized compensation costs					$ 8.4

Share-Based Compensation Plan96

Share-Based Compensation Plans - 2011 Volume and Efficiency Program (Narrative) (Details) - 2011 Volume and Efficiency Program - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units distributed (in shares)	663,350
Weighted average fair value, granted (in dollars per share)	$ 48.06
Capitalized compensation cost		$ 2.8

Share-Based Compensation Plan97

Share-Based Compensation Plans - Restricted Stock Awards (Narrative) (Details) - Restricted stock awards - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted	158,360	89,500	101,510
Period after which the shares granted will be fully vested	3 years
Weighted average fair value, granted (in dollars per share)	$ 75.46	$ 95	$ 71
Total fair value of restricted stock awards	$ 3,808,262	$ 1,500,000	$ 4,300,000
Unrecognized compensation costs on non-vested awards	$ 13,200,000
Unrecognized compensation costs on non-vested awards, weighted average period of recognition	1 year 8 months

Share-Based Compensation Plan98

Share-Based Compensation Plans - Summary of Restricted Stock Activity (Details) - Restricted stock awards - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Non- Vested Shares
Non-Vested Shares, Outstanding, Beginning Balance	229,990
Non-Vested Shares, Granted	158,360	89,500	101,510
Non-Vested Shares, Vested	(71,100)
Non-Vested Shares, Forfeited	(17,130)
Non-Vested Shares, Outstanding, Ending Balance	300,120	229,990
Weighted Average Fair Value
Weighted Average Fair Value, Outstanding, Beginning Balance (in dollars per share)	$ 74.90
Weighted Average Fair Value, Granted (in dollars per share)	75.46	$ 95	$ 71
Weighted Average Fair Value, Vested (in dollars per share)	53.56
Weighted Average Fair Value, Forfeited (in dollars per share)	80.92
Weighted Average Fair Value, Outstanding, Ending Balance (in dollars per share)	$ 79.90	$ 74.90
Aggregate Fair Value
Aggregate Fair Value, Outstanding, Beginning Balance	$ 17,225,411
Aggregate Fair Value, Granted	11,949,751
Aggregate Fair Value, Vested	(3,808,262)	$ (1,500,000)	$ (4,300,000)
Aggregate Fair Value, Forfeited	(1,386,273)
Aggregate Fair Value, Outstanding, Ending Balance	$ 23,980,627	$ 17,225,411

Share-Based Compensation Plan99

Share-Based Compensation Plans - Schedule of Valuation Assumptions for Non-Qualified Stock Options (Details) - Non-qualified Stock Options	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.61%	1.72%	0.76%
Dividend yield	0.12%	0.15%	0.22%
Volatility factor	26.80%	24.80%	31.69%
Expected term	5 years	5 years	5 years

Share-Based Compensation Pla100

Share-Based Compensation Plans - Non-Qualified Stock Options (Narrative) (Details) - Non-qualified Stock Options - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants in period (in shares)	158,200	133,500	259,600
Weighted average grant date fair value (in dollars per share)	$ 19.90	$ 22.25	$ 16.72
Total intrinsic value of options exercised	$ 15.1	$ 14.4	$ 22.8
Unrecognized compensation costs on non-vested awards	$ 2.9

Share-Based Compensation Pla101

Share-Based Compensation Plans - Summary of Option Activity (Details) - Non-qualified Stock Options - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Shares
Shares, outstanding, beginning balance	1,338,468
Shares, granted	158,200	133,500	259,600
Shares, exercised	(405,526)
Shares, forfeited	0
Shares, expired	(10,900)
Shares, outstanding, ending balance	1,080,242	1,338,468
Shares, exercisable	788,542
Weighted Average Exercise Price
Weighted average exercise price, outstanding, beginning balance (in dollars per share)	$ 54.08
Weighted average exercise price, granted (in dollars per share)	75.70
Weighted average exercise price, exercised (in dollars per share)	46
Weighted average exercise price, forfeited (in dollars per share)	0
Weighted average exercise price, expired (in dollars per share)	48.91
Weighted average exercise price, outstanding, ending balance (in dollars per share)	60.33	$ 54.08
Weighted average exercise price, exercisable (in dollars per share)	$ 52.25
Weighted Average Remaining Contractual Term
Weighted average remaining contractual term, outstanding, end of period	6 years 6 months 11 days
Weighted average remaining contractual term, exercisable	5 years 9 months 11 days
Aggregate Intrinsic Value
Aggregate intrinsic value, outstanding, end of period	$ 2,261,513
Aggregate intrinsic value, exercisable, end of period	$ 2,261,513

Share-Based Compensation Pla102

Share-Based Compensation Plans - Non-Employee Directors' Share Based Awards (Narrative) (Details) - Non-employee Directors' Share-Based Awards - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding	222,251
Shares granted	24,110	17,900	25,500
Weighted average fair value, granted (in dollars per share)	$ 75.52	$ 89.78	$ 58.98

Share-Based Compensation Pla103

Share-Based Compensation Plans - EQM Awards (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 28, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jan. 01, 2015	Jul. 31, 2012
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding		14,433
Weighted average fair value, granted (in dollars per share)		$ 88	$ 58.79	$ 37.92
Number of shares granted		2,220	2,580	3,790
EQM Total Return Programs | Performance awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding					139,980	146,490
Weighted average fair value, granted (in dollars per share)		$ 20.02
Volatility factor		38.00%
Partnership distribution growth rate		10.00%
Non-vested shares, forfeited		2,350
Number of shares granted		137,630
EQM Total Return Programs | Performance awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of unitholder return realized on common units from the date of grant		10.00%
Volatility factor		27.00%
EQM Total Return Programs | Performance awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility factor		72.00%
2014 EQM Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding		28,696			62,845
Weighted average fair value, granted (in dollars per share)		$ 58.79
Award vested at end of year one (as a percent)			50.00%
Award vested at end of year two (as a percent)			50.00%
Shares of common stock	31,629
Capitalized compensation cost		$ 0.1	$ 0.3

Share-Based Compensation Pla104

Share-Based Compensation Plans - EQGP Awards (Details) - EQGP Awards	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Independent director unit-based awards including accrued distributions outstanding (in shares) | shares	2,928
Weighted average fair value, granted (in dollars per share) | $ / shares	$ 28.77

Share-Based Compensation Pla105

Share-Based Compensation Plans - 2016 Value Driver Award Programs and 2015 Executive Performance Incentive Program (Narrative) (Details) - Scenario, Forecast - shares	12 Months Ended	36 Months Ended
	Dec. 31, 2016	Dec. 31, 2018
Value Driver Award Program 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted	377,330
Award vested at end of year one (as a percent)	50.00%
Award vested at end of year two (as a percent)	50.00%
Value Driver Award Program 2016 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level	0.00%
Value Driver Award Program 2016 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level	300.00%
Executive Performance Incentive Program 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted		468,710
Period after which the shares granted will be fully vested		3 years
Executive Performance Incentive Program 2016 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level		0.00%
Executive Performance Incentive Program 2016 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level		300.00%

Share-Based Compensation Pla106

Share-Based Compensation Plans - 2016 Stock Options (Narrative) (Details) - Scenario, Forecast - Stock Options 2016	Jan. 01, 2016$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants in period (in shares) | shares	188,600
Term of stock options	10 years
Exercise price (in dollars per share) | $ / shares	$ 52.13
Period after which the shares granted will be fully vested	3 years

Concentrations of Credit Risk (

Concentrations of Credit Risk (Details)	12 Months Ended
	Dec. 31, 2015USD ($)customer	Dec. 31, 2014customer	Dec. 31, 2013customer
Concentration Risk
Adjustments to the fair value of derivative contracts due to credit related concerns outside of the normal non-performance risk adjustment | $	$ 0
Customer concentration | Sales revenue goods, net | EQT Production
Concentration Risk
Number of customers | customer	1	1	1
Concentration risk	10.00%	12.00%	11.00%
Customer concentration | Accounts receivable
Concentration Risk
Concentration risk	79.00%	87.00%

Commitments and Contingencies (

Commitments and Contingencies (Details) MMBTU / d in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Bcf / dmi	Dec. 31, 2014USD ($)MMBTU / dmi	Dec. 31, 2013USD ($)
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Operating leases, rent expense	$ 85.2	$ 65.6	$ 56
Future lease payments under non-cancelable operating leases, 2015	155.5
Future lease payments under non-cancelable operating leases, 2016	41.5
Future lease payments under non-cancelable operating leases, 2017	31.5
Future lease payments under non-cancelable operating leases, 2018	19.7
Future lease payments under non-cancelable operating leases, 2019	11.9
Future lease payments under non-cancelable operating leases, 2020	9.8
Future lease payments under non-cancelable operating leases, thereafter	41.1
Other Liabilities and Credits
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Remedial action included in other credits	$ 1
MVP Joint Venture
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Firms capacity commitments per day (in Bcf per day) | Bcf / d	2
EQM
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Amount due as of the balance sheet date	$ 5,700
EQT | MVP Joint Venture
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Firms capacity commitments per day (in Bcf per day) | Bcf / d	1.29
OVC Pipeline
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Natural gas interstate pipeline (in miles) | mi		37
Term of agreement		20 years
Transmission capacity (in MMBtu per day) | MMBTU / d		650
Mountain Valley Pipeline
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Natural gas interstate pipeline (in miles) | mi	300
Natural gas interstate pipeline (in miles) | mi	300
Transmission firm capacity (in Bcf per day) | Bcf / d	2
period of firm capacity commitments	20 years
Pipeline Demand Charges
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Amount due as of the balance sheet date	$ 11,700
Amount due in 2016	314.2
Amount due in 2017	392.7
Amount due in 2018	447.6
Amount due in 2019	741.2
Amount due in 2020	736.1
Amount due thereafter	9,040.2
Drilling Equipment and Services
Commitments for demand charges under existing long-term contracts and binding precedent agreements with various pipelines
Amount due as of the balance sheet date	$ 63.2

Guarantees (Details)

Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 11, 2016
Initial guarantee	$ 108
Variable Interest Entity, Not Primary Beneficiary | Subsequent Event | MVP Joint Venture
Performance guarantee		$ 91
NORESCO Guarantees, Energy Savings
Undiscounted maximum aggregate payments related to guarantees	$ 134
Guarantee obligations term	12 years
Mountain Valley Pipeline | Variable Interest Entity, Not Primary Beneficiary | MVP Joint Venture
Percent of obligation to issue new guarantee	33.00%

Interim Financial Informatio110

Interim Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 601,380	$ 583,978	$ 439,589	$ 714,815	$ 703,194	$ 578,723	$ 526,168	$ 661,625	$ 2,339,762	$ 2,469,710	$ 1,862,011
Operating income	45,291	170,055	33,034	314,759	40,330	231,503	224,771	356,791	563,139	853,395	654,604
Net income (loss) attributable to EQT Corporation	(134,579)	40,787	5,536	173,427	(14,704)	98,555	110,921	192,193	85,171	386,965	390,572
Amounts attributable to EQT Corporation:
Net income (loss) attributable to EQT Corporation					(14,303)	98,555	109,045	192,297	85,171	385,594	298,729
(Loss) income from discontinued operations					(401)	0	1,876	(104)	0	1,371	91,843
Net income (loss) attributable to EQT Corporation	$ (134,579)	$ 40,787	$ 5,536	$ 173,427	$ (14,704)	$ 98,555	$ 110,921	$ 192,193	$ 85,171	$ 386,965	$ 390,572
Basic:
Income (loss) from continuing operations (in dollars per share)					$ (0.10)	$ 0.65	$ 0.72	$ 1.27	$ 0.56	$ 2.54	$ 1.98
Income from discontinued operations (in dollars per share)					0	0	0.01	0	0	0.01	0.61
Net income (in dollars per share)	$ (0.88)	$ 0.27	$ 0.04	$ 1.14	(0.10)	0.65	0.73	1.27	0.56	2.55	2.59
Diluted:
Income (loss) from continuing operations (in dollars per share)					(0.10)	0.65	0.72	1.26	0.56	2.53	1.97
Income from discontinued operations (in dollars per share)					0	0	0.01	0	0	0.01	0.60
Net income (in dollars per share)	$ (0.88)	$ 0.27	$ 0.04	$ 1.14	$ (0.10)	$ 0.65	$ 0.73	$ 1.26	$ 0.56	$ 2.54	$ 2.57

Natural Gas Producing Activi111

Natural Gas Producing Activities (Unaudited) - Costs Incurred Relating to Natural Gas, NGL, and Oil Production Activities (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs:
Proved properties		$ 10,918,499	$ 9,258,298	$ 7,702,724
Unproved properties		898,270	824,527	450,227
Total capitalized costs		11,816,769	10,082,825	8,152,951
Accumulated depreciation and depletion		3,425,618	2,693,535	2,134,953
Net capitalized costs		8,391,151	7,389,290	6,017,998
Property acquisition:
Proved properties		23,890	231,322	90,390
Unproved properties		158,405	493,067	95,861
Exploration		53,463	16,023	4,285
Development		$ 1,633,498	1,697,501	1,230,301
Chesapeake
Property acquisition:
Unproved properties	$ 57,200
Permian | Range Resources Corporation
Property acquisition:
Unproved properties			317,200
Proved properties, wells			198,200
Proved properties, leases			$ 1,100
Marcellus | Chesapeake
Property acquisition:
Proved properties	$ 57,000
Unproved properties				41,900
Proved properties, wells				57,000
Proved properties, leases				$ 15,300

Natural Gas Producing Activi112

Natural Gas Producing Activities (Unaudited) - Results of Operations Related to Natural Gas, NGL and Oil Production (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Production costs	$ 123,665	$ 133,488	$ 108,091
Exploration costs	61,970	21,716	18,483
Impairment of long-lived assets	122,469	267,339	0
EQT Production
Revenues:
Affiliated	1,412	4,761	5,912
Nonaffiliated	1,154,422	1,724,771	1,305,026
Production costs	398,044	334,050	250,372
Exploration costs	61,970	21,665	18,483
Depreciation, depletion and accretion	723,448	592,855	578,641
Impairment of long-lived assets	118,268	267,339	0
Income tax (benefit) expense	(58,603)	202,881	183,060
Results of operations from producing activities (excluding corporate overhead)	$ (87,293)	$ 310,742	$ 280,382

Natural Gas Producing Activi113

Natural Gas Producing Activities (Unaudited) - Reserve Information (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Bcfewell	Dec. 31, 2014USD ($)Bcfe	Dec. 31, 2013USD ($)Bcfelocation
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Unproved property impairments | $	$ 19,700	$ 86,600
Unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling | $	37,400	14,600	$ 14,200
Unproved properties | $	$ 898,270	$ 824,527	$ 450,227
Engineer experience (in years)	18 years
Percentage of total net natural gas, NGL and oil proved reserves reviewed	100.00%
Percentage of proved developed reserves covered in the audit	80.00%
Percentage of audit coverage of remaining properties	20.00%
Wells per case, operated wells | well	200
Wells per case, non-operated wells | well	230
Net (downward) upward revisions (in mcfe)	(2,195)	(301.4)	191.5
Undeveloped reserves removed (in mcfe)	2,168	1,047.2
Period undeveloped locations will not be drilled	5 years	5 years
Proved undeveloped reserve removed due to economic locations (in mcfe)	342
Additional downward revisions associated with previously booked locations with shortened lives due to reduction in commodity prices (in mcfe)	259
Increase in proved developed reserves due to improved performance of producing locations (in mcfe)	386	845.1
Increase in reserves of natural gas equivalents (in mcfe)	2,051	3,276.1	2,046.6
Production of natural gas equivalents (in mcfe)	619	488.1	367.1
Negative revisions in reserves due to removal of undeveloped locations and associated reserves (in mcfe)			349
Number of undeveloped locations and associated reserves that were removed | location			58
Decrease in lateral spacing | location			1

Natural Gas Producing Activi114

Natural Gas Producing Activities (Unaudited) - Schedule of the Entity's Proved and Unproved Reserves (Details)	12 Months Ended
	Dec. 31, 2015MMcfMBbls	Dec. 31, 2014MMcfMBbls	Dec. 31, 2013MMcfMBbls
Proved developed and undeveloped reserves:
Beginning of year	10,738,948	8,348,269	6,004,952
Revision of previous estimates	(2,194,675)	(301,351)	191,509
Purchase	0	102,713	472,798
Sale	(61)	(198,657)	(455)
Extensions, discoveries and other additions	2,051,071	3,276,054	2,046,578
Production	(618,686)	(488,080)	(367,113)
End of year	9,976,597	10,738,948	8,348,269
Proved developed reserves:
Beginning of year	4,826,387	3,985,687	2,798,381
End of year	6,279,557	4,826,387	3,985,687
Proved undeveloped reserves:
Beginning of year	5,912,561	4,362,582	3,206,571
End of year	3,697,040	5,912,561	4,362,582
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	9,775,954	7,561,561	5,985,758
Revision of previous estimates	(2,059,531)	(228,085)	(375,887)
Purchase	0	44,867	472,798
Sale	(61)	(198,531)	(455)
Extensions, discoveries and other additions	1,955,935	3,040,938	1,844,840
Production	(561,986)	(444,796)	(365,493)
End of year	9,110,311	9,775,954	7,561,561
Proved developed reserves:
Beginning of year	4,257,377	3,567,313	2,779,187
End of year	5,652,989	4,257,377	3,567,313
Proved undeveloped reserves:
Beginning of year	5,518,577	3,994,248	3,206,571
End of year	3,457,322	5,518,577	3,994,248
Cubic feet per thousand barrel (in mmcf)	6,000,000
Oil
Proved developed and undeveloped reserves:
Beginning of year | MBbls	5,005	3,956	3,199
Revision of previous estimates | MBbls	1,219	(905)	270
Purchase | MBbls	0	2,165	0
Sale | MBbls	0	(3)	0
Extensions, discoveries and other additions | MBbls	419	241	757
Production | MBbls	(743)	(449)	(270)
End of year | MBbls	5,900	5,005	3,956
Proved developed reserves:
Beginning of year | MBbls	5,005	3,892	3,199
End of year | MBbls	5,900	5,005	3,892
Proved undeveloped reserves:
Beginning of year | MBbls	0	64	0
End of year | MBbls	0	0	64
Cubic feet per thousand barrel (in mmcf)	0
Natural Gas Liquids
Proved developed and undeveloped reserves:
Beginning of year | MBbls	155,494	127,162	0
Revision of previous estimates | MBbls	(23,743)	(11,306)	94,296
Purchase | MBbls	0	7,476	0
Sale | MBbls	0	(18)	0
Extensions, discoveries and other additions | MBbls	15,437	38,945	32,866
Production | MBbls	(8,707)	(6,765)	0
End of year | MBbls	138,481	155,494	127,162
Proved developed reserves:
Beginning of year | MBbls	89,830	65,837	0
End of year | MBbls	98,528	89,830	65,837
Proved undeveloped reserves:
Beginning of year | MBbls	65,664	61,325	0
End of year | MBbls	39,953	65,664	61,325
Cubic feet per thousand barrel (in mmcf)	0

Natural Gas Producing Activi115

Natural Gas Producing Activities (Unaudited) - Standard Measure of Discounted Future Cash Flow (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl$ / Dekatherm	Dec. 31, 2014$ / bbl$ / Dekatherm	Dec. 31, 2013$ / bbl$ / Dekatherm
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discount rate to compute standard measure of future cash flow (as a percent)	10.00%
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas sensitivity (in usd per dth)	0.2
Discounted future net cash flows relating to proved oil and gas reserves, change in price of oil sensitivity (in usd per bbl) | $ / bbl	10
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas liquids (in usd per bbl) | $ / bbl	10
Change in discounted future cash flows for assumed natural gas price change | $	$ 788.6
Change in discounted future cash flows for assumed oil price change | $	26
Change in discounted future cash flows for assumed natural gas liquids price change | $	$ 533.8
West Texas Intermediate
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of reserves (in usd per bbl) | $ / bbl	50.28	94.99	89.22
Columbia Gas Transmission Corp.
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	2.506	4.278	3.653
Dominion Transmission, Inc.
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	1.394	3.191	3.447
East Tennessee Natural Gas Pipeline
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	2.552	4.350	3.693
Texas Eastern Transmission Corp
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	1.428	3.258	3.495
Tennessee Zone 4-300 Leg of Tennessee Gas Pipeline Company
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	1.079	2.286	2.842
Tennessee LA 500 Leg of Tennessee Gas Pipeline Company
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	2.430	4.170	3.521
Waha
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	2.473	4.152
Houston Ship Channel
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of oil and gas reserves (in usd per dth)	2.549	4.243
West Virginia Marcellus reserves
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of reserves (in usd per bbl) | $ / bbl	17.60	49.22	51.91
Kentucky
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of reserves (in usd per bbl) | $ / bbl	21.69	49.47	49.38
Utica
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of reserves (in usd per bbl) | $ / bbl	16.84	47.11	48.14
Permian
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price used in computation of reserves (in usd per bbl) | $ / bbl	17.51	31.92

Natural Gas Producing Activi116

Natural Gas Producing Activities (Unaudited) - Estimated Future Net Cash Flows from Natural Gas and Oil Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 10,071,465	$ 30,428,815	$ 25,912,542
Future production costs	(3,415,715)	(4,868,079)	(4,180,136)
Future development costs	(2,377,650)	(5,052,195)	(4,199,722)
Future income tax expenses	(1,333,989)	(7,718,407)	(6,533,817)
Future net cash flow	2,944,111	12,790,134	10,998,867
10% annual discount for estimated timing of cash flows	(1,966,557)	(7,980,106)	(7,047,588)
Standardized measure of discounted future net cash flows	$ 977,554	$ 4,810,028	$ 3,951,279	$ 2,155,159

Natural Gas Producing Activi117

Natural Gas Producing Activities (Unaudited) - Summary of Changes in the Standardized Measure of Discounted Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Sales and transfers of natural gas and oil produced – net	$ (757,789)	$ (1,479,242)	$ (1,060,566)
Net changes in prices, production and development costs	(5,566,232)	(1,525,944)	(292,533)
Extensions, discoveries and improved recovery, less related costs	264,735	2,300,923	1,509,002
Development costs incurred	971,186	1,023,075	1,319,135
Purchase of minerals in place – net	0	72,139	348,608
Sale of minerals in place – net	(43)	(146,476)	(252)
Revisions of previous quantity estimates	(1,541,419)	(222,195)	106,170
Accretion of discount	600,099	578,676	343,502
Net change in income taxes	2,424,200	(529,337)	(1,031,105)
Timing and other	(227,211)	787,130	554,159
Net (decrease) increase	(3,832,474)	858,749	1,796,120
Beginning of year	4,810,028	3,951,279	2,155,159
End of year	$ 977,554	$ 4,810,028	$ 3,951,279