EQT (EQT) 10-K 12 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document and Entity Information
Entity Registrant Name	EQT Corp
Entity Central Index Key	33213
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		151,602
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$14

STATEMENTS_OF_CONSOLIDATED_INC

STATEMENTS OF CONSOLIDATED INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement [Abstract]
Operating revenues	$2,469,710	$1,862,011	$1,377,222
Operating expenses:
Transportation and processing	202,203	148,708	134,951
Operation and maintenance	108,283	97,762	99,257
Production	133,488	108,091	96,155
Exploration	21,716	18,483	10,370
Selling, general and administrative	238,134	200,849	172,243
Depreciation, depletion and amortization	679,298	653,132	474,617
Impairment of long-lived assets	267,339	0	0
Total operating expenses	1,650,461	1,227,025	987,593
Gain on sale / exchange of assets	34,146	19,618	0
Operating income	853,395	654,604	389,629
Other income	6,853	9,242	15,536
Interest expense	136,537	142,688	184,786
Income before income taxes	723,711	521,158	220,379
Income taxes	214,092	175,186	71,461
Income from continuing operations	509,619	345,972	148,918
Income from discontinued operations, net of tax	1,371	91,843	47,493
Net income	510,990	437,815	196,411
Less: Net income attributable to noncontrolling interests	124,025	47,243	13,016
Net income	386,965	390,572	183,395
Amounts attributable to EQT Corporation:
Income from continuing operations	385,594	298,729	135,902
Income from discontinued operations	1,371	91,843	47,493
Net income	$386,965	$390,572	$183,395
Basic:
Income from continuing operations (in dollars per share)	$2.54	$1.98	$0.91
Income from discontinued operations (in dollars per share)	$0.01	$0.61	$0.32
Net income (in dollars per share)	$2.55	$2.59	$1.23
Diluted:
Income from continuing operations (in dollars per share)	$2.53	$1.97	$0.90
Income from discontinued operations (in dollars per share)	$0.01	$0.60	$0.32
Net income (in dollars per share)	$2.54	$2.57	$1.22

STATEMENTS_OF_CONSOLIDATED_COM

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income	$510,990	$437,815	$196,411
Net change in cash flow hedges:
Natural gas, net of tax expense (benefit) of $102,850, ($50,200) and ($61,757)	155,422	-76,489	-93,878
Interest rate, net of tax expense of $104, $63 and $4,833	145	144	6,369
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of ($515), $16,115 and ($1,992)	-776	21,501	-1,085
Other comprehensive income (loss)	154,791	-54,844	-88,594
Comprehensive income	665,781	382,971	107,817
Less: Comprehensive income attributable to noncontrolling interests	124,025	47,243	13,016
Comprehensive income attributable to EQT Corporation	$541,756	$335,728	$94,801

STATEMENTS_OF_CONSOLIDATED_COM1

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net change in cash flow hedges:
Natural gas, tax expense (benefit)	$102,850	($50,200)	($61,757)
Interest rate, tax expense	104	63	4,833
Pension and other post-retirement benefits liability adjustment, tax (benefit) expense	($515)	$16,115	($1,992)

STATEMENTS_OF_CONSOLIDATED_CAS

STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income	$510,990	$437,815	$196,411
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes	32,021	110,363	95,185
Depreciation, depletion and amortization	679,298	676,570	499,118
Impairment of long-lived assets and leases	281,979	14,198	5,543
Gain on sale / exchange of assets	-34,146	-19,618	0
Gain on dispositions included in discontinued operations	-2,898	-166,276	0
Provisions for (recoveries of) losses on accounts receivable	88	2,957	-1,235
Other income	-6,853	-9,508	-15,965
Stock-based compensation expense	42,123	52,618	40,230
(Gain) loss recognized in operating revenues for hedging ineffectiveness	-24,774	21,335	75
Gain on derivatives not designated as hedges	-80,942	-2,834	-2,176
Gain on derivatives not designated as hedges	34,239	1,115	7,508
Noncash financial instrument put premium	0	0	8,227
Changes in other assets and liabilities:
Dividend from Nora Gathering, LLC	9,463	9,000	12,750
Excess tax benefits on stock-based compensation	-33,216	-12,251	0
Accounts receivable and unbilled revenues	-70,392	-44,818	-48,364
Inventory	15,511	30,090	43,277
Accounts payable	30,350	15,990	20,624
Other items, net	31,901	46,115	-64,386
Net cash provided by operating activities	1,414,742	1,162,861	796,822
Cash flows from investing activities:
Capital expenditures from continuing operations, excluding acquisitions	-2,277,472	-1,612,501	-1,346,595
Capital expenditures for acquisitions	-174,184	-114,224	0
Capital expenditures from discontinued operations	0	-36,637	-28,745
Proceeds from sale of assets	7,444	740,587	4,842
Proceeds from sale of energy marketing contracts	0	23,000	0
Net cash used in investing activities	-2,444,212	-999,775	-1,370,498
Cash flows from financing activities:
Proceeds from the issuance of common units of EQT Midstream Partners, LP, net of issuance costs	902,467	529,442	276,780
Proceeds from issuance of EQT Midstream Partners, LP debt	500,000	0	0
Increase in short-term loans	450,000	178,500	0
Decrease in short-term loans	-450,000	-178,500	0
Dividends paid	-18,207	-18,094	-131,803
Distributions to noncontrolling interests	-67,819	-32,781	-5,031
Repayments and retirements of long-term debt	-11,162	-23,204	-219,315
Proceeds and excess tax benefits from exercises under employee compensation plans	52,373	45,137	7,871
Cash paid for taxes related to net settlement of share-based incentive awards	-51,262	0	0
Debt issuance costs and revolving credit facility origination fees	-12,764	0	-4,022
Repurchase and retirement of common stock	-32,368	0	0
Net cash provided by (used in) financing activities	1,261,258	500,500	-75,520
Net change in cash and cash equivalents	231,788	663,586	-649,196
Cash and cash equivalents at beginning of year	845,641	182,055	831,251
Cash and cash equivalents at end of year	1,077,429	845,641	182,055
Cash paid during the year for:
Interest, net of amount capitalized	128,567	143,187	187,884
Income taxes, net	$204,818	$163,703	$27,605

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,077,429	$845,641
Accounts receivable (less accumulated provision for doubtful accounts: $5,311 in 2014; $5,171 in 2013)	306,085	235,781
Inventory	4,145	19,656
Derivative instruments, at fair value	458,460	107,647
Prepaid expenses and other	58,204	46,700
Total current assets	1,904,323	1,255,425
Equity in nonconsolidated investments	0	128,983
Property, plant and equipment	13,608,151	11,062,136
Less: accumulated depreciation and depletion	3,531,337	2,728,374
Net property, plant and equipment	10,076,814	8,333,762
Other assets	83,763	73,883
Total assets	12,064,900	9,792,053
Current liabilities:
Current portion of long-term debt	166,011	11,162
Accounts payable	444,077	330,329
Derivative instruments, at fair value	22,942	29,651
Other current liabilities	200,449	152,268
Total current liabilities	833,479	523,410
Long-term debt	2,822,889	2,490,354
Deferred income taxes	1,750,870	1,655,765
Other liabilities and credits	284,599	258,396
Total liabilities	5,691,837	4,927,925
Stockholders’ equity
Common stock, no par value, authorized 320,000 shares, shares issued: 175,384 in 2014 and 175,684 in 2013	1,895,632	1,869,843
Treasury stock, shares at cost: 23,788 in 2014 and 24,800 in 2013	-429,440	-447,738
Retained earnings	2,917,129	2,567,980
Accumulated other comprehensive income	199,494	44,703
Total common stockholders’ equity	4,582,815	4,034,788
Noncontrolling interests in consolidated subsidiaries	1,790,248	829,340
Total equity	6,373,063	4,864,128
Total liabilities and equity	$12,064,900	$9,792,053

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Accounts receivable, accumulated provision for doubtful accounts (in dollars)	$5,311	$5,171
Common stock, par value (in dollars per share)	$0	$0
Common stock, authorized shares	320,000,000	320,000,000
Common stock, shares issued	175,384,000	175,684,000
Treasury stock, shares	23,788,000	24,800,000

STATEMENTS_OF_CONSOLIDATED_EQU

STATEMENTS OF CONSOLIDATED EQUITY (USD $)	Total	Common Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests in Consolidated Subsidiaries
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2011	$3,593,830	$1,261,779	$2,143,910	$188,141	$0
Beginning Balance (in shares) at Dec. 31, 2011		149,477,000
Increase (Decrease) in Stockholders' Equity
Net income	196,411		183,395		13,016
Net change in cash flow hedges:
Natural gas, net of tax (benefit) expense of $102,850, ($50,200), and ($61,757) during 2014, 2013 and 2012, respectively	-93,878			-93,878
Interest rate, net of tax expense of $104, $63, and $4,833 during 2014, 2013 and 2012, respectively	6,369			6,369
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of ($515), $16,115, and ($1,992) during 2014, 2013 and 2012, respectively	-1,085			-1,085
Dividends ($0.12, $0.12 and $0.88 per share during 2014, 2013 and 2012, respectively)	-131,803		-131,803
Stock-based compensation plans, net (in shares)		632,000
Stock-based compensation plans, net	41,838	41,621			217
Distributions to noncontrolling interests ($2.02, $1.55 and $0.35 per common unit during 2014, 2013 and 2012, respectively)	-5,031				-5,031
Issuance of common units of EQT Midstream Partners, LP	276,780				276,780
Deferred taxes related to the public offering of common units of EQT Midstream Partners, LP	5,371	5,371
Common stock, authorized shares	320,000,000
Preferred stock, authorized shares	3,000,000
Ending Balance at Dec. 31, 2012	3,888,802	1,308,771	2,195,502	99,547	284,982
Ending Balance (in shares) at Dec. 31, 2012		150,109,000
Increase (Decrease) in Stockholders' Equity
Net income	437,815		390,572		47,243
Net change in cash flow hedges:
Natural gas, net of tax (benefit) expense of $102,850, ($50,200), and ($61,757) during 2014, 2013 and 2012, respectively	-76,489			-76,489
Interest rate, net of tax expense of $104, $63, and $4,833 during 2014, 2013 and 2012, respectively	144			144
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of ($515), $16,115, and ($1,992) during 2014, 2013 and 2012, respectively	21,501			21,501
Dividends ($0.12, $0.12 and $0.88 per share during 2014, 2013 and 2012, respectively)	-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 ($2.02, $1.55 and $0.35 per common unit during 2014, 2013 and 2012, respectively)	-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
Common stock, authorized shares	320,000,000
Preferred stock, authorized shares	3,000,000
Ending Balance at Dec. 31, 2013	4,864,128	1,422,105	2,567,980	44,703	829,340
Ending Balance (in shares) at Dec. 31, 2013		150,884,000
Increase (Decrease) in Stockholders' Equity
Net income	510,990		386,965		124,025
Net change in cash flow hedges:
Natural gas, net of tax (benefit) expense of $102,850, ($50,200), and ($61,757) during 2014, 2013 and 2012, respectively	155,422			155,422
Interest rate, net of tax expense of $104, $63, and $4,833 during 2014, 2013 and 2012, respectively	145			145
Pension and other post-retirement benefits liability adjustment, net of tax (benefit) expense of ($515), $16,115, and ($1,992) during 2014, 2013 and 2012, respectively	-776			-776
Dividends ($0.12, $0.12 and $0.88 per share during 2014, 2013 and 2012, respectively)	-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 ($2.02, $1.55 and $0.35 per common unit during 2014, 2013 and 2012, respectively)	-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
Common stock, authorized shares	320,000,000
Preferred stock, authorized shares	3,000,000
Ending Balance at Dec. 31, 2014	$6,373,063	$1,466,192	$2,917,129	$199,494	$1,790,248
Ending Balance (in shares) at Dec. 31, 2014		151,596,000

STATEMENTS_OF_CONSOLIDATED_EQU1

STATEMENTS OF CONSOLIDATED EQUITY (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Natural gas, tax (benefit) (in dollars)	$102,850	($50,200)	($61,757)
Interest rate, tax (in dollars)	104	63	4,833
Pension and other post-retirement benefits liability adjustment, tax expense	($515)	$16,115	($1,992)
Dividends (in dollars per share)	$0.12	$0.12	$0.88
Distributions to noncontrolling interests (in dollars per common unit)	$2.02	$1.55	$0.35
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

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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. As of December 31, 2014, EQT owned a 2.0% general partner interest, all incentive distribution rights and a 34.4% limited partner interest in EQT Midstream Partners, LP (the Partnership) (NYSE: EQM). The Partnership is consolidated in EQT’s consolidated financial statements. EQT records the noncontrolling interest of the public limited partners in EQT’s 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, transportation, storage and marketing activities of the Company, including ownership and operation of the Partnership.
	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. Additionally, financial statements and notes to the financial statements previously reported in prior periods have been recast to reflect the presentation of discontinued operations as a result of the Equitable Gas Transaction. Refer to Note 2 for additional information on discontinued operations.
	Certain prior year amounts in the Statements of Consolidated Cash Flows have been revised to correctly present changes in accrued liabilities related to the timing of payments for capital expenditures. For the year ended December 31, 2013, net cash provided by operating activities decreased by approximately $37.5 million with a corresponding decrease in net cash used in investing activities as a result of this correction, and for the year ended December 31, 2012, net cash provided by operating activities decreased by $11.7 million with a corresponding decrease in net cash used in investing activities. The correction had no impact on the Statements of Consolidated Income or Consolidated Balance Sheets.
	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. For hedged inventory subject to fair value hedges, the Company adjusts the average cost for the change in natural gas spot prices from the date the inventory is hedged until settlement. These fair value adjustments become part of the average cost of the inventory. During the years ended December 31, 2014, 2013 and 2012, the Company recorded losses for lower of cost or market adjustments of $3.2 million, $0.4 million and $7.0 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,
		2014			2013
		(Thousands)
	Oil and gas producing properties, successful efforts method	$	10,263,547		$	8,152,951
	Accumulated depletion	(2,874,257		)	(2,134,953		)
	Net oil and gas producing properties	7,389,290			6,017,998
	Midstream plant	3,234,370			2,807,165
	Accumulated depreciation and amortization	(606,998		)	(547,991		)
	Net midstream plant	2,627,372			2,259,174
	Other properties, at cost less accumulated depreciation	60,152			56,590
	Net property, plant and equipment	$	10,076,814		$	8,333,762
	Oil and gas producing properties use the successful efforts method of accounting for production activities.  Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, 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 $108.5 million, $93.5 million and $72.1 million in 2014, 2013 and 2012, respectively.  The Company capitalized $35.0 million, $22.9 million and $15.6 million of interest relative to Marcellus and Utica well development in 2014, 2013 and 2012, 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 costs capitalized 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, 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 $1.22 per Mcfe, $1.50 per Mcfe and $1.52 per Mcfe produced for the years ended December 31, 2014, 2013 and 2012, respectively.
	The carrying values of the Company’s proved oil and gas properties are reviewed for indications of 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, in limited cases, risk-adjusted probable reserves, utilizing assumptions about the use of the asset, market prices for oil and gas and future operating costs.  Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows would be deemed to be unrecoverable.  Those properties would be written down to fair value, which would be estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.
	Due to the decline in commodity prices during 2014, there were indications that the carrying values of certain of the Company’s oil and gas producing properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon estimates of future production levels, commodity prices, drilling and operating costs and discount rates, as a result, valuation of the impaired assets was a Level 3 measurement. For the year ended December 31, 2014, the Company recognized pretax impairment charges on proved oil and gas properties of $180.7 million, which are included in the impairment of long-lived assets caption in the Statements of Consolidated Income. This impairment included charges of $105.2 million on proved properties in its Permian Basin of Texas primarily due to the decline in commodity prices and $75.5 million on proved properties in its Utica Shale of Ohio as a result of insufficient recovery of hydrocarbons to support continued development along with the decline in commodity prices. For the years ended December 31, 2013 and 2012, 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 year ended December 31, 2014, unproved property impairments relating to the determination that the properties will not yield proved reserves were $86.6 million and are included in the impairment of long-lived assets in the Statements of Consolidated Income. This impairment relates to the Company’s decision to stop development of properties in its Utica Shale of Ohio described above. In addition, unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling of $14.6 million, $14.2 million and $5.5 million are included in exploration expense for the years ended December 31, 2014, 2013 and 2012, respectively. Unproved properties had a net book value of $824.5 million and $450.2 million at December 31, 2014 and 2013, respectively.
	At December 31, 2014, the Company had $9.0 million of capitalized exploratory well costs, there were no capitalized exploratory wells costs at December 31, 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). The Company capitalized internal costs of $40.0 million, $32.5 million and $27.2 million in 2014, 2013 and 2012, respectively.
	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. No impairment of any long-lived asset other than proved and unproved oil and gas properties was recorded in 2014, 2013 and 2012.
	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 consist of 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,
		2014			2013			2012
		(Thousands)
	Net Revenues	$	267,997		$	184,767		$	131,184
	Operating expenses	$	89,617		$	71,517		$	66,202
	The following table presents the regulated net property, plant and equipment included in EQT Midstream:
		As of December 31,
		2014			2013
		(Thousands)
	Property, plant & equipment	$	1,160,696		$	1,015,118
	Accumulated depreciation and amortization	(188,884		)	(158,533		)
	Net property, plant & equipment	$	971,812		$	856,585
	The regulatory assets associated with deferred taxes of $15.2 million and $13.3 million as of December 31, 2014 and 2013, 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 the allowance for funds used during the construction 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 & Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Board of Directors. The HFRC is composed of the president and chief executive officer, 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 may also use 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 remains 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.
	Effective October 1, 2013, the Company de-designated all derivative commodity instruments that were previously designated and qualified as fair value hedges. For a derivative instrument that had been designated and qualified as a fair value hedge, the change in the fair value for the instrument was recognized as a portion of operating revenues in the Statements of Consolidated Income each period. In addition, the change in the fair value of the hedged item (natural gas inventory) was recognized as a portion of operating revenues in the Statements of Consolidated Income. The Company elected to exclude the spot/forward differential from the assessment of effectiveness of the fair value 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.
	Allowance for Funds Used During Construction:   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 $5.8 million, $4.3 million and $3.9 million for the years ended December 31, 2014, 2013 and 2012, 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 $3.2 million, $1.2 million and $6.8 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Other Current Liabilities:  Other current liabilities as of December 31, 2014 and 2013 are detailed below.
		December 31,
		2014			2013
		(Thousands)
	Incentive compensation	$	70,826		$	65,053
	Taxes other than income	52,035			39,073
	Accrued interest payable	37,349			29,379
All other accrued liabilities	40,239			18,763
Total other current liabilities	$	200,449		$	152,268
Revenue Recognition:  Revenue is recognized for production and gathering activities when deliveries of natural gas, NGLs and crude oil occur. Revenues from natural gas transportation 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 income statement, 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:  EQT owns a 2.0% general partner interest, all incentive distribution rights and a 34.4% limited partner interest in the Partnership. The Partnership is consolidated in EQT’s consolidated financial statements because EQT controls the Partnership through its ownership of the general partner and the rights provided to the general partner under the Partnership’s partnership agreement. EQT records the noncontrolling interest of the public limited partners in EQT’s financial statements. 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.  These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets.
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. Some transportation costs incurred by the Company are marketed for resale and 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 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 credit worthiness 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.  Accordingly, actual results may differ from these estimates under different assumptions or conditions.
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 15.
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,
	2014			2013
	(Thousands)
Asset retirement obligation as of beginning of period	$	116,045		$	109,034
Accretion expense	9,420			8,342
Liabilities incurred	16,953			2,510
Liabilities settled	(14,025		)	(3,353		)
Revisions in estimated cash flows	11,693			(488		)
Asset retirement obligation as of end of period	$	140,086		$	116,045
In connection with the exchange of certain assets with Range Resources Corporation (Range) (see Notes 7 and 9 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,
	2014			2013
	(Thousands)
Net gain from natural gas hedging transactions	$	217,121		$	61,699
Net loss from interest rate swaps	(987		)	(1,132		)
Pension and other post-retirement benefits liability adjustment	(16,640		)	(15,864		)
Accumulated OCI	$	199,494		$	44,703
Noncontrolling interests: Noncontrolling interests represent third-party equity ownership in the Partnership 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, which for the Partnership gives effect to the incentive distribution rights declared for each period. See Note 3 for further discussion of noncontrolling interests related to the Partnership.
Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board 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 replace most of the existing revenue recognition requirements in United States GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.
Subsequent Events: The Company has evaluated subsequent events through the date of the financial statement issuance.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations
	On December 17, 2013, the Company and its 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. Prior periods have been recast to reflect this presentation.
	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,
		2014		2013		2012
		(Thousands)
	Operating revenues	$	—	$	332,947	$	314,821
	Income from discontinued operations before income taxes	2,377		251,378		81,328
	Income taxes	1,006		159,535		33,835
	Income from discontinued operations, net of tax	$	1,371	$	91,843	$	47,493
	The Company incurred $8.1 million and $4.5 million of transaction costs related to the Equitable Gas Transaction for the year ended December 31, 2013 and 2012, respectively, 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_Midstream_Partners_LP

EQT Midstream Partners, LP	12 Months Ended
	Dec. 31, 2014
EQT Midstream Partners, LP
EQT Midstream Partners, LP	EQT Midstream Partners, LP
	On July 2, 2012, the Partnership, a subsidiary of the Company, completed an underwritten initial public offering (IPO) of 14,375,000 common units representing limited partner interests in the Partnership, which represented 40.6% of the Partnership’s outstanding equity. The Company retained a 59.4% equity interest in the Partnership, including 2,964,718 common units, 17,339,718 subordinated units and a 2% general partner interest. Prior to the IPO, the Company contributed to the Partnership 100% of Equitrans, L.P. (Equitrans).  A wholly owned subsidiary of the Company serves as the general partner of the Partnership, and the Company continues to operate the Equitrans business pursuant to certain contractual arrangements established in connection with the IPO.  The Company continues to consolidate the results of the Partnership but records an income tax provision only as to its ownership percentage.  The Company records the noncontrolling interest of the public limited partners in its financial statements.
	On July 22, 2013, Sunrise, a subsidiary of the Company, merged with and into Equitrans, a subsidiary of the Partnership, with Equitrans continuing as the surviving company (the Sunrise Merger). Equitrans is consolidated by the Company as it is still controlled by the Company.
	On July 22, 2013, the Partnership completed an underwritten public offering of 12,650,000 common units representing Partnership limited partner interests. Following the offering and the closing of the Sunrise Merger, the Company retained a 44.6% equity interest in the Partnership, which included 3,443,902 common units, 17,339,718 subordinated units and a 2% general partner interest. The Partnership received net proceeds of $529.4 million from the offering, after deducting the underwriters’ discount and offering expenses of $20.9 million.
	On May 7, 2014, EQT Gathering, LLC, a wholly owned subsidiary of the Company, EQT Gathering contributed a high-pressure gathering system to EQM Gathering, a wholly owned subsidiary of the Partnership, in exchange for $1.18 billion (the Jupiter Transaction). EQM Gathering is consolidated by the Company as it is still controlled by the Company.
	On May 7, 2014, the Partnership completed an underwritten public offering of 12,362,500 common units, which included the full exercise of the underwriters’ overallotment option, representing Partnership limited partner interests. The Partnership received net proceeds of approximately $902.5 million from the offering, after deducting the underwriters’ discount and offering expenses of approximately $34.0 million. As of December 31, 2014, the Company held a 2% general partner interest, all incentive distribution rights and a 34.4% limited partner interest in the Partnership. The Company’s limited partner interest in the Partnership consists of 3,959,952 common units and 17,339,718 subordinated units.
	In August 2014, the Partnership issued 4.00% Senior Notes due 2024 (4.00% Senior Notes) in the aggregate principal amount of $500.0 million. Net proceeds of the offering of $492.3 million, after deducting a discount of $2.9 million and debt issuance costs of $4.8 million, were used to repay all of the outstanding borrowings under the Partnership’s credit facility and for general partnership purposes. The indenture governing the 4.00% Senior Notes contains covenants that limit the Partnership’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 the Partnership’s assets. The payment obligations under the 4.00% Senior Notes were unconditionally guaranteed by each of the Partnership’s subsidiaries that guaranteed the Partnership’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 the Partnership’s credit facility.
	On January 22, 2015, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders for the fourth quarter of 2014 of $0.58 per common and subordinated unit, $0.8 million to the general partner related to its 2% general partner interest and $5.2 million to the general partner related to its incentive distribution rights. The cash distribution will be paid on February 13, 2015 to unitholders of record at the close of business on February 3, 2015. As a result of this cash distribution, the subordination period with respect to the Partnership’s 17,339,718 subordinated units will expire on February 17, 2015 and all outstanding Partnership subordinated units will convert into Partnership common units on a one-for-one basis on that day.
	Net income attributable to noncontrolling interests (i.e. the limited partner units not owned by the Company) was $124.0 million, $47.2 million and $13.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.  The Partnership paid distributions of $67.8 million ($2.02 per common unit), $32.8 million ($1.55 per common unit) and $5.0 million ($0.35 per common unit) to noncontrolling interests for the years ended December 31, 2014, 2013 and 2012, respectively.

Financial_Information_by_Busin

Financial Information by Business Segment	12 Months Ended
	Dec. 31, 2014
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, natural gas liquids (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, transportation, storage and marketing activities of the Company, including ownership and operation of the Partnership.
	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.
	The Company’s management reviews and reports the EQT Production segment results with third-party transportation and processing costs reflected as a deduction from operating revenues. 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. Some transportation costs incurred by the Company are marketed for resale and are not incurred to transport gas produced by EQT Production. These transportation costs are reflected as a deduction from operating revenues.
	Substantially all of the Company’s operating revenues, income from operations and assets are generated or located in United States.
		Years Ended December 31,
		2014			2013			2012
					(Thousands)
	Revenues from external customers:
	EQT Production	$	1,612,730		$	1,168,657		$	793,773
	EQT Midstream	699,083			614,042			505,498
	Third-party transportation and processing costs (a)	200,562			142,281			126,783
	Less intersegment revenues, net (b)	(42,665		)	(62,969		)	(48,832		)
	Total	$	2,469,710		$	1,862,011		$	1,377,222
	EQT Production (c)	$	505,950		$	371,245		$	187,913
	EQT Midstream (c)	384,309			328,782			237,324
	Unallocated expenses (d)	(36,864		)	(45,423		)	(35,608		)
	Total operating income	$	853,395		$	654,604		$	389,629
	Reconciliation of operating income to income from continuing operations:
	Other income	$	6,853		$	9,242		$	15,536
	Interest expense	136,537			142,688			184,786
	Income taxes	214,092			175,186			71,461
	Income from continuing operations	$	509,619		$	345,972		$	148,918
		As of December 31,
		2014			2013
		(Thousands)
	Segment assets:
	EQT Production	$	8,153,199		$	6,359,065
	EQT Midstream	2,709,052			2,514,429
	Total operating segments	10,862,251			8,873,494
	Headquarters assets, including cash and short-term investments	1,202,649			918,559
	Total assets	$	12,064,900		$	9,792,053
	EQT Production and EQT Midstream had segment assets of $5,675.5 million and $2,046.6 million, respectively, as of December 31, 2012.
	(a)   This amount reflects the reclassification of third-party transportation and processing costs from operating revenues to transportation and processing costs at the consolidated level.
	(b)   Includes entries to eliminate intercompany natural gas sales from EQT Production to EQT Midstream. The Company also had $37.6 million and $36.8 million for the years ended December 31, 2013 and 2012, respectively, of intercompany eliminations for transmission and storage services between EQT Midstream and Distribution that have been recast to discontinued operations as a result of the Equitable Gas Transaction. Additionally, the Company had $2.6 million and $11.7 million for the years ended December 31, 2013 and 2012, respectively, of intercompany eliminations for retail business activity between Distribution and EQT Midstream that have been recast to discontinued operations. These recast adjustments had no impact on the Company’s net income for any period.
	(c)   Gain on sale / exchange of assets of $6.8 million and $19.6 million are included in EQT Midstream operating income for 2014 and 2013, respectively.  Gain on sale / exchange of assets of $27.4 million are included in EQT Production operating income for 2014. See Note 7. Impairment of long-lived assets of $267.3 million are included in EQT Production operating income for 2014. See Note 1.
	(d)  Unallocated expenses consist primarily of a $20.0 million contribution to the EQT Foundation in 2014, incentive compensation, administrative costs and in 2013 and 2012, corporate overhead charges previously allocated to the Distribution segment that were reclassified to Headquarters as part of the recast of those periods to reflect the discontinued operations presentation requirements.
		Years Ended December 31,
		2014			2013			2012
					(Thousands)
	Depreciation, depletion and amortization:
	EQT Production	$	592,855		$	578,641		$	409,628
	EQT Midstream	87,034			75,032			64,782
	Other	(591		)	(541		)	207
	Total	$	679,298		$	653,132		$	474,617
	Expenditures for segment assets: (e)
	EQT Production (f)	$	2,441,486		$	1,423,185		$	991,775
	EQT Midstream	455,359			369,399			375,731
	Other	3,341			4,292			3,134
	Total	$	2,900,186		$	1,796,876		$	1,370,640
	(e) Includes non-cash capital expenditures of $99.3 million, $70.2 million and $24.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, for certain labor overhead costs including a portion of non-cash stock-based compensation expense and non-cash capital expense accruals that had not yet been paid at the respective year-end.
	(f)   Expenditures for segment assets in the EQT Production segment include $724.4 million, $186.2 million and $134.6 million for property acquisitions in 2014, 2013 and 2012, respectively.  Included within the $724.4 million of property acquisitions for the year ended December 31, 2014 is $349.2 million of non-cash capital expenditures for the exchange of assets with Range Resources Corporation (described in Note 7).

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
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 and the creditworthiness of these institutions 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. During 2014, the Company granted 50,000 dth per day of calendar 2016 swaptions to counterparties in exchange for calendar 2015 collars with premium pricing. Swaption contracts grant the counterparty the option to enter into a fixed price swap agreement with the Company at a future date. Each 2016 swaption and associated 2015 collar was executed contemporaneously with a single counterparty and no cash was exchanged at the inception of the contracts.
	The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. These assets and liabilities are reported in the Consolidated Balance Sheets as derivative instruments at fair value. 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 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 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. On December 31, 2013, the Company sold certain energy marketing contracts and de-designated related derivative instruments that were previously designated as cash flow hedges because it was probable that the forecasted transactions would not occur, resulting in a $1.0 million pre-tax gain in operating revenues within the Statements of Consolidated Income for the year ended December 31, 2013. In conjunction with the exchange of assets with Range Resources Corporation (see Note 7), 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 with 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 hedging instruments that have been de-designated 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, 2014 and 2013, the Company deferred net gains of $217.1 million and $61.7 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, 2014, the forecasted transactions remain 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 Company estimates that approximately $153.2 million of net gains on its derivative commodity instruments reflected in accumulated OCI, net of tax, as of December 31, 2014 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, all future changes in fair value of the Company’s derivative instruments will be recognized in the Statements of Consolidated Income each future period.
	Historically, some of the derivative commodity instruments used by the Company to hedge its exposure to adverse changes in the market price of natural gas stored in the ground were designated and qualified as fair value hedges. These positions were de-designated effective October 1, 2013. Any hedging ineffectiveness and any change in fair value of derivative instruments that have not been designated as hedges are recognized in the Statements of Consolidated Income each period.
	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,
		2014			2013			2012
					(Thousands)
	Commodity derivatives designated as cash flow hedges
	Amount of gain recognized in OCI (effective portion), net of tax	$	156,207		$	10,669		$	86,259
	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 (loss) gain reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	(15,950		)	87,158			180,137
	Amount of gain (loss) recognized in operating revenues (ineffective portion) (a)	24,774			(21,335		)	(75		)
	Interest rate derivatives designated as cash flow hedges
	Amount of loss recognized in OCI (effective portion), net of tax	$	—		$	—		$	(7,138	)
	Amount of loss reclassified from accumulated OCI, net of tax, into interest expense due to forecasted transactions no longer being probable	—			—			(13,266		)
	Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	(145		)	(144		)	(241		)
	Commodity derivatives designated as fair value hedges (b)
	Amount of (loss) gain recognized in operating revenues for fair value commodity contracts	$	—		$	(1,341	)	$	3,878
	Fair value gain recognized in operating revenues for inventory designated as hedged item	—			386			3,292
	Derivatives not designated as hedging instruments
	Amount of gain recognized in operating revenues	$	80,942		$	2,834		$	2,176
	(a)         No amounts have been 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. For the year ended December 31, 2012, the net impact on operating revenues consisted of a $7.6 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.4 million loss due to changes in basis.
		As of December 31,
		2014			2013
		(Thousands)
	Asset derivatives
	Commodity derivatives designated as hedging instruments	$	—		$	104,430
	Commodity derivatives not designated as hedging instruments	458,460			3,217
	Total asset derivatives	$	458,460		$	107,647
	Liability derivatives
	Commodity derivatives designated as hedging instruments	$	—		$	27,618
	Commodity derivatives not designated as hedging instruments	22,942			2,033
	Total liability derivatives	$	22,942		$	29,651
	During 2012, the Company deferred $7.1 million in accumulated OCI, net of tax, related to a forward-starting interest rate swap which settled in November 2012.  As of December 31, 2012, the related forecasted debt issuance was no longer probable and the entire liability related to this swap of $23.3 million, pre-tax, was recognized in interest expense in the Statements of Consolidated Income.  This resulted in the reversal of $13.3 million which had previously been deferred in accumulated OCI, net of tax.  The forecasted debt issuance was no longer probable given the Company’s strong liquidity position at December 31, 2012.
	The net fair value of derivative commodity instruments changed during 2014 primarily as a result of decreased New York Mercantile Exchange (NYMEX) forward prices and new derivative commodity instruments executed during the year.  The absolute quantities of the Company’s derivative commodity instruments totaled 624 Bcf and 414 Bcf as of December 31, 2014 and 2013, respectively, and are primarily related to natural gas swaps, basis swaps and collars. The open positions at December 31, 2014 had maturities extending through December 2018.
	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 futures contracts have limited credit risk because Commodity Future Trading Commission (CFTC) regulations are in place to protect exchange participants, including the Company, from potential financial instability of the exchange members.  The Company’s OTC derivative instruments are primarily placed 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 closely 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.
	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 financial institution acting as counterparty, the counterparty requires the Company to remit funds to the counterparty 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 financial institution acting as 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, 2014 or December 31, 2013.
	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 recorded current assets of $0.1 million and $0.3 million as of December 31, 2014 and December 31, 2013, respectively, for such deposits in its Consolidated Balance Sheets.
	The Company recognizes all derivative instruments as either assets or liabilities at fair value on a gross basis. Margin deposits remitted to financial counterparties or received from financial counterparties related to OTC natural gas swap agreements and options and any funds remitted to or deposits received from the Company’s brokers are recorded on a gross basis.  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, 2014 and 2013.
	As of December 31, 2014	Derivative			Derivative			Margin			Derivative
		instruments,			instruments			deposits			instruments,
		recorded in the			subject to			remitted to			net
		Consolidated			master			counterparties
		Balance			netting
		Sheet, gross			agreements
		(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	)	$	—
	As of December 31, 2013	Derivative			Derivative			Margin			Derivative
		instruments,			instruments			deposits			instruments,
		recorded in the			subject to			remitted to			net
		Consolidated			master			counterparties
		Balance			netting
		Sheet, gross			agreements
		(Thousands)
Asset derivatives:
Derivative instruments, at fair value	$	107,647		$	(20,843	)	$	—		$	86,804
Liability derivatives:
Derivative instruments, at fair value	$	29,651		$	(20,843	)	$	(266	)	$	8,542
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, 2014, the aggregate fair value of all derivative instruments with credit risk-related contingent features that were in a net liability position was $0.9 million, for which the Company had no collateral posted on December 31, 2014.  If the Company’s credit rating by S&P or Moody’s had been downgraded below investment grade on December 31, 2014, the Company would have been required to post $0.9 million of 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, 2014.  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.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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 as inputs market-based parameters, including but not limited to 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. As of December 31, 2013, the Company transferred $54.4 million of derivative instruments from Level 3 into Level 2.
	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 NYMEX forward curves, LIBOR-based discount rates and basis forward curves. The Company’s collars and swaptions are valued using standard industry income approach option models. The Company’s collars were historically classified in Level 3 because the volatility assumption in the option pricing model was not observable over the full duration of the collars. Effective December 31, 2013, the volatility assumption in the option pricing model was, and at December 31, 2014 continued to be, observable for the duration of the term of the collars outstanding. This change did not have a significant impact on the fair value of the derivative instruments previously included in Level 3. 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, collars and swaptions. 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	31-Dec-14		Quoted			Significant		Significant
				prices in			other		unobservable
				active			observable		inputs
				markets for			inputs		(Level 3)
				identical			(Level 2)
				assets
				(Level 1)
		(Thousands)
	Assets
	Derivative instruments, at fair value	$	458,460	$	—		$	458,460	$	—
	Liabilities
	Derivative instruments, at fair value	$	22,942	$	132		$	22,810	$	—
				Fair value measurements at reporting date using
	Description	31-Dec-13		Quoted			Significant		Significant
				prices in			other		unobservable
				active			observable		inputs
				markets for			inputs		(Level 3)
				identical			(Level 2)
				assets
				(Level 1)
		(Thousands)
	Assets
	Derivative instruments, at fair value	$	107,647	$	240		$	107,407	$	—
	Liabilities
	Derivative instruments, at fair value	$	29,651	$	315		$	29,336	$	—
		Fair value measurements using significant
		unobservable inputs
		(Level 3)
		Derivative instruments, at fair value, net
		Years Ended December 31,
		2014		2013
		(Thousands)
	Balance at January 1	$	—	$	90,714
	Total gains or losses:
	Included in earnings	—		640
	Included in OCI	—		(2,554		)
	Purchases	—		—
	Settlements	—		(34,381		)
	Transfers in and/or out of Level 3	—		(54,419		)
	Balance at December 31	$	—	$	—
	There were no gains or losses included in earnings for the periods in the table above attributable to the changes in unrealized gains or losses relating to assets and liabilities held as of December 31, 2013.
	The carrying value of cash equivalents approximates fair value due to the short-term maturity of the instruments; these are considered Level 1 fair values.
	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 long-term debt (including the Partnership’s long-term debt) on the Consolidated Balance Sheets at December 31, 2014 and 2013 was approximately $3.3 billion and $2.8 billion, respectively.
	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. These assets are Level 2 fair value measurements as they were valued using standard industry income approach models.
	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 Resources exchange, the assets acquired in the Chesapeake acquisition and the assets related to the defined benefit pension plan assets, see Notes 1, 7, 8 and Note 13, respectively.

Sales_of_Properties_and_Contra

Sales of Properties and Contracts	12 Months Ended
	Dec. 31, 2014
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; the remaining $2.0 million was received 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 remaining 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 accounted for its previous 50% ownership interest in Nora LLC under the equity method, and this investment was reflected within equity in nonconsolidated investments in the Company’s Consolidated Balance Sheet.
	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 includes 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, 2014
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, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	Income tax expense (benefit) from continuing operations is summarized as follows:
		Years Ended December 31,
		2014			2013			2012
		(Thousands)
	Current:
	Federal	$	164,935		$	100,796		$	3,771
	State	17,136			46,758			229
	Subtotal	182,071			147,554			4,000
	Deferred:
	Federal	38,357			51,767			56,551
	State	(6,336		)	(23,940		)	11,014
	Subtotal	32,021			27,827			67,565
	Amortization of deferred investment tax credit	—			(195		)	(104		)
	Total income taxes	$	214,092		$	175,186		$	71,461
	The current federal income tax expense recorded in 2014 primarily related to federal alternative minimum tax (AMT) as a result of the tax gains generated from the Jupiter Transaction. The current state income tax expense recorded in 2014 primarily related to a Pennsylvania filing. The current income tax expense recorded in 2013 primarily related to AMT and state income taxes as a result of the tax gains generated from the Sunrise Merger as well as the Equitable Gas Transaction.  The current income tax expense recorded in 2012 primarily related to AMT as a result of the tax gain generated from the Partnership’s IPO.
	The Tax Increase Prevention Act of 2014 was enacted on December 19, 2014 and retroactively extended the research and experimentation (R&E) tax credit for 2014 and reinstated 50% bonus depreciation for property placed in service in 2014. The impact of this law change has 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 NOLs for federal tax purposes in 2014 and 2013, given the increase in current taxable income. The Company generated NOLs for federal tax purposes from 2009 to 2012, primarily as a result of intangible drilling costs (IDCs), which are deducted for tax purposes but capitalized for financial statement purposes, and from accelerated and bonus tax depreciation associated with the expansion of the Company’s midstream business.  For federal income tax purposes, the Company deducts a portion of drilling costs as IDCs in the year incurred which typically will cause the Company to generate a tax loss for the year.  The Company expects to continue to generate tax losses over the next several years as it continues its drilling program in Appalachia, excluding taxable gains which may be recorded from potential future asset sales.  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 differs from amounts computed at the federal statutory rate of 35% on pre-tax income as follows:
		Years Ended December 31,
		2014			2013			2012
		(Thousands)
	Tax at statutory rate	$	253,299		$	182,406		$	77,133
	State income taxes	7,020			16,180			2,869
	Noncontrolling partners’ share of Partnership earnings	(43,409		)	(16,535		)	(4,571		)
	Other	(2,818		)	(6,865		)	(3,970		)
	Income tax expense	$	214,092		$	175,186		$	71,461
	Effective tax rate	29.6		%	33.6		%	32.4		%
	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 Partnership earnings and the noncontrolling public limited partners’ share of Partnership earnings as a result of the Sunrise Merger and Jupiter Transaction. The Company consolidates 100% of the pre-tax income related to the noncontrolling public limited partners’ share of Partnership earnings but is not required to record an income tax provision with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners.
	The Company’s effective tax rate for the year ended December 31, 2013 was 33.6% compared to 32.4% for the year ended December 31, 2012.  The increase in the rate from 2012 to 2013 was primarily due to an increase in pre-tax book income on state tax paying entities as well as a shift in the Company’s business to states with higher income tax rates. This was partially offset by state tax benefits of $9.8 million realized in 2013 primarily related to the Sunrise Merger and the Equitable Gas Transaction which allowed the Company to utilize NOLs that had previously been fully reserved. As described in the preceding paragraph, the overall rate was reduced in both periods because the Company is not required to record an income tax provision with respect to the portion of the Partnership’s earnings allocated to its noncontrolling public limited partners.
	The following table reconciles the beginning and ending amount of reserve for uncertain tax positions (excluding interest and penalties):
		2014			2013			2012
		(Thousands)
	Balance at January 1	$	57,087		$	17,858		$	30,730
	Additions based on tax positions related to current year	1,195			49,289			2,165
	Additions for tax positions of prior years	93			—			2,320
	Settlements	—			—			—
	Reductions for tax positions of prior years	(1,418		)	(790		)	(12,235		)
	Lapse of statute of limitations	—			(9,270		)	(5,122		)
	Balance at December 31	$	56,957		$	57,087		$	17,858
	Included in the tabular reconciliation above at December 31, 2014, 2013 and 2012 are $6.9 million, $7.6 million and $6.4 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.  Additionally, there are uncertain tax positions of $10.1 million and $9.8 million for the years ended December 31, 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 NOLs and R&E tax credit carryforwards.
	The Company recognizes interest and penalties related to unrecognized tax benefits in income tax expense.  The Company recorded approximately $1.9 million for 2014, and reversed $0.4 million and $1.8 million of previously recorded interest expense in 2013 and 2012, respectively.  Interest and penalties of $2.0 million, $0.2 million and $0.5 million were included in the balance sheet reserve at December 31, 2014, 2013 and 2012, respectively.
	There were no material changes to the Company’s methodology for unrecognized tax benefits during 2014. The total amount of unrecognized tax benefits (excluding interest and penalties) that, if recognized, would affect the effective tax rate was $33.9 million, $33.3 million and $5.3 million as of December 31, 2014, 2013 and 2012, respectively.
	As of December 31, 2014, 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 Internal Revenue Service (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, which is the only item that remains open for those tax years. The Company also is the subject of various state income tax examinations. With few exceptions, as of December 31, 2014, the Company is no longer subject to state examinations by tax authorities for years before 2011.
	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,
		2014			2013
		(Thousands)
	Deferred income taxes:
	Total deferred income tax assets .	$	(961,556	)	$	(612,705	)
	Total deferred income tax liabilities	2,690,492			2,237,465
	Total net deferred income tax liabilities	1,728,936			1,624,760
	Total deferred income tax liabilities (assets)
	Drilling and development costs expensed for income tax reporting	1,391,156			1,190,357
	Tax depreciation in excess of book depreciation	1,154,082			1,018,255
	Accumulated OCI	130,770			28,597
	Post-retirement benefits	3,146			256
	Incentive compensation	(65,086		)	(60,863		)
	Net operating loss carryforwards	(212,718		)	(358,964		)
	Investment in Partnership	(336,394		)	(2,801		)
	Alternative minimum tax credit carryforward	(412,345		)	(246,157		)
Other	11,338			(324		)
Total excluding valuation allowances	1,663,949			1,568,356
Valuation allowance	64,987			56,404
Total (including amounts classified as current assets of $21,934 and $31,005, respectively)	$	1,728,936		$	1,624,760
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 net deferred tax liability relating to the Company’s accumulated OCI balance as of December 31, 2013 consisted of an $38.7 million deferred tax liability related to the Company’s net unrealized gain from hedging transactions, a $5.3 million deferred tax asset related to other post-retirement benefits, and a $4.8 million deferred tax asset related to the Company’s pension plans.
The Company also has a total deferred tax asset of $30.8 million at December 31, 2014 related to the federal NOL carryforward from 2013 of $1.1 million and 2012 of $29.7 million, respectively.  The deferred tax asset has been increased for uncertain tax positions of approximately $11.7 million and $10.6 million as of December 31, 2014 and 2013, respectively. The Company has federal income tax NOL carryforwards of $88.0 million. The federal NOL carryforward period is 20 years and, if unused, the loss carryforward, in excess of the 2014 NOL utilization, for 2013 and 2012 will expire in 2033 and 2032, respectively.
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, 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.  As of December 31, 2013, the Company had a deferred tax asset of $118.2 million, net of valuation allowances of $56.4 million, related to tax benefits from state NOL carryforwards with various expiration dates ranging from 2014 to 2033.  The deferred tax asset has been reduced for uncertain tax positions of approximately $0.3 million and $0.3 million during the years ended December 31, 2014 and 2013, respectively.
During the year ended December 31, 2012, share-based payment arrangements paid in stock generated an $8.1 million excess tax benefit that was not recorded in the Company’s financial statements as an addition to common stockholders’ equity due to the Company’s NOL position. The tax benefits had not previously been recorded related to this item as the Company could not realize a reduction in income taxes payable given the NOL. Due to taxable income generated in the year ended December 31, 2014, and the corresponding ability to realize a benefit from these amounts, the Company has recorded tax benefits of $26.6 million in the financial statements as an addition to common stockholders’ equity as these tax benefits reduced taxes payable in the current year. The Company also recorded tax benefits of $6.6 million for the 2011 excess tax benefits previously not recorded since the Company fully utilized the 2011 net operating loss during 2014. The Company uses tax law ordering when determining when excess tax benefits have been realized.

Equity_in_Nonconsolidated_Inve

Equity in Nonconsolidated Investments	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity in Nonconsolidated Investments	Equity in Nonconsolidated Investments
	Prior to the asset exchange with Range during 2014, the Company had ownership interests in a nonconsolidated investment that was accounted for under the equity method of accounting.  The following table summarizes the Company’s equity in the nonconsolidated investment:
				Interest	Ownership as of		As of December 31,
	Investees	Location		Type	December 31, 2014		2014				2013
							(Thousands)
	Nora Gathering, LLC (Nora LLC)	USA		Joint	—		$	—			$	128,983
	EQT Midstream’s equity investment in Nora LLC represented a 50% ownership interest. EQT Midstream made no additional equity investments in Nora LLC during 2014 or 2013.
	In connection with the asset exchange with Range, the Company received acreage and producing wells in the Permian Basin of Texas in exchange for acreage, producing wells, the Company’s 50% ownership interest in Nora LLC and cash of $167.3 million. In conjunction with this transaction, the Company recognized a pre-tax gain of $6.8 million which is reflected in gain on sale / exchange of assets on the Statements of Consolidated Income.
	The Company’s ownership share of the earnings for 2014, 2013 and 2012 related to the total investments accounted for under the equity method was $3.4 million, $7.6 million and $6.1 million, respectively, reported in other income on the Statements of Consolidated Income.
	During September 2014, the Company and an affiliate of Nextera Energy, Inc. announced the formation of a joint venture, Mountain Valley Pipeline, LLC (MVP LLC), that will construct and own the Mountain Valley Pipeline (MVP). The Company expects to transfer its interest in MVP LLC to the Partnership. The approximately 300-mile pipeline will extend from the Partnership’s existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia. The Company expects that the Partnership will own the largest interest in the joint venture and will operate MVP. As of December 31, 2014, the Company’s interest in MVP LLC was recorded in other assets instead of equity in nonconsolidated investments as certain formation and funding activities for MVP LLC had not yet occurred.
	The following tables summarize the unaudited condensed financial statements for nonconsolidated investments accounted for under the equity method of accounting for the periods noted:
	Summarized Balance Sheets
		As of December 31,
		2014			2013
		(Thousands)
	Current assets	$	—		$	27,014
	Noncurrent assets	—			239,583
	Total assets	$	—		$	266,597
	Current liabilities	$	—		$	8,529
	Stockholders’ equity	—			258,068
	Total liabilities and stockholders’ equity	$	—		$	266,597
	Summarized Statements of Income
		Years Ended December 31,
		2014			2013				2012
		(Thousands)
	Revenues	$	19,924		$	45,040			$	47,888
	Operating expenses	13,155			29,810				35,596
	Net income	$	6,769		$	15,230			$	12,292

ShortTerm_Loans

Short-Term Loans	12 Months Ended
	Dec. 31, 2014
Short-term Debt [Abstract]
Short-Term Loans	Short-Term Loans
	The Company has a $1.5 billion revolving credit facility, which was amended in February 2014, 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.
	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.
	In February 2014, the Partnership amended its credit facility to increase the borrowing capacity to $750 million. The amended credit facility will expire 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, the Partnership 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 the Partnership. The Company is not a guarantor of the Partnership’s obligations under the credit facility.  The Partnership’s obligations under the revolving portion of the credit facility are unsecured. The Partnership’s obligations under the credit facility were unconditionally guaranteed by each of the Partnership’s subsidiaries. In January 2015, the Partnership amended its credit facility to, among other things, release its subsidiaries from their guarantee obligations under the credit facility.
	As of December 31, 2014 and 2013, neither the Company nor the Partnership had loans or letters of credit outstanding under their respective credit facilities. The Company incurred commitment fees averaging approximately 23 basis points and 24 basis points for the years ended December 31, 2014 and 2013, respectively, to maintain credit availability under its credit facility. The Partnership incurred commitment fees averaging approximately 24 basis points and 25 basis points for the years ended December 31, 2014 and 2013, respectively, to maintain credit availability under its credit facility.
	The Company did not have any short-term loans outstanding at any time during the year ended December 31, 2014. The maximum amount of outstanding short-term loans at any time under the Company’s credit facility during the year ended December 31, 2013 was $178.5 million. The average daily balance of short-term loans outstanding for the Company during the year ended December 31, 2013 was approximately $12.1 million at a weighted average annual interest rate of 1.7%. The maximum amount of outstanding short-term loans at any time under the Partnership’s credit facility during the year ended December 31, 2014 was $450 million, and the average daily balance of short-term loans outstanding was approximately $119 million at a weighted average annual interest rate of 1.7%. The Partnership had no short-term loans outstanding at any time during the year ended December 31, 2013.
	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, 2014, the Company was in compliance with all debt provisions and covenants.
	The Partnership’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 the credit facility, the Partnership 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, 2014, the Partnership was in compliance with all credit facility provisions and covenants.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Current and Noncurrent [Abstract]
Long-Term Debt	Long-Term Debt
		As of December 31,
		2014		2013
		(Thousands)
	7.76% notes, due 2015 thru 2016	$	10,700	$	18,316
	5.00% notes, due October 1, 2015	150,000		150,000
	5.15% notes, due March 1, 2018	200,000		200,000
	6.50% notes, due April 1, 2018	500,000		500,000
	8.13% notes, due June 1, 2019	700,000		700,000
	4.88% notes, due November 15, 2021	750,000		750,000
	4.00% EQT Midstream Partners notes, due August 1, 2024	500,000		—
	7.75% debentures, due July 15, 2026	115,000		115,000
	Medium-term notes:
	7.3% to 7.6% Series B, due 2015 thru 2023	20,000		20,000
	7.6% Series C, due 2018	8,000		8,000
	8.7% to 9.0% Series A, due 2020 thru 2021	35,200		40,200
		2,988,900		2,501,516
	Less debt payable within one year	166,011		11,162
	Total long-term debt	$	2,822,889	$	2,490,354
	In August 2014, the Partnership issued 4.00% Senior Notes due 2024 (4.00% Senior Notes) in the aggregate principal amount of $500.0 million. Refer to Note 3 for additional information.
	The indentures governing the Company’s and the Partnership’s long-term indebtedness contain certain restrictive financial and operating covenants, including covenants that restrict the Company’s ability to incur 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 the Partnership’s debt rating would not trigger a default under the indentures governing the indebtedness.
	Aggregate maturities of long-term debt are $166.0 million in 2015, $3.0 million in 2016, zero in 2017, $708.0 million in 2018, and $700.0 million in 2019.

Pension_and_Other_PostRetireme

Pension and Other Post-Retirement Benefit Plans	12 Months Ended
	Dec. 31, 2014
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). The termination process is expected to be complete by the end of 2016. Following the satisfaction of the IRS and PBGC regulatory requirements, 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,
		2014				2013				2014			2013
		Pension Benefits								Other Benefits
		(Thousands)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	21,828			$	63,270			$	18,253		$	36,255
	Service cost	350				500				669			905
	Interest cost	820				1,935				693			1,110
	Amendments	—				—				227			—
	Actuarial loss (gain)	2,412				(3,038		)		1,190			(2,355		)
	Benefits paid	(1,988		)		(5,269		)		(2,291		)	(3,961		)
	Expenses paid	(262		)		(493		)		—			—
	Divestitures	—				(34,410		)		—			(13,701		)
	Settlements	(1,456		)		(667		)		—			—
	Benefit obligation at end of year	$	21,704			$	21,828			$	18,741		$	18,253
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	20,089			$	46,984			$	493		$	165
	Actual gain on plan assets	1,217				7,304				—			—
	Contributions	723				2,639				330			328
	Benefits paid	(1,988		)		(5,269		)		—			—
	Expenses paid	(262		)		(493		)		—			—
	Divestitures	—				(30,409		)		—			—
	Settlements	(1,456		)		(667		)		—			—
	Fair value of plan assets at end of year	18,323				20,089				823			493
	Funded status at end of year	$	(3,381	)		$	(1,739	)		$	(17,918	)	$	(17,760	)
	Amounts recognized in the statement of financial position consist of:
	Current liabilities	$	—			$	—			$	(924	)	$	(1,341	)
	Noncurrent liabilities	(3,381		)		(1,739		)		(16,994		)	(16,419		)
	Net amounts recognized	$	(3,381	)		$	(1,739	)		$	(17,918	)	$	(17,760	)
	Amounts recognized in accumulated OCI, net of tax, consist of:
	Net loss	$	8,082			$	7,524			$	8,273		$	8,234
	Net prior service (credit)	—				—				285			106
	Net amount recognized	$	8,082			$	7,524			$	8,558		$	8,340
	The accumulated benefit obligation for the Company’s defined benefit pension plans was $21.7 million and $21.8 million at December 31, 2014 and 2013, 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,
		2014				2013				2012			2014			2013			2012
		Pension Benefits											Other Benefits
		(Thousands)
	Components of net periodic benefit cost:
	Service cost	$	350			$	500			$	500		$	669		$	905		$	737
	Interest cost	820				1,935				2,448			693			1,110			1,427
	Expected return on plan assets	(1,377		)		(3,323		)		(3,712		)	—			—			—
	Amortization of prior service cost	—				—				—			(446		)	(845		)	(845		)
	Recognized net actuarial loss	709				2,306				1,880			879			1,760			1,671
	Settlement loss and special termination benefits	879				381				725			—			—			—
	Subtotal	1,381				1,799				1,841			1,795			2,930			2,990
	Net periodic benefit cost of discontinued operations	—				1,552				1,586			—			1,356			1,288
	Net periodic benefit cost	$	1,381			$	247			$	255		$	1,795		$	1,574		$	1,702
	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,
		2014				2013				2012			2014			2013			2012
		Pension Benefits											Other Benefits
		(Thousands)
	Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
	Net loss	$	558			$	712			$	261		$	39		$	2,147		$	494
	Net prior service cost	—				—				—			179			416			330
	Total recognized in OCI, net of tax	$	558			$	712			$	261		$	218		$	2,563		$	824
	Total recognized in net periodic benefit cost and OCI, net of tax	$	1,939			$	959			$	2,102		$	2,013		$	4,137		$	3,814
	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 plans that will be amortized from accumulated OCI, net of tax, into net periodic benefit cost during 2015 is $0.4 million.  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 2015 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,
	2014		2013		2014		2013
	Pension Benefits				Other Benefits
Discount rate	3.60%		4.00%		3.60%		4.00%
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,
	2014			2013			2014			2013
	Pension Benefits						Other Benefits
Discount rate	4	%		3.25	%		4	%		3.25	%
Expected return on plan assets	7.75	%		7.75	%		N/A			N/A
Rate of compensation increase	N/A			N/A			N/A			N/A
The expected rate of return is established 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 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 for 2015 is expected to be in the range of 5.50% to 6.25%.  This assumption will be used to derive the Company’s 2015 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 or discount rate changes.
For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits in 2014 was 7.25% for both the Pre-65 and Post-65 medical charges.  The rates were assumed to decrease gradually to ultimate rates of 5.00% in 2024.
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											One-Percentage-Point
	Increase											Decrease
	2014				2013				2012			2014			2013			2012
	(Thousands)
Increase (decrease) to total of service and interest cost components	$	13			$	25			$	32		$	(14	)	$	(26	)	$	(32	)
Increase (decrease) to post-retirement benefit obligation	$	228			$	220			$	711		$	(229	)	$	(223	)	$	(688	)
The asset allocation for the Retirement Plan at December 31, 2014 and 2013 and target allocation for January 2013 - October 2014 by asset category are as follows:
	Target Allocation		Percentage of Plan Assets
			at December 31,
Asset Category	January 2013 - October 2014		2014			2013
Domestic broadly diversified equity securities	40% - 60%		26	%		42	%
Fixed income securities	20% - 50%		63	%		29	%
International broadly diversified equity securities	5% - 15%		8	%		7	%
Alternative fixed income securities	0% - 10%		—			4	%
Cash and equivalent investments	0% - 15%		3	%		18	%
			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, 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 broadly diversified equity securities categories were outside of the previously established target allocations but consistent with the BIC’s October 2014 determination. The investment allocation is likely to be adjusted further through the date of the liquidation of all assets of, and the settlement of the benefit obligations under, the Retirement Plan. The cash and equivalent investments category was outside of the target allocation at December 31, 2013 as a result of liquidating investments for transfer to the Peoples Natural Gas Company LLC DB Plan for Former Employees of Equitable Gas Company in connection with the Equitable Gas Transaction.
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 $0.7 million, $2.6 million and $2.9 million during 2014, 2013 and 2012, respectively, to meet certain funding targets. The Company expects to make cash payments of at least $0.6 million related to its pensions during 2015, which will meet minimum required contributions and the 80% funding obligation on the Retirement Plan.  Typically, pension plan cash contributions are designed to at least meet requirements of the 80% funding level.  Assuming the termination process for the Retirement Plan is completed in 2016 as anticipated, the Company expects to make a cash contribution to the Retirement Plan so that it is fully funded and able to purchase the required annuities. The actual dollar amount of the cash contribution made in any particular year will vary as a result of gains or losses sustained by the pension plan during the year due to market conditions.  The Company does not expect its cash contributions to have a significant effect on its financial position, results of operations or liquidity.
If the termination process for the Retirement Plan is not completed, the pension benefit payments over the next five years and five years thereafter, which reflect expected future service, are expected to be as follows: $2.1 million in 2015; $1.9 million in 2016; $1.8 million in 2017; $1.7 million in 2018; $1.9 million in 2019; and $7.7 million in the five years thereafter.
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: $1.8 million in 2015; $1.7 million in 2016; $1.7 million in 2017; $1.7 million in 2018; $1.6 million in 2019; and $7.6 million in the five years thereafter.
Expense recognized by the Company related to its defined contribution plans totaled $13.7 million in 2014, $14.6 million in 2013 and $12.0 million in 2012.
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 include mutual funds with a fair value of $5.7 million and $6.9 million as of December 31, 2014 and 2013, 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 with a fair value of $12.6 million and $13.2 million as of December 31, 2014 and 2013, 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, 2014 and 2013, 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_C

Changes in Accumulated Other Comprehensive Income by Component	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
		Year Ended December 31, 2014
		Natural gas cash				Interest rate				Pension and				Accumulated
		flow hedges, net				cash flow				other post-				OCI (loss), net
		of tax				hedges, net				retirement				of tax
						of tax				benefits
										liability
										adjustment,
										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
		flow hedges, net				cash flow				other post-				OCI (loss), net
		of tax				hedges, net				retirement				of tax
						of tax				benefits
										liability
										adjustment,
										net of tax
		(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 5 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 13 for additional information.

Common_Stock_and_Earnings_Per_

Common Stock and Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Common Stock and Earnings Per Share	Common Stock and Earnings Per Share
	Common Stock
	At December 31, 2014, shares of EQT’s authorized and unissued common stock were reserved as follows:
		(Thousands)
	Possible future acquisitions	20,457
	Stock compensation plans	16,236
	Total	36,693
	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,
			2014		2013		2012
			(Thousands except per share amounts)
	Basic earnings per common share:
	Net income attributable to EQT Corporation		$	386,965	$	390,572	$	183,395
	Average common shares outstanding		151,553		150,574		149,619
	Basic earnings per common share		$	2.55	$	2.59	$	1.23
	Diluted earnings per common share:
	Net income attributable to EQT Corporation		$	386,965	$	390,572	$	183,395
	Average common shares outstanding		151,553		150,574		149,619
	Potentially dilutive securities:
	Stock options and awards (a)		960		1,213		887
	Total		152,513		151,787		150,506
	Diluted earnings per common share		$	2.54	$	2.57	$	1.22
	(a)         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. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 281,528 shares for the year ended December 31, 2012.
	The impact of the Partnership’s dilutive units did not have a material impact on the Company’s earnings per share calculations for any of the periods presented.

ShareBased_Compensation_Plans

Share-Based Compensation Plans	12 Months Ended
	Dec. 31, 2014
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,
			2014				2013			2012
			(Thousands)
	2010 Executive Performance Incentive Programs		$	—			$	—		$	1,940
	2012 Executive Performance Incentive Program		7,743				6,739			10,633
	2013 Executive Performance Incentive Program		8,208				6,602			—
	2014 Executive Performance Incentive Program		9,104				—			—
	2010 Stock Incentive Award Program		—				—			4,022
	2011 Volume and Efficiency Program		—				13,834			5,286
	2011 EQT Value Driver Award Program		—				—			3,033
	2012 EQT Value Driver Award Program		—				2,327			11,557
	2013 EQT Value Driver Award Program		4,403				13,050			—
	2014 EQT Value Driver Award Program		11,510				—			—
	2014 EQM Value Driver Award Program		2,378				—			—
	Restricted stock awards		4,688				3,033			2,007
	Non-qualified stock options		3,002				3,805			3,580
	Other programs, including non-employee director awards		(409		)		9,154			3,763
	Total share-based compensation expense		$	50,627			$	58,544		$	45,821
	The Company typically uses treasury stock to fund awards that are paid in stock.  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 4.
	Cash received from exercises under all share-based payment arrangements for employees and directors for the years ended December 31, 2014, 2013 and 2012 were $19.2 million, $32.9 million and $7.9 million, respectively.  During the years ended December 31, 2014, 2013 and 2012, share-based payment arrangements paid in stock generated tax benefits of $45.9 million, $14.4 million and $15.1 million, respectively. As a result of the Company’s NOL position in 2012, excess tax benefits of $8.1 million were not recorded in the financial statements as an addition to common stockholders’ equity.
	Executive Performance Incentive Programs
	Effective in 2009, the Compensation Committee of the Board of Directors adopted the 2010 Executive Performance Incentive Program (2010 EPIP) and the 2010 July Executive Performance Incentive Program (the 2010 July EPIP, and together with the 2010 EPIP, the 2010 EPIPs) under the 2009 Long-Term Incentive Plan. The 2010 EPIPs were established to provide long-term incentive opportunities to key employees to further align their interest with those of the Company’s shareholders and with the strategic objectives of the Company. The vesting of the units under the 2010 EPIPs occurred on December 31, 2012, after the ordinary close of the respective performance periods. Awards granted were earned based on a combination of the level of total shareholder return relative to the respective peer groups over the period January 1, 2010 (July 1, 2010 for the 2010 July EPIP) through December 31, 2012 and the level of production sales revenues over the period January 1, 2010 (July 1, 2010 for the 2010 July EPIP) through September 20, 2012. The Company accounted for these awards as equity awards using the $60.09 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 periods. The prices were generated using each company’s annual volatility for the expected term and the commensurate three-year risk-free rate of 1.69%. Based on the Company’s performance relative to the conditions discussed above, 192,744 shares of common stock, valued at $6.9 million based on the Monte Carlo value on the grant date, were distributed on December 31, 2012.
	Effective in 2012, the Compensation Committee of the Board of Directors adopted the 2012 Executive Performance Incentive Plan (2012 EPIP) under the 2009 Long-Term Incentive Plan. The 2012 EPIP 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 EPIP will occur upon payment in the first quarter of 2015, 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 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, are expected to be distributed during the first quarter of 2015. The total compensation cost capitalized in 2014, 2013 and 2012 was $2.6 million, $8.1 million, and $2.1 million, respectively.
	The peer companies for the 2012 EPIP are as follows:
	Cabot Oil & Gas Corp.	National Fuel Gas Company	Sempra Energy
	Chesapeake Energy Corp.	NStar Electric Co.	SM Energy Company
	Cimarex Energy Co.	ONEOK, Inc.	Southwestern Energy Company
	CONSOL Energy Inc.	Penn Virginia Corp.	Spectra Energy Corp
	Energen Corp.	Pioneer Natural Resources Company	Ultra Petroleum Corp.
	EOG Resources, Inc.	Plains Exploration & Production Co.	Whiting Petroleum Corp.
	EXCO Resources, Inc.	Questar Corp.	The Williams Companies, Inc.
	MarkWest Energy Partners, L.P.	Quicksilver Resources Inc.
	MDU Resources Group, Inc.	Range Resources Corp.
	Effective in 2013, the Compensation Committee of the Board of Directors adopted the 2013 Executive Performance Incentive Plan (2013 EPIP) under the 2009 Long-Term Incentive Plan. The 2013 EPIP 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 297,597 units were outstanding at January 1, 2014. Adjusting for 26,534 forfeitures, there were 271,063 outstanding units as of December 31, 2014. The vesting of the units under the 2013 EPIP will occur upon payment after December 31, 2015 (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 cumulative operating cash flow per share over the period January 1, 2013 through December 31, 2015. 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 0.36%. As the program includes a performance condition that affects the number of shares that will ultimately vest (the cumulative operating cash flow per share 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, 2014, the compensation expense was recorded using a grant date fair value of $140.00 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 2014 and 2013 was $5.5 million and $5.0 million, respectively.  As of December 31, 2014, $12.6 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2013 EPIP was expected to be recognized by December 31, 2015.
	The peer companies for the 2013 EPIP 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 of the Board of Directors adopted the 2014 Executive Performance Incentive Plan (2014 EPIP) under the 2009 Long-Term Incentive Plan. The 2014 EPIP 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 278,440 units were granted in 2014 and no additional units may be granted. Adjusting for 19,210 forfeitures, there were 259,230 outstanding units as of December 31, 2014. The vesting of the units under the 2014 EPIP 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, 2014, the compensation expense was recorded using a grant date fair value of $167.12 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 2014 was $4.6 million. As of December 31, 2014, $27.3 million of unrecognized compensation cost (assuming no changes to the performance condition achievement level) related to the 2014 EPIP was expected to be recognized over the next two years.
	The peer companies for the 2014 EPIP 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.
	2010 Stock Incentive Award Program
	Effective in 2010, the Compensation Committee of the Board of Directors adopted the 2010 Stock Incentive Award Program (2010 SIA) under the 2009 Long-Term Incentive Plan. The 2010 SIA 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 payout opportunity with respect to the performance awards was contingent upon adjusted 2010 earnings before interest, taxes, depreciation and amortization (EBITDA) performance as compared to the Company’s annual business plan and individual, business unit and Company value drive performance over the period January 1, 2010 through December 31, 2010. The vesting of the awards occurred on December 31, 2012. The vesting resulted in 294,925 awards including accrued dividends, valued at $12.6 million based on the grant date fair value, being distributed in Company common stock on December 31, 2012.
	Value Driver Award Programs
	Effective in 2011, the Compensation Committee of the Board of Directors adopted the 2011 Value Driver Award Program (2011 EQT VDA) under the 2009 Long-Term Incentive Plan. The 2011 EQT VDA was established to align the interests of key employees with the interests of shareholders and customers and the strategic objective of the Company. Under the 2011 EQT VDA, 50% of the units confirmed vested upon payment following the first anniversary of the grant date; the remaining 50% of the units confirmed vested on December 31, 2012. The payments were contingent upon adjusted 2011 EBITDA performance as compared to the Company’s annual business plan and individual, business unit and Company value drive performance over the period January 1, 2011 through December 31, 2011. The two tranches of awards vested and were distributed in cash payments of $14.6 million in February 2012 and $15.3 million on December 31, 2012. The Company accounted for these awards as liability awards and as such, recorded 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 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.
	Effective in 2012, the Compensation Committee of the Board of Directors adopted the 2012 Value Driver Award Program (2012 EQT VDA) under the 2009 Long-Term Incentive Plan. The 2012 EQT VDA 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 VDA, 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.
	Effective in 2013, the Compensation Committee of the Board of Directors adopted the 2013 Value Driver Award Program (2013 EQT VDA) under the 2009 Long-Term Incentive Plan. The 2013 EQT VDA 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 VDA, 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 are 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. As of January 1, 2014, 614,048 awards including accrued dividends were outstanding under the 2013 EQT VDA.  The first tranche of the confirmed awards vested and 306,076 were distributed in Company common stock in February 2014.  The remainder of the confirmed awards are expected to vest and be paid in Company common stock in the first quarter of 2015.  As of December 31, 2014, 279,761 awards including accrued dividends were outstanding under the 2013 EQT VDA. 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 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 was $2.9 million and $14.1 million in 2014 and 2013, respectively.
	Effective in 2014, the Compensation Committee of the Board of Directors adopted the 2014 Value Driver Award Program (2014 EQT VDA) under the 2009 Long-Term Incentive Plan. The 2014 EQT VDA 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 VDA, 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 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 December 31, 2014, 375,426 awards including accrued dividends were outstanding under the 2014 EQT VDA. The first tranche of the confirmed awards are expected to vest and be paid in cash in the first quarter of 2015. The remainder of the confirmed awards are expected to vest and be paid in cash in the first quarter of 2016. 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 was $9.8 million in 2014. The total liability recorded for the 2014 EQT VDA was $21.3 million as of December 31, 2014.
2011 Volume and Efficiency Program
Effective in 2011, the Compensation Committee of the Board of Directors 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 was $2.8 million and $2.5 million in 2013 and 2012, respectively.
Restricted Stock Awards
The Company granted 89,500, 101,510 and 103,730 restricted stock awards during the years ended December 31, 2014, 2013 and 2012, 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 $95, $71 and $54 for the years ended December 31, 2014, 2013 and 2012, respectively.  The total fair value of restricted stock awards vested during the years ended December 31, 2014, 2013 and 2012 was $1.5 million, $4.3 million and $1.6 million, respectively.
As of December 31, 2014, $9.4 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 1.5 years.
A summary of restricted stock activity as of December 31, 2014, and changes during the year then ended, is presented below:
Restricted Stock		Non-			Weighted			Aggregate
		Vested			Average			Fair Value
		Shares			Fair Value
Outstanding at January 1, 2014		182,378			$	61.98		$	11,302,992
Granted		89,500			$	94.91		8,494,746
Vested		(27,310	)		$	53.82		(1,469,604		)
Forfeited		(14,578	)		$	75.64		(1,102,723		)
Outstanding at December 31, 2014		229,990			$	74.9		$	17,225,411
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, 2014, 2013 and 2012.  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,
		2014		2013		2012
Risk-free interest rate		1.72%		0.76%		0.89%
Dividend yield		0.15%		0.22%		1.64%
Volatility factor		24.80%		31.69%		31.44%
Expected term		5 years		5 years		5 years
The Company granted 133,500, 259,600 and 278,300 stock options during the years ended December 31, 2014, 2013 and 2012, respectively.   The weighted average grant date fair value of the options was $22.25, $16.72 and $13.19 for the years ended December 31, 2014, 2013 and 2012, respectively.  The total intrinsic value of options exercised during the years ended December 31, 2014, 2013 and 2012 was $14.4 million, $22.8 million, and $11.8 million, respectively.
As of December 31, 2014, $1.9 million of unrecognized compensation cost related to outstanding nonvested stock options was expected to be recognized by December 31, 2016.
A summary of option activity as of December 31, 2014, and changes during the year then ended, is presented below:
Non-qualified Stock Options		Shares			Weighted		Weighted	Aggregate
					Average		Average	Intrinsic
					Exercise		Remaining	Value
					Price		Contractual
							Term
Outstanding at January 1, 2014		1,482,001			$49.77
Granted		133,500			$89.78
Exercised		(277,033	)		$48.27
Forfeited		—			$—
Outstanding at December 31, 2014		1,338,468			$54.08		6.35 years	$30,823,027
Exercisable at December 31, 2014		1,079,968			$49.09		5.83 years	$28,733,027
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 197,778 non-employee director share-based awards including accrued dividends were outstanding as of December 31, 2014.  A total of 17,900, 25,500 and 28,140 share-based awards were granted to non-employee directors during the years ended December 31, 2014, 2013 and 2012, respectively.  The weighted average fair value of these grants, based on the Company’s common stock price on the grant date, was $89.78, $58.98 and $53.47 for the years ended December 31, 2014, 2013 and 2012, respectively.
EQM Awards
At the closing of the Partnership’s IPO in July 2012, the Compensation Committee of the Board of Directors and the general partner of the Partnership granted certain key Company employees performance awards under the EQM Total Return Program representing 146,490 common units of the Partnership.  The performance condition related to the performance awards will be satisfied on December 31, 2015 if the total unitholder return realized on the Partnership’s common units from the date of grant is at least 10%. If the unitholder return performance condition is not achieved as of December 31, 2015, the performance condition will nonetheless be satisfied if the 10% unitholder return threshold is satisfied as of the end of any calendar quarter ending after December 31, 2015 and on or before December 31, 2017. If earned, the units are expected to be distributed in Partnership common units.
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 Partnership 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 an expected Partnership distribution growth rate of 10%.  As of December 31, 2013, 142,500 of these performance awards were outstanding. Adjusting for 2,520 forfeitures, there were 139,980 awards outstanding as of December 31, 2014. As of December 31, 2014, there was $0.8 million of unrecognized compensation cost related to the EQM Total Return Program which is expected to be recognized by December 31, 2015.
Additionally, the general partner of the Partnership has granted Partnership common unit-based phantom awards to its independent directors, which vested upon grant.  The value of the phantom awards will be paid in Partnership 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 11,759 independent director unit-based awards including accrued distributions were outstanding as of December 31, 2014.  A total of 2,580, 3,790 and 4,780 unit-based awards were granted to independent directors during the years ended December 31, 2014, 2013 and 2012, respectively.  The weighted average fair value of these grants, based on the Partnership’s common unit price on the grant date, was $58.79, $37.92 and $24.30 for the years ended December 31, 2014, 2013 and 2012, respectively.
Effective in 2014, the Compensation Committee of the Board of Directors and the Board of Directors of the Partnership’s general partner adopted the 2014 EQM Value Driver Award Program (2014 EQM VDA) under the 2009 Long-Term Incentive Plan and the Partnership’s 2012 Long-Term Incentive Plan. The 2014 EQM VDA was established to align the interests of key employees with the interests of Partnership unitholders and customers and the strategic objectives of the Partnership. Under the 2014 EQM VDA, 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 performance metrics are the Partnership’s 2014 adjusted EBITDA performance as compared to the Partnership’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 December 31, 2014, 62,845 awards including accrued dividends were outstanding under the 2014 EQM VDA. The first tranche of the confirmed awards is expected to vest and be distributed in Partnership common units in the first quarter of 2015. The remainder of the confirmed awards is expected to vest and be paid in Partnership common units in the first quarter of 2016. The Partnership accounts for these awards as equity awards using the $58.79 grant date fair value per unit which was equal to the Partnership’s common unit price on the date prior to the date of grant. Due to the graded vesting of the awards, the Partnership 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 in 2014 was $0.3 million. As of December 31, 2014, there was $0.9 million of unrecognized compensation cost related to the 2014 EQM VDA which is expected to be recognized by December 31, 2015.
2015 Value Driver Award Programs and 2015 Executive Performance Incentive Program
Effective in 2015, the Compensation Committee of the Board of Directors adopted the 2015 EQT Value Driver Award Program (2015 EQT VDA) and the 2015 Executive Performance Incentive Program (2015 EPIP) under the 2014 Long-Term Incentive Plan. The 2015 EQT VDA and 2015 EPIP 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 281,460 units were granted under the 2015 EQT VDA.  Fifty percent of the units confirmed under the 2015 EQT VDA will vest upon the payment date following the first anniversary of the grant date; the remaining 50% of the confirmed units under the 2015 EQT VDA 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 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.  If earned, the 2015 EQT VDA units are expected to be distributed in Company common stock. The Company did not record any obligation or expense related to the 2015 EQT VDA as of December 31, 2014.
A total of 369,290 units were granted under the 2015 EPIP.  The vesting of the units under the 2015 EPIP will occur upon payment after December 31, 2017 (the end of the three years 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, 2015 through December 31, 2017.  If earned, the 2015 EPIP units are expected to be distributed in Company common stock.  The Company did not record any expense related to the 2015 EPIP as of December 31, 2014.
2015 Stock Options
Effective January 1, 2015, the Compensation Committee of the Board of Directors granted 158,200 non-qualified stock options to key employees of the Company.  The 2015 options are ten years options, with an exercise price of $75.70, and are subject to three years cliff vesting. The Company did not record any expense related to 2015 stock options as of December 31, 2014.

Concentrations_of_Credit_Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2014
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 account for approximately 12% and 11% of its revenues in 2014 and 2013, respectively. No single customer accounted for more than 10% of revenues in 2012.
	Approximately 87% and 82% of the Company’s accounts receivable balance as of December 31, 2014 and 2013, 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, 2014, 2013 or 2012.
	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 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, 2014, the Company was not in default under any derivative contracts and has no knowledge of default by any counterparty to 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, 2014
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 third-party pipelines.  Future payments for these items as of December 31, 2014 totaled $4,632.2 million (2015 - $205.1 million, 2016 - $267.8 million, 2017 - $333.1 million, 2018 - $353.4 million, 2019 - $348.0 million and thereafter - $3,124.8 million).  The Company has entered into agreements to release some of its capacity to various third parties.
	The Company has agreements with drilling contractors to provide drilling equipment and services to the Company.  These obligations totaled approximately $132.0 million as of December 31, 2014.  Operating lease rentals for drilling contractors, office locations and warehouse buildings, as well as a limited amount of equipment, amounted to approximately $65.6 million in 2014, $56.0 million in 2013 and $45.0 million in 2012.  Future lease payments under non-cancelable operating leases as of December 31, 2014 totaled $225.6 million (2015 - $83.4 million, 2016 - $37.4 million, 2017 - $31.7 million, 2018 – $16.8 million, 2019 - $9.6 million and thereafter - $46.7 million).
	In July 2014, the Partnership announced that it will construct and own the Ohio Valley Connector (OVC) pipeline. The OVC includes a 36-mile pipeline that will extend the Partnership’s transmission and storage system from northern West Virginia to Clarington, Ohio, at which point it will interconnect with the Rockies Express Pipeline and the Texas Eastern Pipeline. The Partnership has entered into a 20-year precedent agreement with the Company for a total of 650 BBtu per day of firm transmission capacity on the OVC.
	In September 2014, the Company and an affiliate of NextEra Energy, Inc. announced the formation of the MVP LLC joint venture that will construct and own the MVP. The Company expects to transfer its interest in MVP LLC to the Partnership. The approximately 300-mile pipeline will extend from the Partnership’s existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia. The Company expects that the Partnership will own the largest interest in the joint venture and will operate the MVP, with the Partnership funding its proportionate share through capital contributions made to the joint venture. The joint venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms and is currently in negotiation with additional shippers who have expressed interest in the MVP project. As a result, the final project scope, including pipe diameter and total capacity, has not yet been determined; however the voluntary pre-filing process with the FERC began in October 2014.
	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 $1.3 million is included in other liabilities and credits in the Consolidated Balance Sheets as of December 31, 2014.
	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, 2014
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 $153 million as of December 31, 2014, extending at a decreasing amount for approximately 13 years.
	In December 2014, the Company issued a $130 million performance guarantee (the Original MVP Guarantee) in connection with its subsidiary’s obligations to fund the Company’s proportionate share of the construction budget for the MVP. Upon the FERC’s initial release to begin construction of the MVP, the Original MVP Guarantee will terminate, and the Company will be obligated to issue a new guarantee in an amount equal to 33% of the subsidiary’s remaining obligations to make capital contributions to MVP LLC in connection with the then remaining construction budget.  Upon the transfer of the Company’s interest in the joint venture to the Partnership, the Partnership will assume these obligations to provide performance assurances for the MVP. See Note 18 for additional discussion regarding the MVP joint venture.
	The NORESCO and the MVP guarantees are exempt from ASC Topic 460, Guarantees.  The Company has determined that the likelihood it will be required to perform on these arrangements is remote and any potential payments are expected to be immaterial to the Company’s financial position, results of operations and liquidity.  As such, the Company has not recorded any liabilities in its Consolidated Balance Sheets related to these guarantees.

Interim_Financial_Information_

Interim Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2014
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 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)
	2014 (a)
	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	)
	2013 (a)
	Operating revenues	$	415,883		$	473,093	$	479,606	$	493,429
	Operating income	144,479			161,980		167,064		181,081
	Amounts attributable to EQT Corporation:
	Income from continuing operations	69,131			81,466		86,199		61,933
	Income from discontinued operations	31,124			5,390		2,057		53,272
	Net income attributable to EQT Corporation	$	100,255		$	86,856	$	88,256	$	115,205
	Earnings per share of common stock attributable to EQT Corporation:
	Basic:
	Income from continuing operations	$	0.46		$	0.54	$	0.57	$	0.41
	Income from discontinued operations	0.21			0.04		0.02		0.35
	Net income	$	0.67		$	0.58	$	0.59	$	0.76
	Diluted:
	Income from continuing operations	$	0.46		$	0.54	$	0.57	$	0.4
	Income from discontinued operations	0.2			0.03		0.01		0.35
	Net income	$	0.66		$	0.57	$	0.58	$	0.75
	(a)                     The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
	During the three months ended December 31, 2014, the Company recognized impairment charges on proved and unproved oil and gas properties of $267.3 million. Refer to Note 1 for additional information.
	Differences between all amounts in the above table and those previously reported in the Company’s 2013 Form 10-Qs are attributable to the Equitable Gas Transaction, as described in Note 2. All prior periods presented have been recast to reflect the presentation of discontinued operations.

Natural_Gas_Producing_Activiti

Natural Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2014
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 table presents the costs incurred relating to natural gas, NGL and oil production activities (a):
			For the Years Ended December 31,
			2014				2013				2012
			(Thousands)
	At December 31:
	Capitalized costs		$	10,263,547			$	8,152,951			$	6,750,343
	Accumulated depreciation and depletion		2,874,257				2,134,953				1,572,775
	Net capitalized costs		$	7,389,290			$	6,017,998			$	5,177,568
	Costs incurred for the years ended December 31:
	Property acquisition:
	Proved properties (b)		$	231,322			$	90,390			$	16,965
	Unproved properties (c)		493,067				95,861				117,654
	Exploration (d)		16,023				4,285				4,827
	Development		1,697,501				1,230,301				850,854
	(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 acquisition in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake acquisition in 2013.
	(c)                    Amounts include $317.2 million for the purchase of Permian leases acquired in the Range acquisition in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake acquisition in 2013.
	(d)                     Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.
	Results of Operations for Producing Activities
	The following table presents the results of operations related to natural gas, NGL and oil production:
			For the Years Ended December 31,
			2014				2013				2012
			(Thousands)
	Revenues:
	Affiliated		$	4,761			$	5,912			$	3,433
	Nonaffiliated		1,607,969				1,162,745				790,340
	Production costs		133,488				108,091				96,155
	Exploration costs		21,665				18,483				10,370
	Depreciation, depletion and accretion		592,855				578,641				409,628
	Impairment of long-lived assets		267,339				—				—
	Income tax expense		238,057				183,060				109,660
	Results of operations from producing activities (excluding corporate overhead)		$	359,326			$	280,382			$	167,960
	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 17 years of experience in the oil and gas industry.  To ensure that the reserves are materially accurate, management reviews the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves; division of interest and production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserve reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGL and oil reserves are audited by the independent consulting firm of Ryder Scott Company, L.P. (Ryder Scott), which is hired by the Company’s management.  Since 1937, Ryder Scott has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.
	Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment.  There were no differences between the internally prepared and externally audited estimates.  Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.  Ryder Scott reviewed 100% of the total net gas, NGL and oil proved reserves attributable to the Company’s interests as of December 31, 2014.  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, Ryder Scott determined which areas within the Company’s acreage were to be considered 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,
			2014			2013			2012
			(Millions of Cubic Feet)
	Natural Gas
	Proved developed and undeveloped reserves:
	Beginning of year		7,561,561			5,985,758			5,347,386
	Revision of previous estimates		(228,085	)		(375,887	)		(755,788	)
	Purchase of natural gas in place		44,867			472,798			—
	Sale of natural gas in place		(198,531	)		(455	)		(694	)
	Extensions, discoveries and other additions		3,040,938			1,844,840			1,654,228
	Production		(444,796	)		(365,493	)		(259,374	)
	End of year		9,775,954			7,561,561			5,985,758
	Proved developed reserves:
	Beginning of year		3,567,313			2,779,187			2,948,546
	End of year		4,257,377			3,567,313			2,779,187
			Years Ended December 31,
			2014			2013			2012
			(Thousands of Bbls)
	Oil (a)
	Proved developed and undeveloped reserves:
	Beginning of year		3,956			3,199			2,931
	Revision of previous estimates		(905	)		270			265
	Purchase of oil in place		2,165			—			—
	Sale of oil in place		(3	)		—			—
	Extensions, discoveries and other additions		241			757			268
	Production		(449	)		(270	)		(265	)
End of year		5,005			3,956			3,199
Proved developed reserves:
Beginning of year		3,892			3,199			2,931
End of year		5,005			3,892			3,199
(a)                      One thousand Bbl equals approximately 6 million cubic feet (MMcf).
	Years Ended December 31,
	2014			2013
	(Thousands of Bbls)
NGLs (a)
Proved developed and undeveloped reserves:
Beginning of year	127,162			—
Revision of previous estimates	(11,306	)		94,296
Purchase of NGLs in place	7,476			—
Sale of NGLs in place	(18	)		—
Extensions, discoveries and other additions	38,945			32,866
Production	(6,765	)		—
End of year	155,494			127,162
Proved developed reserves:
Beginning of year	65,837			—
End of year	89,830			65,837
(a)                     One thousand Bbl equals approximately 6 million cubic feet (MMcf).
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 will not be drilled within 5 years of initial booking. This total includes locations that are no longer economic in accordance with SEC pricing requirements as well as the remainder of proved undeveloped Huron locations that are 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.
During 2012, the Company recorded downward revisions of 754.2 Bcfe to the December 31, 2011 estimates of its reserves primarily due to the decrease in the average NYMEX natural gas price for the year causing the existing reserves to become uneconomic in accordance with SEC pricing requirements.  The Company’s 2012 extensions, discoveries and other additions, resulting from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery, of 1,655.8 Bcfe exceeded the 2012 production of 261.0 Bcfe. These reserve extensions and discoveries were mainly due to decreased lateral spacing in one of the Company’s Greene County, Pennsylvania locations and additional proved locations in the Company’s Wetzel and Doddridge County, West Virginia development areas.
As of December 31, 2014, the Company had a total of 15.3 Bcfe of reserves that have been classified as proved undeveloped for more than five years. These reserves are associated with two wells that were drilled in 2014 and that are scheduled to be completed and producing in 2015.
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:
		2014				2013				2012
		(Thousands)
Future cash inflows (a)		$	30,428,815			$	25,912,542			$	15,250,019
Future production costs		(4,868,079		)		(4,180,136		)		(3,070,957		)
Future development costs		(5,052,195		)		(4,199,722		)		(3,082,053		)
Future income tax expenses		(7,718,407		)		(6,533,817		)		(3,324,472		)
Future net cash flow		12,790,134				10,998,867				5,772,537
10% annual discount for estimated timing of cash flows		(7,980,106		)		(7,047,588		)		(3,617,378		)
Standardized measure of discounted future net cash flows		$	4,810,028			$	3,951,279			$	2,155,159
(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. 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 West Texas Intermediate (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.
	For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012 of $82.90 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $2.793 per Dth for Columbia Gas Transmission Corp., $2.785 per Dth for Dominion Transmission, Inc., $2.769 per Dth for the East Tennessee Natural Gas Pipeline, $2.782 per Dth for Texas Eastern Transmission Corp., $2.403 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.878 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.  For 2012, the West Virginia Marcellus reserves from Doddridge and Ritchie Counties were computed using an additional $0.591 and reserves from Wetzel County were computed using an additional $0.398 for revenues earned on NGLs that are produced from those reserves.  Revenues earned on NGLs that are produced from certain Kentucky reserves were computed using an additional $0.764.
Holding production and development costs constant, a change in price of $1 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, 2014 discounted future net cash flows before income taxes of the Company’s proved reserves of approximately $4.3 billion, $21.8 million and $551.1 million, respectively.
Summary of changes in the standardized measure of discounted future net cash flows for the years ended December 31:
		2014				2013				2012
		(Thousands)
Sales and transfers of natural gas and oil produced – net		$	(1,479,242	)		$	(1,060,566	)		$	(697,618	)
Net changes in prices, production and development costs		(1,525,944		)		(292,533		)		(3,530,086		)
Extensions, discoveries and improved recovery, less related costs		2,300,923				1,509,002				917,986
Development costs incurred		1,023,075				1,319,135				548,852
Purchase of minerals in place – net		72,139				348,608				—
Sale of minerals in place – net		(146,476		)		(252		)		(807		)
Revisions of previous quantity estimates		(222,195		)		106,170				(876,336		)
Accretion of discount		578,676				343,502				622,072
Net change in income taxes		(529,337		)		(1,031,105		)		1,127,272
Timing and other		787,130				554,159				111,000
Net increase (decrease)		858,749				1,796,120				(1,777,665		)
Beginning of year		3,951,279				2,155,159				3,932,824
End of year		$	4,810,028			$	3,951,279			$	2,155,159

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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. As of December 31, 2014, EQT owned a 2.0% general partner interest, all incentive distribution rights and a 34.4% limited partner interest in EQT Midstream Partners, LP (the Partnership) (NYSE: EQM). The Partnership is consolidated in EQT’s consolidated financial statements. EQT records the noncontrolling interest of the public limited partners in EQT’s 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, transportation, storage and marketing activities of the Company, including ownership and operation of the Partnership.
	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. Additionally, financial statements and notes to the financial statements previously reported in prior periods have been recast to reflect the presentation of discontinued operations as a result of the Equitable Gas Transaction. Refer to Note 2 for additional information on discontinued operations.
	Certain prior year amounts in the Statements of Consolidated Cash Flows have been revised to correctly present changes in accrued liabilities related to the timing of payments for capital expenditures. For the year ended December 31, 2013, net cash provided by operating activities decreased by approximately $37.5 million with a corresponding decrease in net cash used in investing activities as a result of this correction, and for the year ended December 31, 2012, net cash provided by operating activities decreased by $11.7 million with a corresponding decrease in net cash used in investing activities. The correction had no impact on the Statements of Consolidated Income or Consolidated Balance Sheets.
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. For hedged inventory subject to fair value hedges, the Company adjusts the average cost for the change in natural gas spot prices from the date the inventory is hedged until settlement. These fair value adjustments become part of the average cost of the inventory.
Property, Plant and Equipment	Property, Plant and Equipment: The Company’s property, plant and equipment consist of the following:
		As of December 31,
		2014			2013
		(Thousands)
	Oil and gas producing properties, successful efforts method	$	10,263,547		$	8,152,951
	Accumulated depletion	(2,874,257		)	(2,134,953		)
	Net oil and gas producing properties	7,389,290			6,017,998
	Midstream plant	3,234,370			2,807,165
	Accumulated depreciation and amortization	(606,998		)	(547,991		)
	Net midstream plant	2,627,372			2,259,174
	Other properties, at cost less accumulated depreciation	60,152			56,590
	Net property, plant and equipment	$	10,076,814		$	8,333,762
	Oil and gas producing properties use the successful efforts method of accounting for production activities.  Under this method, the cost of productive wells, including mineral interests, wells and related equipment, development dry holes, as well as productive acreage, 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 $108.5 million, $93.5 million and $72.1 million in 2014, 2013 and 2012, respectively.  The Company capitalized $35.0 million, $22.9 million and $15.6 million of interest relative to Marcellus and Utica well development in 2014, 2013 and 2012, 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 costs capitalized 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, 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 $1.22 per Mcfe, $1.50 per Mcfe and $1.52 per Mcfe produced for the years ended December 31, 2014, 2013 and 2012, respectively.
	The carrying values of the Company’s proved oil and gas properties are reviewed for indications of 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, in limited cases, risk-adjusted probable reserves, utilizing assumptions about the use of the asset, market prices for oil and gas and future operating costs.  Proved oil and gas properties that have carrying amounts in excess of estimated future cash flows would be deemed to be unrecoverable.  Those properties would be written down to fair value, which would be estimated by discounting the estimated future cash flows using discount rate assumptions that marketplace participants would use in their estimates of fair value.
	Due to the decline in commodity prices during 2014, there were indications that the carrying values of certain of the Company’s oil and gas producing properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon estimates of future production levels, commodity prices, drilling and operating costs and discount rates, as a result, valuation of the impaired assets was a Level 3 measurement. For the year ended December 31, 2014, the Company recognized pretax impairment charges on proved oil and gas properties of $180.7 million, which are included in the impairment of long-lived assets caption in the Statements of Consolidated Income. This impairment included charges of $105.2 million on proved properties in its Permian Basin of Texas primarily due to the decline in commodity prices and $75.5 million on proved properties in its Utica Shale of Ohio as a result of insufficient recovery of hydrocarbons to support continued development along with the decline in commodity prices. For the years ended December 31, 2013 and 2012, 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 year ended December 31, 2014, unproved property impairments relating to the determination that the properties will not yield proved reserves were $86.6 million and are included in the impairment of long-lived assets in the Statements of Consolidated Income. This impairment relates to the Company’s decision to stop development of properties in its Utica Shale of Ohio described above. In addition, unproved oil and gas property impairments primarily as a result of lease expirations prior to drilling of $14.6 million, $14.2 million and $5.5 million are included in exploration expense for the years ended December 31, 2014, 2013 and 2012, respectively. Unproved properties had a net book value of $824.5 million and $450.2 million at December 31, 2014 and 2013, respectively.
	At December 31, 2014, the Company had $9.0 million of capitalized exploratory well costs, there were no capitalized exploratory wells costs at December 31, 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). The Company capitalized internal costs of $40.0 million, $32.5 million and $27.2 million in 2014, 2013 and 2012, respectively.
	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. No impairment of any long-lived asset other than proved and unproved oil and gas properties was recorded in 2014, 2013 and 2012.
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 consist of 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,
		2014			2013			2012
		(Thousands)
	Net Revenues	$	267,997		$	184,767		$	131,184
	Operating expenses	$	89,617		$	71,517		$	66,202
	The following table presents the regulated net property, plant and equipment included in EQT Midstream:
		As of December 31,
		2014			2013
		(Thousands)
	Property, plant & equipment	$	1,160,696		$	1,015,118
	Accumulated depreciation and amortization	(188,884		)	(158,533		)
	Net property, plant & equipment	$	971,812		$	856,585
	The regulatory assets associated with deferred taxes of $15.2 million and $13.3 million as of December 31, 2014 and 2013, 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 the allowance for funds used during the construction 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 & Financial Risk Committee (HFRC) and reviewed by the Audit Committee of the Board of Directors. The HFRC is composed of the president and chief executive officer, 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 may also use 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 remains 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.
	Effective October 1, 2013, the Company de-designated all derivative commodity instruments that were previously designated and qualified as fair value hedges. For a derivative instrument that had been designated and qualified as a fair value hedge, the change in the fair value for the instrument was recognized as a portion of operating revenues in the Statements of Consolidated Income each period. In addition, the change in the fair value of the hedged item (natural gas inventory) was recognized as a portion of operating revenues in the Statements of Consolidated Income. The Company elected to exclude the spot/forward differential from the assessment of effectiveness of the fair value 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.
Allowance for Funds Used During Construction	Allowance for Funds Used During Construction:   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 $5.8 million, $4.3 million and $3.9 million for the years ended December 31, 2014, 2013 and 2012, 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 $3.2 million, $1.2 million and $6.8 million for the years ended December 31, 2014, 2013 and 2012, 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 transportation 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 income statement, 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	Investments:  EQT owns a 2.0% general partner interest, all incentive distribution rights and a 34.4% limited partner interest in the Partnership. The Partnership is consolidated in EQT’s consolidated financial statements because EQT controls the Partnership through its ownership of the general partner and the rights provided to the general partner under the Partnership’s partnership agreement. EQT records the noncontrolling interest of the public limited partners in EQT’s financial statements. 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.  These investments are classified as equity in nonconsolidated investments on the Consolidated Balance Sheets.
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. Some transportation costs incurred by the Company are marketed for resale and 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 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 credit worthiness 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.  Accordingly, actual results may differ from these estimates under different assumptions or conditions.
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 15.
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.
	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,
		2014			2013
		(Thousands)
	Asset retirement obligation as of beginning of period	$	116,045		$	109,034
	Accretion expense	9,420			8,342
	Liabilities incurred	16,953			2,510
	Liabilities settled	(14,025		)	(3,353		)
	Revisions in estimated cash flows	11,693			(488		)
	Asset retirement obligation as of end of period	$	140,086		$	116,045
	In connection with the exchange of certain assets with Range Resources Corporation (Range) (see Notes 7 and 9 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	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 the Partnership 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, which for the Partnership gives effect to the incentive distribution rights declared for each period. See Note 3 for further discussion of noncontrolling interests related to the Partnership.
Recently Issued Accounting Standards	Recently Issued Accounting Standards: In May 2014, the Financial Accounting Standards Board 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 replace most of the existing revenue recognition requirements in United States GAAP when it becomes effective. The guidance in ASU No. 2014-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.
Subsequent Events	Subsequent Events: The Company has evaluated subsequent events through the date of the financial statement issuance.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Property, Plant and Equipment	The Company’s property, plant and equipment consist of the following:
		As of December 31,
		2014			2013
		(Thousands)
	Oil and gas producing properties, successful efforts method	$	10,263,547		$	8,152,951
	Accumulated depletion	(2,874,257		)	(2,134,953		)
	Net oil and gas producing properties	7,389,290			6,017,998
	Midstream plant	3,234,370			2,807,165
	Accumulated depreciation and amortization	(606,998		)	(547,991		)
	Net midstream plant	2,627,372			2,259,174
	Other properties, at cost less accumulated depreciation	60,152			56,590
	Net property, plant and equipment	$	10,076,814		$	8,333,762
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,
		2014			2013			2012
		(Thousands)
	Net Revenues	$	267,997		$	184,767		$	131,184
	Operating expenses	$	89,617		$	71,517		$	66,202
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,
		2014			2013
		(Thousands)
	Property, plant & equipment	$	1,160,696		$	1,015,118
	Accumulated depreciation and amortization	(188,884		)	(158,533		)
	Net property, plant & equipment	$	971,812		$	856,585
Schedule of other current liabilities	Other current liabilities as of December 31, 2014 and 2013 are detailed below.
		December 31,
		2014			2013
		(Thousands)
	Incentive compensation	$	70,826		$	65,053
	Taxes other than income	52,035			39,073
	Accrued interest payable	37,349			29,379
	All other accrued liabilities	40,239			18,763
	Total other current liabilities	$	200,449		$	152,268
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,
		2014			2013
		(Thousands)
	Asset retirement obligation as of beginning of period	$	116,045		$	109,034
	Accretion expense	9,420			8,342
	Liabilities incurred	16,953			2,510
	Liabilities settled	(14,025		)	(3,353		)
	Revisions in estimated cash flows	11,693			(488		)
	Asset retirement obligation as of end of period	$	140,086		$	116,045
Schedule of components of accumulated OCI, net of tax	The components of accumulated OCI, net of tax, are as follows:
		As of December 31,
		2014			2013
		(Thousands)
	Net gain from natural gas hedging transactions	$	217,121		$	61,699
	Net loss from interest rate swaps	(987		)	(1,132		)
	Pension and other post-retirement benefits liability adjustment	(16,640		)	(15,864		)
	Accumulated OCI	$	199,494		$	44,703

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014		2013		2012
		(Thousands)
	Operating revenues	$	—	$	332,947	$	314,821
	Income from discontinued operations before income taxes	2,377		251,378		81,328
	Income taxes	1,006		159,535		33,835
	Income from discontinued operations, net of tax	$	1,371	$	91,843	$	47,493

Financial_Information_by_Busin1

Financial Information by Business Segment (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of revenue from external customers and operating income	(a)   This amount reflects the reclassification of third-party transportation and processing costs from operating revenues to transportation and processing costs at the consolidated level.
	(b)   Includes entries to eliminate intercompany natural gas sales from EQT Production to EQT Midstream. The Company also had $37.6 million and $36.8 million for the years ended December 31, 2013 and 2012, respectively, of intercompany eliminations for transmission and storage services between EQT Midstream and Distribution that have been recast to discontinued operations as a result of the Equitable Gas Transaction. Additionally, the Company had $2.6 million and $11.7 million for the years ended December 31, 2013 and 2012, respectively, of intercompany eliminations for retail business activity between Distribution and EQT Midstream that have been recast to discontinued operations. These recast adjustments had no impact on the Company’s net income for any period.
	(c)   Gain on sale / exchange of assets of $6.8 million and $19.6 million are included in EQT Midstream operating income for 2014 and 2013, respectively.  Gain on sale / exchange of assets of $27.4 million are included in EQT Production operating income for 2014. See Note 7. Impairment of long-lived assets of $267.3 million are included in EQT Production operating income for 2014. See Note 1.
	(d)  Unallocated expenses consist primarily of a $20.0 million contribution to the EQT Foundation in 2014, incentive compensation, administrative costs and in 2013 and 2012, corporate overhead charges previously allocated to the Distribution segment that were reclassified to Headquarters as part of the recast of those periods to reflect the discontinued operations presentation requirements.
		Years Ended December 31,
		2014			2013			2012
					(Thousands)
	Revenues from external customers:
	EQT Production	$	1,612,730		$	1,168,657		$	793,773
	EQT Midstream	699,083			614,042			505,498
	Third-party transportation and processing costs (a)	200,562			142,281			126,783
	Less intersegment revenues, net (b)	(42,665		)	(62,969		)	(48,832		)
	Total	$	2,469,710		$	1,862,011		$	1,377,222
	EQT Production (c)	$	505,950		$	371,245		$	187,913
	EQT Midstream (c)	384,309			328,782			237,324
	Unallocated expenses (d)	(36,864		)	(45,423		)	(35,608		)
	Total operating income	$	853,395		$	654,604		$	389,629
	Reconciliation of operating income to income from continuing operations:
	Other income	$	6,853		$	9,242		$	15,536
	Interest expense	136,537			142,688			184,786
	Income taxes	214,092			175,186			71,461
	Income from continuing operations	$	509,619		$	345,972		$	148,918
Schedule of segment assets
		As of December 31,
		2014			2013
		(Thousands)
	Segment assets:
	EQT Production	$	8,153,199		$	6,359,065
	EQT Midstream	2,709,052			2,514,429
	Total operating segments	10,862,251			8,873,494
	Headquarters assets, including cash and short-term investments	1,202,649			918,559
	Total assets	$	12,064,900		$	9,792,053
Schedule of depreciation, depletion and amortization and expenditures for segment assets
		Years Ended December 31,
		2014			2013			2012
					(Thousands)
	Depreciation, depletion and amortization:
	EQT Production	$	592,855		$	578,641		$	409,628
	EQT Midstream	87,034			75,032			64,782
	Other	(591		)	(541		)	207
	Total	$	679,298		$	653,132		$	474,617
	Expenditures for segment assets: (e)
	EQT Production (f)	$	2,441,486		$	1,423,185		$	991,775
	EQT Midstream	455,359			369,399			375,731
	Other	3,341			4,292			3,134
	Total	$	2,900,186		$	1,796,876		$	1,370,640
	(e) Includes non-cash capital expenditures of $99.3 million, $70.2 million and $24.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, for certain labor overhead costs including a portion of non-cash stock-based compensation expense and non-cash capital expense accruals that had not yet been paid at the respective year-end.
	(f)   Expenditures for segment assets in the EQT Production segment include $724.4 million, $186.2 million and $134.6 million for property acquisitions in 2014, 2013 and 2012, respectively.  Included within the $724.4 million of property acquisitions for the year ended December 31, 2014 is $349.2 million of non-cash capital expenditures for the exchange of assets with Range Resources Corporation (described in Note 7).

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives designated and not designated as hedging instruments	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,
		2014			2013			2012
					(Thousands)
	Commodity derivatives designated as cash flow hedges
	Amount of gain recognized in OCI (effective portion), net of tax	$	156,207		$	10,669		$	86,259
	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 (loss) gain reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	(15,950		)	87,158			180,137
	Amount of gain (loss) recognized in operating revenues (ineffective portion) (a)	24,774			(21,335		)	(75		)
	Interest rate derivatives designated as cash flow hedges
	Amount of loss recognized in OCI (effective portion), net of tax	$	—		$	—		$	(7,138	)
	Amount of loss reclassified from accumulated OCI, net of tax, into interest expense due to forecasted transactions no longer being probable	—			—			(13,266		)
	Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	(145		)	(144		)	(241		)
	Commodity derivatives designated as fair value hedges (b)
	Amount of (loss) gain recognized in operating revenues for fair value commodity contracts	$	—		$	(1,341	)	$	3,878
	Fair value gain recognized in operating revenues for inventory designated as hedged item	—			386			3,292
	Derivatives not designated as hedging instruments
	Amount of gain recognized in operating revenues	$	80,942		$	2,834		$	2,176
	(a)         No amounts have been 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. For the year ended December 31, 2012, the net impact on operating revenues consisted of a $7.6 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.4 million loss due to changes in basis.
Asset and liability derivatives
		As of December 31,
		2014			2013
		(Thousands)
	Asset derivatives
	Commodity derivatives designated as hedging instruments	$	—		$	104,430
	Commodity derivatives not designated as hedging instruments	458,460			3,217
	Total asset derivatives	$	458,460		$	107,647
	Liability derivatives
	Commodity derivatives designated as hedging instruments	$	—		$	27,618
	Commodity derivatives not designated as hedging instruments	22,942			2,033
	Total liability derivatives	$	22,942		$	29,651
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, 2014 and 2013.
	As of December 31, 2014	Derivative			Derivative			Margin			Derivative
		instruments,			instruments			deposits			instruments,
		recorded in the			subject to			remitted to			net
		Consolidated			master			counterparties
		Balance			netting
		Sheet, gross			agreements
		(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	)	$	—
	As of December 31, 2013	Derivative			Derivative			Margin			Derivative
		instruments,			instruments			deposits			instruments,
		recorded in the			subject to			remitted to			net
		Consolidated			master			counterparties
		Balance			netting
		Sheet, gross			agreements
		(Thousands)
	Asset derivatives:
	Derivative instruments, at fair value	$	107,647		$	(20,843	)	$	—		$	86,804
	Liability derivatives:
	Derivative instruments, at fair value	$	29,651		$	(20,843	)	$	(266	)	$	8,542

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Derivative instrument 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	31-Dec-14		Quoted			Significant		Significant
				prices in			other		unobservable
				active			observable		inputs
				markets for			inputs		(Level 3)
				identical			(Level 2)
				assets
				(Level 1)
		(Thousands)
	Assets
	Derivative instruments, at fair value	$	458,460	$	—		$	458,460	$	—
	Liabilities
	Derivative instruments, at fair value	$	22,942	$	132		$	22,810	$	—
				Fair value measurements at reporting date using
	Description	31-Dec-13		Quoted			Significant		Significant
				prices in			other		unobservable
				active			observable		inputs
				markets for			inputs		(Level 3)
				identical			(Level 2)
				assets
				(Level 1)
		(Thousands)
	Assets
	Derivative instruments, at fair value	$	107,647	$	240		$	107,407	$	—
	Liabilities
	Derivative instruments, at fair value	$	29,651	$	315		$	29,336	$	—
Fair value measurements using significant unobservable inputs (Level 3)
		Fair value measurements using significant
		unobservable inputs
		(Level 3)
		Derivative instruments, at fair value, net
		Years Ended December 31,
		2014		2013
		(Thousands)
	Balance at January 1	$	—	$	90,714
	Total gains or losses:
	Included in earnings	—		640
	Included in OCI	—		(2,554		)
	Purchases	—		—
	Settlements	—		(34,381		)
	Transfers in and/or out of Level 3	—		(54,419		)
	Balance at December 31	$	—	$	—

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2012
		(Thousands)
	Current:
	Federal	$	164,935		$	100,796		$	3,771
	State	17,136			46,758			229
	Subtotal	182,071			147,554			4,000
	Deferred:
	Federal	38,357			51,767			56,551
	State	(6,336		)	(23,940		)	11,014
	Subtotal	32,021			27,827			67,565
	Amortization of deferred investment tax credit	—			(195		)	(104		)
	Total income taxes	$	214,092		$	175,186		$	71,461
Reconciliation of income tax expense to amount computed at the federal statutory rate	Income tax expense differs from amounts computed at the federal statutory rate of 35% on pre-tax income as follows:
		Years Ended December 31,
		2014			2013			2012
		(Thousands)
	Tax at statutory rate	$	253,299		$	182,406		$	77,133
	State income taxes	7,020			16,180			2,869
	Noncontrolling partners’ share of Partnership earnings	(43,409		)	(16,535		)	(4,571		)
	Other	(2,818		)	(6,865		)	(3,970		)
	Income tax expense	$	214,092		$	175,186		$	71,461
	Effective tax rate	29.6		%	33.6		%	32.4		%
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):
		2014			2013			2012
		(Thousands)
	Balance at January 1	$	57,087		$	17,858		$	30,730
	Additions based on tax positions related to current year	1,195			49,289			2,165
	Additions for tax positions of prior years	93			—			2,320
	Settlements	—			—			—
	Reductions for tax positions of prior years	(1,418		)	(790		)	(12,235		)
	Lapse of statute of limitations	—			(9,270		)	(5,122		)
	Balance at December 31	$	56,957		$	57,087		$	17,858
Summary of net deferred income tax liabilities (assets)	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,
		2014			2013
		(Thousands)
	Deferred income taxes:
	Total deferred income tax assets .	$	(961,556	)	$	(612,705	)
	Total deferred income tax liabilities	2,690,492			2,237,465
	Total net deferred income tax liabilities	1,728,936			1,624,760
	Total deferred income tax liabilities (assets)
	Drilling and development costs expensed for income tax reporting	1,391,156			1,190,357
	Tax depreciation in excess of book depreciation	1,154,082			1,018,255
	Accumulated OCI	130,770			28,597
	Post-retirement benefits	3,146			256
	Incentive compensation	(65,086		)	(60,863		)
	Net operating loss carryforwards	(212,718		)	(358,964		)
	Investment in Partnership	(336,394		)	(2,801		)
	Alternative minimum tax credit carryforward	(412,345		)	(246,157		)
	Other	11,338			(324		)
	Total excluding valuation allowances	1,663,949			1,568,356
	Valuation allowance	64,987			56,404
	Total (including amounts classified as current assets of $21,934 and $31,005, respectively)	$	1,728,936		$	1,624,760

Equity_in_Nonconsolidated_Inve1

Equity in Nonconsolidated Investments (Tables)	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity in the nonconsolidated investments	The following table summarizes the Company’s equity in the nonconsolidated investment:
				Interest	Ownership as of		As of December 31,
	Investees	Location		Type	December 31, 2014		2014				2013
							(Thousands)
	Nora Gathering, LLC (Nora LLC)	USA		Joint	—		$	—			$	128,983
Schedule of summarized balance sheet for nonconsolidated investments accounted for under the equity method of accounting	Summarized Balance Sheets
		As of December 31,
		2014			2013
		(Thousands)
	Current assets	$	—		$	27,014
	Noncurrent assets	—			239,583
	Total assets	$	—		$	266,597
	Current liabilities	$	—		$	8,529
	Stockholders’ equity	—			258,068
	Total liabilities and stockholders’ equity	$	—		$	266,597
Schedule of summarized Statements of Income for nonconsolidated investments accounted for under the equity method of accounting	Summarized Statements of Income
		Years Ended December 31,
		2014			2013				2012
		(Thousands)
	Revenues	$	19,924		$	45,040			$	47,888
	Operating expenses	13,155			29,810				35,596
	Net income	$	6,769		$	15,230			$	12,292

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Current and Noncurrent [Abstract]
Long-Term Debt
		As of December 31,
		2014		2013
		(Thousands)
	7.76% notes, due 2015 thru 2016	$	10,700	$	18,316
	5.00% notes, due October 1, 2015	150,000		150,000
	5.15% notes, due March 1, 2018	200,000		200,000
	6.50% notes, due April 1, 2018	500,000		500,000
	8.13% notes, due June 1, 2019	700,000		700,000
	4.88% notes, due November 15, 2021	750,000		750,000
	4.00% EQT Midstream Partners notes, due August 1, 2024	500,000		—
	7.75% debentures, due July 15, 2026	115,000		115,000
	Medium-term notes:
	7.3% to 7.6% Series B, due 2015 thru 2023	20,000		20,000
	7.6% Series C, due 2018	8,000		8,000
	8.7% to 9.0% Series A, due 2020 thru 2021	35,200		40,200
		2,988,900		2,501,516
	Less debt payable within one year	166,011		11,162
	Total long-term debt	$	2,822,889	$	2,490,354

Pension_and_Other_PostRetireme1

Pension and Other Post-Retirement Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule of funded status and amounts recognized for defined benefit pension and other post-retirement benefit plans	Refer to Note 2 for further information related to the Equitable Gas Transaction.
		For the Years Ended December 31,
		2014				2013				2014			2013
		Pension Benefits								Other Benefits
		(Thousands)
	Change in benefit obligation:
	Benefit obligation at beginning of year	$	21,828			$	63,270			$	18,253		$	36,255
	Service cost	350				500				669			905
	Interest cost	820				1,935				693			1,110
	Amendments	—				—				227			—
	Actuarial loss (gain)	2,412				(3,038		)		1,190			(2,355		)
	Benefits paid	(1,988		)		(5,269		)		(2,291		)	(3,961		)
	Expenses paid	(262		)		(493		)		—			—
	Divestitures	—				(34,410		)		—			(13,701		)
	Settlements	(1,456		)		(667		)		—			—
	Benefit obligation at end of year	$	21,704			$	21,828			$	18,741		$	18,253
	Change in plan assets:
	Fair value of plan assets at beginning of year	$	20,089			$	46,984			$	493		$	165
	Actual gain on plan assets	1,217				7,304				—			—
	Contributions	723				2,639				330			328
	Benefits paid	(1,988		)		(5,269		)		—			—
	Expenses paid	(262		)		(493		)		—			—
	Divestitures	—				(30,409		)		—			—
	Settlements	(1,456		)		(667		)		—			—
	Fair value of plan assets at end of year	18,323				20,089				823			493
	Funded status at end of year	$	(3,381	)		$	(1,739	)		$	(17,918	)	$	(17,760	)
Schedule of amounts recognized in statement of financial position
	Amounts recognized in the statement of financial position consist of:
	Current liabilities	$	—			$	—			$	(924	)	$	(1,341	)
	Noncurrent liabilities	(3,381		)		(1,739		)		(16,994		)	(16,419		)
	Net amounts recognized	$	(3,381	)		$	(1,739	)		$	(17,918	)	$	(17,760	)
	Amounts recognized in accumulated OCI, net of tax, consist of:
	Net loss	$	8,082			$	7,524			$	8,273		$	8,234
	Net prior service (credit)	—				—				285			106
	Net amount recognized	$	8,082			$	7,524			$	8,558		$	8,340
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,
		2014				2013				2012			2014			2013			2012
		Pension Benefits											Other Benefits
		(Thousands)
	Components of net periodic benefit cost:
	Service cost	$	350			$	500			$	500		$	669		$	905		$	737
	Interest cost	820				1,935				2,448			693			1,110			1,427
	Expected return on plan assets	(1,377		)		(3,323		)		(3,712		)	—			—			—
	Amortization of prior service cost	—				—				—			(446		)	(845		)	(845		)
	Recognized net actuarial loss	709				2,306				1,880			879			1,760			1,671
	Settlement loss and special termination benefits	879				381				725			—			—			—
	Subtotal	1,381				1,799				1,841			1,795			2,930			2,990
	Net periodic benefit cost of discontinued operations	—				1,552				1,586			—			1,356			1,288
	Net periodic benefit cost	$	1,381			$	247			$	255		$	1,795		$	1,574		$	1,702
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,
		2014				2013				2012			2014			2013			2012
		Pension Benefits											Other Benefits
		(Thousands)
	Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
	Net loss	$	558			$	712			$	261		$	39		$	2,147		$	494
	Net prior service cost	—				—				—			179			416			330
	Total recognized in OCI, net of tax	$	558			$	712			$	261		$	218		$	2,563		$	824
	Total recognized in net periodic benefit cost and OCI, net of tax	$	1,939			$	959			$	2,102		$	2,013		$	4,137		$	3,814
Schedule of 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,
		2014		2013		2014		2013
		Pension Benefits				Other Benefits
	Discount rate	3.60%		4.00%		3.60%		4.00%
	Rate of compensation increase	N/A		N/A		N/A		N/A
Schedule of 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,
		2014			2013			2014			2013
		Pension Benefits						Other Benefits
	Discount rate	4	%		3.25	%		4	%		3.25	%
	Expected return on plan assets	7.75	%		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											One-Percentage-Point
		Increase											Decrease
		2014				2013				2012			2014			2013			2012
		(Thousands)
	Increase (decrease) to total of service and interest cost components	$	13			$	25			$	32		$	(14	)	$	(26	)	$	(32	)
	Increase (decrease) to post-retirement benefit obligation	$	228			$	220			$	711		$	(229	)	$	(223	)	$	(688	)
Schedule of the entity's asset allocation	The asset allocation for the Retirement Plan at December 31, 2014 and 2013 and target allocation for January 2013 - October 2014 by asset category are as follows:
		Target Allocation		Percentage of Plan Assets
				at December 31,
	Asset Category	January 2013 - October 2014		2014			2013
	Domestic broadly diversified equity securities	40% - 60%		26	%		42	%
	Fixed income securities	20% - 50%		63	%		29	%
	International broadly diversified equity securities	5% - 15%		8	%		7	%
	Alternative fixed income securities	0% - 10%		—			4	%
	Cash and equivalent investments	0% - 15%		3	%		18	%
				100	%		100	%

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Income by Component (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
		Year Ended December 31, 2014
		Natural gas cash				Interest rate				Pension and				Accumulated
		flow hedges, net				cash flow				other post-				OCI (loss), net
		of tax				hedges, net				retirement				of tax
						of tax				benefits
										liability
										adjustment,
										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
		flow hedges, net				cash flow				other post-				OCI (loss), net
		of tax				hedges, net				retirement				of tax
						of tax				benefits
										liability
										adjustment,
										net of tax
		(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 5 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 13 for additional information.

Common_Stock_and_Earnings_Per_1

Common Stock and Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Reserved Authorized and Unissued Common Stock	At December 31, 2014, shares of EQT’s authorized and unissued common stock were reserved as follows:
		(Thousands)
	Possible future acquisitions	20,457
	Stock compensation plans	16,236
	Total	36,693
Schedule of Earnings Per Share, Basic and Diluted
			Years Ended December 31,
			2014		2013		2012
			(Thousands except per share amounts)
	Basic earnings per common share:
	Net income attributable to EQT Corporation		$	386,965	$	390,572	$	183,395
	Average common shares outstanding		151,553		150,574		149,619
	Basic earnings per common share		$	2.55	$	2.59	$	1.23
	Diluted earnings per common share:
	Net income attributable to EQT Corporation		$	386,965	$	390,572	$	183,395
	Average common shares outstanding		151,553		150,574		149,619
	Potentially dilutive securities:
	Stock options and awards (a)		960		1,213		887
	Total		152,513		151,787		150,506
	Diluted earnings per common share		$	2.54	$	2.57	$	1.22
	(a)         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. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 281,528 shares for the year ended December 31, 2012

ShareBased_Compensation_Plans_

Share-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based compensation expense	Share-based compensation expense recorded by the Company was as follows:
			Years Ended December 31,
			2014				2013			2012
			(Thousands)
	2010 Executive Performance Incentive Programs		$	—			$	—		$	1,940
	2012 Executive Performance Incentive Program		7,743				6,739			10,633
	2013 Executive Performance Incentive Program		8,208				6,602			—
	2014 Executive Performance Incentive Program		9,104				—			—
	2010 Stock Incentive Award Program		—				—			4,022
	2011 Volume and Efficiency Program		—				13,834			5,286
	2011 EQT Value Driver Award Program		—				—			3,033
	2012 EQT Value Driver Award Program		—				2,327			11,557
	2013 EQT Value Driver Award Program		4,403				13,050			—
	2014 EQT Value Driver Award Program		11,510				—			—
	2014 EQM Value Driver Award Program		2,378				—			—
	Restricted stock awards		4,688				3,033			2,007
	Non-qualified stock options		3,002				3,805			3,580
	Other programs, including non-employee director awards		(409		)		9,154			3,763
	Total share-based compensation expense		$	50,627			$	58,544		$	45,821
List of Executive Performance Incentive Program Peer Companies	The peer companies for the 2014 EPIP 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.
	The peer companies for the 2013 EPIP 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.
	The peer companies for the 2012 EPIP are as follows:
	Cabot Oil & Gas Corp.	National Fuel Gas Company	Sempra Energy
	Chesapeake Energy Corp.	NStar Electric Co.	SM Energy Company
	Cimarex Energy Co.	ONEOK, Inc.	Southwestern Energy Company
	CONSOL Energy Inc.	Penn Virginia Corp.	Spectra Energy Corp
	Energen Corp.	Pioneer Natural Resources Company	Ultra Petroleum Corp.
	EOG Resources, Inc.	Plains Exploration & Production Co.	Whiting Petroleum Corp.
	EXCO Resources, Inc.	Questar Corp.	The Williams Companies, Inc.
	MarkWest Energy Partners, L.P.	Quicksilver Resources Inc.
	MDU Resources Group, Inc.	Range Resources Corp.
Summary of restricted stock awards activity during the period	A summary of restricted stock activity as of December 31, 2014, and changes during the year then ended, is presented below:
	Restricted Stock		Non-			Weighted			Aggregate
			Vested			Average			Fair Value
			Shares			Fair Value
	Outstanding at January 1, 2014		182,378			$	61.98		$	11,302,992
	Granted		89,500			$	94.91		8,494,746
	Vested		(27,310	)		$	53.82		(1,469,604		)
	Forfeited		(14,578	)		$	75.64		(1,102,723		)
	Outstanding at December 31, 2014		229,990			$	74.9		$	17,225,411
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,
			2014		2013		2012
	Risk-free interest rate		1.72%		0.76%		0.89%
	Dividend yield		0.15%		0.22%		1.64%
	Volatility factor		24.80%		31.69%		31.44%
	Expected term		5 years		5 years		5 years
Summary of option activity	A summary of option activity as of December 31, 2014, and changes during the year then ended, is presented below:
	Non-qualified Stock Options		Shares			Weighted		Weighted	Aggregate
						Average		Average	Intrinsic
						Exercise		Remaining	Value
						Price		Contractual
								Term
	Outstanding at January 1, 2014		1,482,001			$49.77
	Granted		133,500			$89.78
	Exercised		(277,033	)		$48.27
	Forfeited		—			$—
	Outstanding at December 31, 2014		1,338,468			$54.08		6.35 years	$30,823,027
	Exercisable at December 31, 2014		1,079,968			$49.09		5.83 years	$28,733,027

Interim_Financial_Information_1

Interim Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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 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)
	2014 (a)
	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	)
	2013 (a)
	Operating revenues	$	415,883		$	473,093	$	479,606	$	493,429
	Operating income	144,479			161,980		167,064		181,081
	Amounts attributable to EQT Corporation:
	Income from continuing operations	69,131			81,466		86,199		61,933
	Income from discontinued operations	31,124			5,390		2,057		53,272
	Net income attributable to EQT Corporation	$	100,255		$	86,856	$	88,256	$	115,205
	Earnings per share of common stock attributable to EQT Corporation:
	Basic:
	Income from continuing operations	$	0.46		$	0.54	$	0.57	$	0.41
	Income from discontinued operations	0.21			0.04		0.02		0.35
	Net income	$	0.67		$	0.58	$	0.59	$	0.76
	Diluted:
	Income from continuing operations	$	0.46		$	0.54	$	0.57	$	0.4
	Income from discontinued operations	0.2			0.03		0.01		0.35
	Net income	$	0.66		$	0.57	$	0.58	$	0.75
	(a)                     The sum of the quarterly data in some cases may not equal the yearly total due to rounding.

Natural_Gas_Producing_Activiti1

Natural Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of cost incurred relating to property acquisition, exploration and development	The following table presents the costs incurred relating to natural gas, NGL and oil production activities (a):
			For the Years Ended December 31,
			2014				2013				2012
			(Thousands)
	At December 31:
	Capitalized costs		$	10,263,547			$	8,152,951			$	6,750,343
	Accumulated depreciation and depletion		2,874,257				2,134,953				1,572,775
	Net capitalized costs		$	7,389,290			$	6,017,998			$	5,177,568
	Costs incurred for the years ended December 31:
	Property acquisition:
	Proved properties (b)		$	231,322			$	90,390			$	16,965
	Unproved properties (c)		493,067				95,861				117,654
	Exploration (d)		16,023				4,285				4,827
	Development		1,697,501				1,230,301				850,854
	(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 acquisition in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake acquisition in 2013.
	(c)                    Amounts include $317.2 million for the purchase of Permian leases acquired in the Range acquisition in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake acquisition in 2013.
	(d)                     Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.
Results of Operations for Producing Activities	The following table presents the results of operations related to natural gas, NGL and oil production:
			For the Years Ended December 31,
			2014				2013				2012
			(Thousands)
	Revenues:
	Affiliated		$	4,761			$	5,912			$	3,433
	Nonaffiliated		1,607,969				1,162,745				790,340
	Production costs		133,488				108,091				96,155
	Exploration costs		21,665				18,483				10,370
	Depreciation, depletion and accretion		592,855				578,641				409,628
	Impairment of long-lived assets		267,339				—				—
	Income tax expense		238,057				183,060				109,660
	Results of operations from producing activities (excluding corporate overhead)		$	359,326			$	280,382			$	167,960
Schedule of the entity's proved reserves	All of the Company’s proved reserves are located in the United States.
			Years Ended December 31,
			2014			2013			2012
			(Millions of Cubic Feet)
	Natural Gas
	Proved developed and undeveloped reserves:
	Beginning of year		7,561,561			5,985,758			5,347,386
	Revision of previous estimates		(228,085	)		(375,887	)		(755,788	)
	Purchase of natural gas in place		44,867			472,798			—
	Sale of natural gas in place		(198,531	)		(455	)		(694	)
	Extensions, discoveries and other additions		3,040,938			1,844,840			1,654,228
	Production		(444,796	)		(365,493	)		(259,374	)
	End of year		9,775,954			7,561,561			5,985,758
	Proved developed reserves:
	Beginning of year		3,567,313			2,779,187			2,948,546
	End of year		4,257,377			3,567,313			2,779,187
			Years Ended December 31,
			2014			2013			2012
			(Thousands of Bbls)
	Oil (a)
	Proved developed and undeveloped reserves:
	Beginning of year		3,956			3,199			2,931
	Revision of previous estimates		(905	)		270			265
	Purchase of oil in place		2,165			—			—
	Sale of oil in place		(3	)		—			—
	Extensions, discoveries and other additions		241			757			268
	Production		(449	)		(270	)		(265	)
	End of year		5,005			3,956			3,199
	Proved developed reserves:
	Beginning of year		3,892			3,199			2,931
	End of year		5,005			3,892			3,199
	(a)                      One thousand Bbl equals approximately 6 million cubic feet (MMcf).
		Years Ended December 31,
		2014			2013
		(Thousands of Bbls)
	NGLs (a)
	Proved developed and undeveloped reserves:
	Beginning of year	127,162			—
	Revision of previous estimates	(11,306	)		94,296
	Purchase of NGLs in place	7,476			—
	Sale of NGLs in place	(18	)		—
	Extensions, discoveries and other additions	38,945			32,866
	Production	(6,765	)		—
	End of year	155,494			127,162
	Proved developed reserves:
	Beginning of year	65,837			—
	End of year	89,830			65,837
	(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:
			2014				2013				2012
			(Thousands)
	Future cash inflows (a)		$	30,428,815			$	25,912,542			$	15,250,019
	Future production costs		(4,868,079		)		(4,180,136		)		(3,070,957		)
	Future development costs		(5,052,195		)		(4,199,722		)		(3,082,053		)
	Future income tax expenses		(7,718,407		)		(6,533,817		)		(3,324,472		)
	Future net cash flow		12,790,134				10,998,867				5,772,537
	10% annual discount for estimated timing of cash flows		(7,980,106		)		(7,047,588		)		(3,617,378		)
	Standardized measure of discounted future net cash flows		$	4,810,028			$	3,951,279			$	2,155,159
	(a)	The majority of the Company’s production is sold through liquid trading points on interstate pipelines. 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 West Texas Intermediate (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.
		For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012 of $82.90 per Bbl of oil (first day of each month closing price for WTI less Appalachian Basin adjustment), $2.793 per Dth for Columbia Gas Transmission Corp., $2.785 per Dth for Dominion Transmission, Inc., $2.769 per Dth for the East Tennessee Natural Gas Pipeline, $2.782 per Dth for Texas Eastern Transmission Corp., $2.403 per Dth for the Tennessee, zone 4-300 Leg of Tennessee Gas Pipeline Company and $2.878 per Dth for the Tennessee LA 500 Leg of Tennessee Gas Pipeline Company.  For 2012, the West Virginia Marcellus reserves from Doddridge and Ritchie Counties were computed using an additional $0.591 and reserves from Wetzel County were computed using an additional $0.398 for revenues earned on NGLs that are produced from those reserves.  Revenues earned on NGLs that are produced from certain Kentucky reserves were computed using an additional $0.764.
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:
			2014				2013				2012
			(Thousands)
	Sales and transfers of natural gas and oil produced – net		$	(1,479,242	)		$	(1,060,566	)		$	(697,618	)
	Net changes in prices, production and development costs		(1,525,944		)		(292,533		)		(3,530,086		)
	Extensions, discoveries and improved recovery, less related costs		2,300,923				1,509,002				917,986
	Development costs incurred		1,023,075				1,319,135				548,852
	Purchase of minerals in place – net		72,139				348,608				—
	Sale of minerals in place – net		(146,476		)		(252		)		(807		)
	Revisions of previous quantity estimates		(222,195		)		106,170				(876,336		)
	Accretion of discount		578,676				343,502				622,072
	Net change in income taxes		(529,337		)		(1,031,105		)		1,127,272
	Timing and other		787,130				554,159				111,000
	Net increase (decrease)		858,749				1,796,120				(1,777,665		)
	Beginning of year		3,951,279				2,155,159				3,932,824
	End of year		$	4,810,028			$	3,951,279			$	2,155,159

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Narrative (Details) (USD $)	12 Months Ended			0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 22, 2013	Jul. 02, 2012
	segment
Segments:
Number of reportable segments	2
Reclassification:
Decrease in net cash provided by operating activities		$37.50	$11.70
Cash Equivalents:
Maximum original term of maturity for investments to be classified as cash or cash equivalents	3 months
Inventories:
Losses recorded for lower of cost or market adjustments	$3.20	$0.40	$7
EQT Midstream Partners, LP
Principles of Consolidation:
Ownership percentage				44.60%	59.40%
EQT Midstream Partners, LP | General Partner
Principles of Consolidation:
Ownership percentage	2.00%
EQT Midstream Partners, LP | Limited Partner [Member]
Principles of Consolidation:
Ownership percentage	34.40%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Oil and gas producing properties, successful efforts method	$10,263,547	[1]	$8,152,951	[1]	$6,750,343	[1]
Accumulated depletion	-2,874,257	[1]	-2,134,953	[1]	-1,572,775	[1]
Net oil and gas producing properties	7,389,290	[1]	6,017,998	[1]	5,177,568	[1]
Midstream plant	13,608,151		11,062,136
Accumulated depreciation and amortization	-3,531,337		-2,728,374
Net property, plant and equipment	10,076,814		8,333,762
EQT Midstream
Property, Plant and Equipment [Line Items]
Midstream plant	3,234,370		2,807,165
Accumulated depreciation and amortization	-606,998		-547,991
Net property, plant and equipment	2,627,372		2,259,174
Other Properties
Property, Plant and Equipment [Line Items]
Net property, plant and equipment	$60,152		$56,590
[1]	Amounts exclude capital expenditures for facilities and information technology.

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Property, Plant and Equipment (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Capitalized internal costs of oil and gas producing properties under the successful efforts method	$108,500,000	$93,500,000	$72,100,000
Capitalized interest costs	35,000,000	22,900,000	15,600,000
Depletion rate of oil and gas producing properties under successful efforts method (in dollars per Mcfe)	1.22	1.5	1.52
Impairment charges on proved oil and gas properties	180,700,000
Undeveloped property impairments	14,600,000	14,200,000	5,500,000
Net book value of unproved properties	824,500,000	450,200,000
Capitalized exploratory well costs pending the determination of proved reserves	9,000,000	0
EQT Midstream
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Cost Capitalization, Internal Costs	40,000,000	32,500,000	27,200,000
Gathering and Transmission Systems [Member] | EQT Midstream | Minimum
Property, Plant and Equipment [Line Items]
Estimated service life	25 years
Gathering and Transmission Systems [Member] | EQT Midstream | Maximum
Property, Plant and Equipment [Line Items]
Estimated service life	60 years
Building [Member] | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life	35 years
Office Equipment [Member] | EQT Midstream | Minimum
Property, Plant and Equipment [Line Items]
Estimated service life	3 years
Office Equipment [Member] | EQT Midstream | Maximum
Property, Plant and Equipment [Line Items]
Estimated service life	7 years
Vehicles [Member] | EQT Midstream
Property, Plant and Equipment [Line Items]
Estimated service life	5 years
Computer Equipment [Member] | EQT Midstream | Minimum
Property, Plant and Equipment [Line Items]
Estimated service life	3 years
Computer Equipment [Member] | EQT Midstream | Maximum
Property, Plant and Equipment [Line Items]
Estimated service life	7 years
Permian Basin of Texas
Property, Plant and Equipment [Line Items]
Impairment charges on proved oil and gas properties	105,200,000
Utica Shale of Ohio
Property, Plant and Equipment [Line Items]
Impairment charges on proved oil and gas properties	75,500,000
Capitalized costs of undeveloped properties	$86,600,000

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Regulatory Accounting (Details) (EQT Midstream, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
EQT Midstream
Property, Plant and Equipment [Line Items]
Net Revenues	$267,997	$184,767	$131,184
Operating expenses	89,617	71,517	66,202
Property, plant & equipment	1,160,696	1,015,118
Accumulated depreciation and amortization	-188,884	-158,533
Net property, plant & equipment	$971,812	$856,585

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Regulatory Accounting (Narrative) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Accounting Policies [Abstract]
Regulatory assets associated with deferred taxes	$15.20	$13.30

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - Allowance for Funds Used During Construction (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Capitalized interest cost as part of allowance for funds used during construction	$5.80	$4.30	$3.90
AFUDC equity amounts capitalized	$3.20	$1.20	$6.80

Summary_of_Significant_Account9

Summary of Significant Accounting Policies - Other Current Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Other Current Liabilities:
Incentive compensation	$70,826	$65,053
Taxes other than income	52,035	39,073
Accrued interest payable	37,349	29,379
All other accrued liabilities	40,239	18,763
Total other current liabilities	$200,449	$152,268

Recovered_Sheet1

Summary of Significant Accounting Policies - Investments (Narrative) (Details)	0 Months Ended		12 Months Ended
	Jul. 22, 2013	Jul. 02, 2012	Dec. 31, 2014
Minimum
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership percentage used in applying equity method of accounting			20.00%
Maximum
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership percentage used in applying equity method of accounting			50.00%
EQT Midstream Partners
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership percentage	44.60%	59.40%
EQT Midstream Partners | General Partner
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership percentage			2.00%
EQT Midstream Partners | Limited Partner [Member]
Subsidiary of Limited Liability Company or Limited Partnership [Line Items]
Ownership percentage			34.40%

Recovered_Sheet2

Summary of Significant Accounting Policies - Income Taxes (Narrative) (Details)	Dec. 31, 2014
Accounting Policies [Abstract]
Tax benefit recognized in financial statements, percentage threshold	50.00%

Recovered_Sheet3

Summary of Significant Accounting Policies - Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset retirement obligations
Asset retirement obligation as of beginning of period	$116,045	$109,034
Accretion expense	9,420	8,342
Liabilities incurred	16,953	2,510
Liabilities settled	-14,025	-3,353
Revisions in estimated cash flows	11,693	-488
Asset retirement obligation as of end of period	$140,086	$116,045

Recovered_Sheet4

Summary of Significant Accounting Policies - Asset Retirement Obligations (Narrative) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Subsidiary or equity method investee
Liabilities settled	$14,025	$3,353
Liabilities incurred	16,953	2,510
Range Resources Corporation
Subsidiary or equity method investee
Liabilities settled	7,700
Liabilities incurred	$14,200

Recovered_Sheet5

Summary of Significant Accounting Policies - Accumulated other comprehensive income (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounting Policies [Abstract]
Net gain from natural gas hedging transactions	$217,121	$61,699
Net loss from interest rate swaps	-987	-1,132
Pension and other post-retirement benefits liability adjustment	-16,640	-15,864
Accumulated OCI	$199,494	$44,703	$99,547

Discontinued_Operations_Narrat

Discontinued Operations - Narrative (Details) (Equitable Gas and Homeworks, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equitable Gas and Homeworks
Discontinued operations
Additional cash proceeds as a result of post-closing purchase price adjustments	$7.40
Discontinued Operation, Amount of Adjustment to Prior Period Gain (Loss) on Disposal, Net of Tax	2.9
Gain on sale of business		43.8
Cash payment received	748
Preliminary estimated fair value of consideration received	140.9
Preliminary estimated fair value of other contractual assets received as consideration	32.5
Income from discontinued operations, net of tax		122.5
Equitable Gas transaction costs		8.1	4.5
Write off of income tax related regulatory assets		$51.60

Discontinued_Operations_Discon

Discontinued Operations - Discontinued Operations Activity (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discontinued Operations and Disposal Groups [Abstract]
Operating revenues																	$0	$332,947	$314,821
Income from discontinued operations before income taxes																	2,377	251,378	81,328
Income taxes																	1,006	159,535	33,835
Income from discontinued operations, net of tax	($401)	[1]	$0	[1]	$1,876	[1]	($104)	[1]	$53,272	[1]	$2,057	[1]	$5,390	[1]	$31,124	[1]	$1,371	$91,843	$47,493
[1]	The sum of the quarterly data in some cases may not equal the yearly total due to rounding.

EQT_Midstream_Partners_LP_Deta

EQT Midstream Partners, LP (Details) (USD $)	12 Months Ended			0 Months Ended			1 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	7-May-14	Jul. 22, 2013	Jul. 02, 2012	Aug. 31, 2014	Jan. 22, 2015
Subsidiary or equity method investee
Proceeds from offerings, net of underwriters' discount and estimated offering expenses	$902,467,000	$529,442,000	$276,780,000
Net income attributable to noncontrolling interests	124,025,000	47,243,000	13,016,000
Distributions paid to noncontrolling interest	67,819,000	32,781,000	5,031,000
Distributions to noncontrolling interests (in dollars per common unit)	$2.02	$1.55	$0.35
EQT Midstream Partners, LP
Subsidiary or equity method investee
Number of common units issued to the public in an offering (in shares)				12,362,500	12,650,000	14,375,000
Common units issued to the public in an offering as a percentage of outstanding equity						40.60%
Ownership percentage					44.60%	59.40%
Common units (in shares)	3,959,952				3,443,902	2,964,718
Subordinated units (in shares)	17,339,718				17,339,718	17,339,718
General partner interest	2.00%				2.00%	2.00%
Proceeds from offerings, net of underwriters' discount and estimated offering expenses				902,500,000	529,400,000
Offering expenses				34,000,000	20,900,000
Proceeds from sale of property, plant, and equipment				1,180,000,000
Limited partner's interest	34.40%
Debt issuance cost							4,800,000
Net income attributable to noncontrolling interests	124,000,000	47,200,000	13,000,000
Distributions paid to noncontrolling interest	67,800,000	32,800,000	5,000,000
EQT Midstream Partners, LP | Subsequent Event
Subsidiary or equity method investee
Subordinated units (in shares)								17,339,718
General partner interest								2.00%
Distribution declared per common and subordinated unit								$0.58
Distribution declared for general partner interest								800,000
General Partner's Share of Undistributed Earnings, Incentive Distribution Right Embedded in General Partner Interest								5,200,000
EQT Midstream Partners, LP | Senior Notes
Subsidiary or equity method investee
Interest rate							4.00%
Face amount							500,000,000
Net proceeds							492,300,000
Unamortized discount							$2,900,000
Equitrans
Subsidiary or equity method investee
Percentage of ownership contributed						100.00%

Financial_Information_by_Busin2

Financial Information by Business Segment - Revenue from External Customers and Operating Income (Details) (USD $)	3 Months Ended																12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Operating revenues	$703,194,000	[1]	$578,723,000	[1]	$526,168,000	[1]	$661,625,000	[1]	$493,429,000	[1]	$479,606,000	[1]	$473,093,000	[1]	$415,883,000	[1]	$2,469,710,000		$1,862,011,000		$1,377,222,000
Operating income	40,330,000	[1]	231,503,000	[1]	224,771,000	[1]	356,791,000	[1]	181,081,000	[1]	167,064,000	[1]	161,980,000	[1]	144,479,000	[1]	853,395,000		654,604,000		389,629,000
Reconciliation of operating income to income from continuing operations:
Other income																	6,853,000		9,242,000		15,536,000
Interest expense																	136,537,000		142,688,000		184,786,000
Income taxes																	214,092,000		175,186,000		71,461,000
Income from continuing operations																	509,619,000		345,972,000		148,918,000
Gain on sale / exchange of assets																	34,146,000		19,618,000		0
Impairment of long-lived assets	267,300,000																267,339,000		0		0
Contribution to EQT Foundation																	20,000,000
EQT
Reconciliation of operating income to income from continuing operations:
Gain on sale / exchange of assets																	27,400,000
Impairment of long-lived assets																	267,339,000		0		0
EQT Midstream
Reconciliation of operating income to income from continuing operations:
Gain on sale / exchange of assets																	6,800,000		19,600,000
Operating Segments | EQT
Segment Reporting Information [Line Items]
Operating revenues																	1,612,730,000		1,168,657,000		793,773,000
Operating income																	505,950,000	[2]	371,245,000	[2]	187,913,000	[2]
Operating Segments | EQT Midstream
Segment Reporting Information [Line Items]
Operating revenues																	699,083,000		614,042,000		505,498,000
Operating income																	384,309,000	[2]	328,782,000	[2]	237,324,000	[2]
Third-party transportation costs
Segment Reporting Information [Line Items]
Operating revenues																	200,562,000	[3]	142,281,000	[3]	126,783,000	[3]
Less intersegment revenues, net
Segment Reporting Information [Line Items]
Operating revenues																	-42,665,000	[4]	-62,969,000	[4]	-48,832,000	[4]
Less intersegment revenues, net | EQT Midstream
Reconciliation of operating income to income from continuing operations:
Intercompany eliminations for transmission and storage services																			37,600,000		36,800,000
Intercompany eliminations for retail business activity																			2,600,000		11,700,000
Unallocated expenses and Other
Segment Reporting Information [Line Items]
Operating income																	($36,864,000)	[5]	($45,423,000)	[5]	($35,608,000)	[5]
[1]	The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
[2]	Gain on sale / exchange of assets of $6.8 million and $19.6 million are included in EQT Midstream operating income for 2014 and 2013, respectively. Gain on sale / exchange of assets of $27.4 million are included in EQT Production operating income for 2014. See Note 7.
[3]	This amount reflects the reclassification of third-party transportation and processing costs from operating revenues to transportation and processing costs at the consolidated level.
[4]	Includes entries to eliminate intercompany natural gas sales from EQT Production to EQT Midstream. The Company also had $37.6 million and $36.8 million for the years ended December 31, 2013 and 2012, respectively, of intercompany eliminations for transmission and storage services between EQT Midstream and Distribution that have been recast to discontinued operations as a result of the Equitable Gas Transaction. Additionally, the Company had $2.6 million and $11.7 million for the years ended December 31, 2013 and 2012, respectively, of intercompany eliminations for retail business activity between Distribution and EQT Midstream that have been recast to discontinued operations. These recast adjustments had no impact on the Company’s net income for any period.
[5]	Unallocated expenses consist primarily of a $20.0 million contribution to the EQT Foundation in 2014, incentive compensation, administrative costs and in 2013 and 2012, corporate overhead charges previously allocated to the Distribution segment that were reclassified to Headquarters as part of the recast of those periods to reflect the discontinued operations presentation requirements.

Financial_Information_by_Busin3

Financial Information by Business Segment - Segment Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Segment Reporting Information [Line Items]
Total assets	$12,064,900	$9,792,053
Operating Segments
Segment Reporting Information [Line Items]
Total assets	10,862,251	8,873,494
Operating Segments | EQT
Segment Reporting Information [Line Items]
Total assets	8,153,199	6,359,065	5,675,500
Operating Segments | EQT Midstream
Segment Reporting Information [Line Items]
Total assets	2,709,052	2,514,429	2,046,600
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Total assets	$1,202,649	$918,559

Financial_Information_by_Busin4

Financial Information by Business Segment - Narrative (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Segment Reporting Information [Line Items]
Total assets	$12,064,900	$9,792,053
Operating Segments
Segment Reporting Information [Line Items]
Total assets	10,862,251	8,873,494
Operating Segments | EQT
Segment Reporting Information [Line Items]
Total assets	8,153,199	6,359,065	5,675,500
Operating Segments | EQT Midstream
Segment Reporting Information [Line Items]
Total assets	$2,709,052	$2,514,429	$2,046,600

Financial_Information_by_Busin5

Financial Information by Business Segment - Depreciation, Depletion and Amortization and Expenditures for Segment Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	$679,298,000		$653,132,000		$474,617,000
Expenditures for segment assets	2,900,186,000	[1]	1,796,876,000	[1]	1,370,640,000	[1]
Asset expenditures incurred not paid	99,300,000		70,200,000		24,000,000
Operating Segments | EQT
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	592,855,000		578,641,000		409,628,000
Expenditures for segment assets	2,441,486,000	[1],[2]	1,423,185,000	[1],[2]	991,775,000	[1],[2]
Asset expenditures incurred not paid	349,200,000
Expenditures for segment assets for property acquisitions	724,400,000		186,200,000		134,600,000
Operating Segments | EQT Midstream
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	87,034,000		75,032,000		64,782,000
Expenditures for segment assets	455,359,000	[1]	369,399,000	[1]	375,731,000	[1]
Corporate and Reconciling Items [Member]
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization	-591,000		-541,000		207,000
Expenditures for segment assets	$3,341,000	[1]	$4,292,000	[1]	$3,134,000	[1]
[1]	Includes non-cash capital expenditures of $99.3 million, $70.2 million and $24.0 million for the years ended December 31, 2014, 2013 and 2012, respectively, for certain labor overhead costs including a portion of non-cash stock-based compensation expense and non-cash capital expense accruals that had not yet been paid at the respective year-end.
[2]	Expenditures for segment assets in the EQT Production segment include $724.4 million, $186.2 million and $134.6 million for property acquisitions in 2014, 2013 and 2012, respectively. Included within the $724.4 million of property acquisitions for the year ended December 31, 2014 is $349.2 million of non-cash capital expenditures for the exchange of assets with Range Resources Corporation (described in Note 7).

Derivative_Instruments_Narrati

Derivative Instruments - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMBTU	MMcf
	MMcf
Derivative Instruments, Gain (Loss) [Line Items]
Deferred net gains in accumulated other comprehensive income (loss), net of tax	$217,100,000	$61,700,000
Net unrealized gains on derivative commodity instruments	153,200,000
Margin deposits with brokers	100,000	300,000
Additional collateral limit for below investment grade derivative instruments, as a percentage of the derivative liability	100.00%
Aggregate fair value of derivative instruments with credit-risk related contingencies	900,000
Collateral posted	0
Additional collateral for downgrade below investment grade	900,000
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Amount of gain recognized in OCI (effective portion), net of tax			7,100,000
Amount of (loss) gain reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)			23,300,000
Amount of reversal which had previously been deferred in accumulated OCI, net of tax			13,300,000
Commodity derivatives | Cash flow hedges
Derivative Instruments, Gain (Loss) [Line Items]
Swaptions granted to counterparties (in dth)	50,000
Pre-tax gain recognized in operating revenues for de-designation of derivative instruments related to sale of certain energy marketing contracts	28,000,000	1,000,000
Amount of gain recognized in OCI (effective portion), net of tax	156,207,000	10,669,000	86,259,000
Amount of (loss) gain reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	($15,950,000)	$87,158,000	$180,137,000
Absolute quantities of derivative commodity instruments that have been designated and qualify as cash flow or fair value hedges (in Bcf)	624,000	414,000

Derivative_Instruments_Designa

Derivative Instruments - Designated and Not Designated as Hedging Instruments (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
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	($16,735,000)
Interest rate derivatives designated as cash flow hedges
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense due to forecasted transactions no longer being probable	-16,735,000
Derivatives not designated as hedging instruments
Amount of gain recognized in operating revenues	80,942,000		2,834,000		2,176,000
Not designated as hedging instruments
Derivatives not designated as hedging instruments
Amount of gain recognized in operating revenues	80,942,000		2,834,000		2,176,000
Cash flow hedges | Commodity derivatives
Commodity derivatives designated as cash flow hedges
Amount of gain recognized in OCI (effective portion), net of tax	156,207,000		10,669,000		86,259,000
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	16,735,000		0		0
Amount of (loss) gain reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	-15,950,000		87,158,000		180,137,000
Amount of gain (loss) recognized in operating revenues (ineffective portion)	24,774,000	[1]	-21,335,000	[1]	-75,000	[1]
Interest rate derivatives designated as cash flow hedges
Amount of loss recognized in OCI (effective portion), net of tax	156,207,000		10,669,000		86,259,000
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense due to forecasted transactions no longer being probable	16,735,000		0		0
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	-15,950,000		87,158,000		180,137,000
Cash flow hedges | Interest rate derivatives
Commodity derivatives designated as cash flow hedges
Amount of gain recognized in OCI (effective portion), net of tax	0		0		-7,138,000
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		0		-13,266,000
Amount of (loss) gain reclassified from accumulated OCI, net of tax, into operating revenues (effective portion)	-145,000		-144,000		-241,000
Interest rate derivatives designated as cash flow hedges
Amount of loss recognized in OCI (effective portion), net of tax	0		0		-7,138,000
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense due to forecasted transactions no longer being probable	0		0		-13,266,000
Amount of loss reclassified from accumulated OCI, net of tax, into interest expense (effective portion)	-145,000		-144,000		-241,000
Fair value hedges | Commodity derivatives
Commodity derivatives designated as fair value hedges
Amount of (loss) gain recognized in operating revenues for fair value commodity contracts	0	[2]	-1,341,000	[2]	3,878,000	[2]
Fair value gain recognized in operating revenues for inventory designated as hedged item	0	[2]	386,000	[2]	3,292,000	[2]
Derivatives not designated as hedging instruments
Amount of gain (loss) recognized in income due to exclusion of the spot/forward differential from the assessment of effectiveness			500,000		7,600,000
Amount of gain (loss) recognized in income due to changes in basis			$1,500,000		$400,000
[1]	No amounts have been excluded from effectiveness testing of cash flow hedges.
[2]	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. For the year ended December 31, 2012, the net impact on operating revenues consisted of a $7.6 million gain due to the exclusion of the spot/forward differential from the assessment of effectiveness and a $0.4 million loss due to changes in basis.

Derivative_Instruments_Asset_a

Derivative Instruments - Asset and Liability Derivatives (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset and liability derivatives
Derivatives designated as hedging instruments	$458,460	$107,647
Derivatives designated as hedging instruments	22,942	29,651
Commodity derivatives
Asset and liability derivatives
Derivatives designated as hedging instruments	458,460	107,647
Derivatives designated as hedging instruments	22,942	29,651
Commodity derivatives designated as hedging instruments | Commodity derivatives
Asset and liability derivatives
Derivatives designated as hedging instruments	0	104,430
Derivatives designated as hedging instruments	0	27,618
Commodity derivatives not designated as hedging instruments | Commodity derivatives
Asset and liability derivatives
Derivatives designated as hedging instruments	458,460	3,217
Derivatives designated as hedging instruments	$22,942	$2,033

Derivative_Instruments_Impact_

Derivative Instruments - Impact of Netting Agreements and Margin Deposits (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset derivatives:
Derivative instruments, at fair value	$458,460	$107,647
Liability derivatives:
Derivative instruments, at fair value	22,942	29,651
Commodity derivatives
Asset derivatives:
Derivative instruments, at fair value	458,460	107,647
Derivative instruments subject to master netting agreements	-22,810	-20,843
Margin deposits remitted to counterparties	0
Derivative instruments, net	435,650	86,804
Liability derivatives:
Derivative instruments, at fair value	22,942	29,651
Derivative instruments subject to master netting agreements	-22,810	-20,843
Margin deposits remitted to counterparties	-132	-266
Derivative instruments, net	$0	$8,542

Fair_Value_Measurements_Narrat

Fair Value Measurements - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair value measurements
Fair value derivative instruments Level 3 to Level 2 Transfers Amount		$54,400,000
Estimated fair value of long-term debt	3,300,000,000	2,800,000,000
Equitable Gas and Homeworks
Fair value measurements
Cash proceeds	748,000,000
Preliminary estimated fair value of assets	140,900,000
Preliminary estimated fair value of other contractual assets	$32,500,000

Fair_Value_Measurements_Deriva

Fair Value Measurements - Derivative Instrument Assets and Liabilities Measured at Fair Value (Detail) (Fair value on a recurring basis, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets
Derivative instruments, at fair value	$458,460	$107,647
Liabilities
Derivative instruments, at fair value	22,942	29,651
Quoted prices in active markets for identical assets (Level 1)
Assets
Derivative instruments, at fair value	0	240
Liabilities
Derivative instruments, at fair value	132	315
Significant other observable inputs (Level 2)
Assets
Derivative instruments, at fair value	458,460	107,407
Liabilities
Derivative instruments, at fair value	22,810	29,336
Significant unobservable inputs (Level 3)
Assets
Derivative instruments, at fair value	0	0
Liabilities
Derivative instruments, at fair value	$0	$0

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Value Measurements Using Significant Unobservable Inputs (Details) (Derivative instruments, at fair value, net, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative instruments, at fair value, net
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation
Beginning of period	$0	$90,714
Total gains or losses:
Included in earnings	0	640
Included in OCI	0	-2,554
Purchases	0	0
Settlements	0	-34,381
Transfers in and/or out of Level 3	0	-54,419
End of period	$0	$0

Sales_of_Properties_and_Contra1

Sales of Properties and Contracts (Details) (USD $)	0 Months Ended	12 Months Ended
	Jun. 16, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 17, 2013
Schedule of Equity Method Investments [Line Items]
Proceeds from sale of energy marketing contracts in cash		$0	$23,000,000	$0
Pre-tax gain recorded		34,146,000	19,618,000	0
Pre-tax gain on de-designation of derivative instruments	28,000,000
Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%	0.00%
EQT
Schedule of Equity Method Investments [Line Items]
Pre-tax gain recorded		27,400,000
Range Resources Corporation
Schedule of Equity Method Investments [Line Items]
Approximate area of acquisition (in acres)	73,000
Number of producing wells acquired	900
Area of property transferred under asset exchange agreement (in acres)	138,000
Number of producing wells transferred under asset exchange agreement	2,000
Ownership interest transferred	50.00%
Fair value of the consideration acquired	516,500,000
Pre-tax gain recorded	34,100,000
Range Resources Corporation | Acreage
Schedule of Equity Method Investments [Line Items]
Fair value of the consideration acquired	318,300,000
Range Resources Corporation | Wells
Schedule of Equity Method Investments [Line Items]
Fair value of the consideration acquired	198,200,000
Range Resources Corporation | EQT
Schedule of Equity Method Investments [Line Items]
Amount of cash, subject to certain post-closing adjustments	167,300,000
Range Resources Corporation | EQT | Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Amount of cash, subject to certain post-closing adjustments	167,300,000
Ownership percentage		50.00%
Pre-tax gain recorded		6,800,000
Equitable Gas and Homeworks
Schedule of Equity Method Investments [Line Items]
Sale of energy marketing contracts			20,000,000
Number of customers with whom natural gas sale agreements are entered			1,000
Sale volumes of energy marketing contracts (in Mcf)			12,000
Proceeds from sale of energy marketing contracts in cash			18,000,000
Amount expected to be collected			2,000,000
Gain on sale of energy marketing contracts			19,600,000
Number of customers with whom natural gas sale agreements are entered related to certain acquired assets			50
Value of energy marketing contracts					5,000,000
Sale of energy marketing contracts related to certain acquired assets			$5,000,000

Acquisitions_Details

Acquisitions (Details) (USD $)	12 Months Ended						1 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Jun. 30, 2013
							acre
Acquisitions
Purchase price of acquisition allocated to undeveloped acreage	$493,067,000	[1],[2]	$95,861,000	[1],[2]	$117,654,000	[1],[2]
Purchase price of acquisition allocated to acquired wells	231,322,000	[2],[3]	90,390,000	[2],[3]	16,965,000	[2],[3]
Chesapeake
Acquisitions
Approximate area of acquisition (in acres)							99,000
Purchase price of acquisition							114,200,000
Purchase price of acquisition allocated to undeveloped acreage							57,200,000
Chesapeake | Marcellus
Acquisitions
Approximate area of acquisition (in acres)							67,000
Number of wells acquired							10
Portion unlikely to be developed (in acres)							42,000
Purchase price of acquisition allocated to undeveloped acreage			41,900,000	[1],[2]
Purchase price of acquisition allocated to acquired wells							$57,000,000
[1]	Amounts include $317.2 million for the purchase of Permian leases acquired in the Range acquisition in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake acquisition in 2013.
[2]	Amounts exclude capital expenditures for facilities and information technology.
[3]	Amounts include $198.2 million and $1.1 million for the purchase of Permian wells and leases, respectively, acquired in the Range acquisition in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake acquisition in 2013.

Income_Taxes_Income_Tax_Expens

Income Taxes - Income Tax Expense (Benefit) from Continuing Operations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	$164,935	$100,796	$3,771
State	17,136	46,758	229
Subtotal	182,071	147,554	4,000
Deferred:
Federal	38,357	51,767	56,551
State	-6,336	-23,940	11,014
Subtotal	32,021	27,827	67,565
Amortization of deferred investment tax credit	0	-195	-104
Total income taxes	$214,092	$175,186	$71,461

Income_Taxes_Narrative_Details

Income Taxes - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal statutory rate	35.00%
Effective tax rate	29.60%	33.60%	32.40%
State tax benefits offsetting income tax		$9.80
Percentage of consolidated pre-tax income related to the noncontrolling public limited partners' share of partnership earnings	100.00%
Tax deductible, but uncertainty about the timing of deductibility	6.9	7.6	6.4
Decrease in unrecognized tax benefits	10.1	9.8
Interest expense (reversal)	-1.9	0.4	1.8
Interest and penalties included in balance sheet	2	0.2	0.5
Unrecognized tax benefits that would impact effective tax rate	33.9	33.3	5.3
Deferred assets/(liability) related to net unrealized income/loss from hedging transactions	141.3	38.7
Deferred tax asset related to other post-retirement benefits	5.4	5.3
Deferred tax asset related to pension plans	5.1	4.8
Total deferred tax asset related to the federal NOL carryforward	30.8
Deferred tax asset related to NOL carryforward	88	1.1	29.7
Increase (decrease) in deferred tax asset for uncertain tax positions related to federal operating loss carryforwards	11.7	10.6
NOL carryforward period	20 years
Deferred tax asset for state NOL carryforwards	116	118.2
Valuation allowance pertaining to NOL carryforwards	65	56.4
Reduction in deferred tax asset for uncertain tax positions related to state NOL carryforwards	0.3	0.3
Excess tax benefit			8.1
Tax benefits recognized as an addition to common stockholders' equity	26.6
Excess tax benefits previously not recorded	$6.60

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Income Tax Expense to Federal Statutory Rate (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Tax at statutory rate	$253,299	$182,406	$77,133
State income taxes	7,020	16,180	2,869
Noncontrolling partners’ share of Partnership earnings	-43,409	-16,535	-4,571
Other	-2,818	-6,865	-3,970
Total income taxes	$214,092	$175,186	$71,461
Effective tax rate	29.60%	33.60%	32.40%

Income_Taxes_Reconciliation_of1

Income Taxes - Reconciliation of Beginning and Ending Reserve for Uncertain Tax Positions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of reserve for uncertain tax positions, Excluding Amounts Pertaining to Examined Tax Returns
Beginning Balance	$57,087	$17,858	$30,730
Additions based on tax positions related to current year	1,195	49,289	2,165
Additions for tax positions of prior years	93	0	2,320
Settlements	0	0	0
Reductions for tax positions of prior years	-1,418	-790	-12,235
Lapse of statute of limitations	0	-9,270	-5,122
Ending Balance	$56,957	$57,087	$17,858

Income_Taxes_Summary_of_Net_De

Income Taxes - Summary of Net Deferred Income Tax Liabilities (Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred income taxes:
Total deferred income tax assets .	($961,556)	($612,705)
Total deferred income tax liabilities	2,690,492	2,237,465
Total (including amounts classified as current assets of $21,934 and $31,005, respectively)	1,728,936	1,624,760
Total deferred income tax liabilities (assets)
Drilling and development costs expensed for income tax reporting	1,391,156	1,190,357
Tax depreciation in excess of book depreciation	1,154,082	1,018,255
Accumulated OCI	130,770	28,597
Post-retirement benefits	3,146	256
Incentive compensation	-65,086	-60,863
Net operating loss carryforwards	-212,718	-358,964
Investment in Partnership	-336,394	-2,801
Alternative minimum tax credit carryforward	-412,345	-246,157
Other	11,338	-324
Total excluding valuation allowances	1,663,949	1,568,356
Valuation allowance	64,987	56,404
Total (including amounts classified as current assets of $21,934 and $31,005, respectively)	1,728,936	1,624,760
Amounts classified as current assets	$21,934	$31,005

Equity_in_Nonconsolidated_Inve2

Equity in Nonconsolidated Investments - Summary of Equity in Nonconsolidated Investments (Details) (USD $)	Dec. 31, 2014	Jun. 16, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Schedule of Equity Method Investments [Line Items]
Equity in nonconsolidated investments	$0		$128,983
Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	0.00%	50.00%
Equity in nonconsolidated investments	$0		$128,983

Equity_in_Nonconsolidated_Inve3

Equity in Nonconsolidated Investments - Narrative (Details) (USD $)	12 Months Ended			0 Months Ended		1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 16, 2014	Sep. 02, 2014	Sep. 30, 2014
					mi	mi
Schedule of Equity Method Investments [Line Items]
Pre-tax gain recorded	$34,146,000	$19,618,000	$0
Equity in earnings of nonconsolidated investments	3,400,000	7,600,000	6,100,000
Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	0.00%			50.00%
EQT Midstream
Schedule of Equity Method Investments [Line Items]
Pre-tax gain recorded	6,800,000	19,600,000
EQT Midstream | Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%
EQT
Schedule of Equity Method Investments [Line Items]
Pre-tax gain recorded	27,400,000
Range Resources Corporation
Schedule of Equity Method Investments [Line Items]
Pre-tax gain recorded				34,100,000
Range Resources Corporation | EQT
Schedule of Equity Method Investments [Line Items]
Payments to acquire oil and gas property				167,300,000
Range Resources Corporation | EQT | Nora Gathering, LLC
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%
Payments to acquire oil and gas property				167,300,000
Pre-tax gain recorded	$6,800,000
Mountain Valley Pipeline
Schedule of Equity Method Investments [Line Items]
Gas and Oil Length of Pipeline					300	300

Equity_in_Nonconsolidated_Inve4

Equity in Nonconsolidated Investments - Summarized Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Equity Method Investments and Joint Ventures [Abstract]
Current assets	$0	$27,014
Noncurrent assets	0	239,583
Total assets	0	266,597
Current liabilities	0	8,529
Stockholders’ equity	0	258,068
Total liabilities and stockholders’ equity	$0	$266,597

Equity_in_Nonconsolidated_Inve5

Equity in Nonconsolidated Investments - Summarized Statements of Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity Method Investments and Joint Ventures [Abstract]
Revenues	$19,924	$45,040	$47,888
Operating expenses	13,155	29,810	35,596
Net income	$6,769	$15,230	$12,292

ShortTerm_Loans_Details

Short-Term Loans (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Feb. 28, 2014
	extension
	financial_institution
Line of Credit Facility
Revolving credit facility maximum borrowing capacity	$1,500,000,000
Number of times the maturity date of the credit facility can be extended by one year	2
Length of extension of line of credit	1 year
Aggregate potential increased lenders' commitment	2,000,000,000
Number of financial institutions underwriting credit facility of the entity	18
Maximum amount of outstanding short-term loans at any time during the period		178,500,000
Average daily balance of short-term loans outstanding during the period		12,100,000
Weighted average interest rates of average daily balance of short-term loans (as a percent)		1.70%
Percentage of total debt to total capital, maximum	65.00%
Line of credit
Line of Credit Facility
Commitment fee paid to maintain credit facility	23.00%	24.00%
EQT Midstream Partners
Line of Credit Facility
Revolving credit facility maximum borrowing capacity			750,000,000
Aggregate potential increased lenders' commitment	1,000,000,000
Maximum amount of outstanding short-term loans at any time during the period	450,000,000
Average daily balance of short-term loans outstanding during the period	119,000,000
Weighted average interest rates of average daily balance of short-term loans (as a percent)	1.70%
Revolving credit facility outstanding amount at the end of period		$0
EQT Midstream Partners | Line of credit
Line of Credit Facility
Commitment fee paid to maintain credit facility	24.00%	25.00%
Debt instrument covenant consolidated leverage ratio before obtaining investment grade rating	5
Debt instrument covenant consolidated leverage ratio after obtaining investment grade rating	5.5

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt	$2,988,900	$2,501,516
Less debt payable within one year	166,011	11,162
Total long-term debt	2,822,889	2,490,354
7.76% notes, due 2015 thru 2016
Debt Instrument [Line Items]
Long-term debt	10,700	18,316
Interest rate	7.76%	7.76%
5.00% notes, due October 1, 2015
Debt Instrument [Line Items]
Long-term debt	150,000	150,000
Interest rate	5.00%	5.00%
5.15% notes, due March 1, 2018
Debt Instrument [Line Items]
Long-term debt	200,000	200,000
Interest rate	5.15%	5.15%
6.50% notes, due April 1, 2018
Debt Instrument [Line Items]
Long-term debt	500,000	500,000
Interest rate	6.50%	6.50%
8.13% notes, due June 1, 2019
Debt Instrument [Line Items]
Long-term debt	700,000	700,000
Interest rate	8.13%	8.13%
4.88% notes, due November 15, 2021
Debt Instrument [Line Items]
Long-term debt	750,000	750,000
Interest rate	4.88%	4.88%
7.75% debentures, due July 15, 2026
Debt Instrument [Line Items]
Long-term debt	115,000	115,000
Interest rate	7.75%	7.75%
Medium-term notes, 7.3% to 7.6% Series B, due 2015 thru 2023
Debt Instrument [Line Items]
Long-term debt	20,000	20,000
Interest rate, minimum	7.30%	7.30%
Interest rate, maximum	7.60%	7.60%
Medium-term notes, 7.6% Series C, due 2018
Debt Instrument [Line Items]
Long-term debt	8,000	8,000
Interest rate	7.60%	7.60%
Medium-term notes, 8.7% to 9.0% Series A, due 2020 thru 2021
Debt Instrument [Line Items]
Long-term debt	35,200	40,200
Interest rate, minimum	8.70%	8.70%
Interest rate, maximum	9.00%	9.00%
EQT Midstream | 4.00% EQT Midstream Partners notes, due August 1, 2024
Debt Instrument [Line Items]
Long-term debt	$500,000	$0
Interest rate	4.00%	4.00%

LongTerm_Debt_Narrative_Detail

Long-Term Debt - (Narrative) (Details) (USD $)	Dec. 31, 2014	Aug. 31, 2014
Debt Instrument [Line Items]
Aggregate maturities in 2015	$166,000,000
Aggregate maturities in 2016	3,000,000
Aggregate maturities in 2017	0
Aggregate maturities in 2018	708,000,000
Aggregate maturities in 2019	700,000,000
EQT Midstream | Senior Notes | 4.00% Senior Notes
Debt Instrument [Line Items]
Interest rate		4.00%
Face amount		$500,000,000

Pension_and_Other_PostRetireme2

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 $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	$21,828	$63,270
Service cost	350	500	500
Interest cost	820	1,935	2,448
Amendments	0	0
Actuarial loss (gain)	2,412	-3,038
Benefits paid	-1,988	-5,269
Expenses paid	-262	-493
Divestitures	0	-34,410
Settlements	-1,456	-667
Benefit obligation at end of year	21,704	21,828	63,270
Change in plan assets:
Fair value of plan assets at beginning of year	20,089	46,984
Actual gain on plan assets	1,217	7,304
Contributions	723	2,639	2,900
Benefits paid	-1,988	-5,269
Expenses paid	-262	-493
Divestitures	0	-30,409
Settlements	-1,456	-667
Fair value of plan assets at end of year	18,323	20,089	46,984
Funded status at end of year	-3,381	-1,739
Other Benefits
Change in benefit obligation:
Benefit obligation at beginning of year	18,253	36,255
Service cost	669	905	737
Interest cost	693	1,110	1,427
Amendments	227	0
Actuarial loss (gain)	1,190	-2,355
Benefits paid	-2,291	-3,961
Expenses paid	0	0
Divestitures	0	-13,701
Settlements	0	0
Benefit obligation at end of year	18,741	18,253	36,255
Change in plan assets:
Fair value of plan assets at beginning of year	493	165
Actual gain on plan assets	0	0
Contributions	330	328
Benefits paid	0	0
Expenses paid	0	0
Divestitures	0	0
Settlements	0	0
Fair value of plan assets at end of year	823	493	165
Funded status at end of year	($17,918)	($17,760)

Pension_and_Other_PostRetireme3

Pension and Other Post-Retirement Benefit Plans - Schedule of Amounts Recognized in Statement of Financial Position (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Amounts recognized in accumulated OCI, net of tax, consist of:
Net amount recognized	$16,640	$15,864
Pension Benefits
Amounts recognized in the statement of financial position consist of:
Current liabilities	0	0
Noncurrent liabilities	-3,381	-1,739
Net amounts recognized	-3,381	-1,739
Amounts recognized in accumulated OCI, net of tax, consist of:
Net loss	8,082	7,524
Net prior service (credit)	0	0
Net amount recognized	8,082	7,524
Other Benefits
Amounts recognized in the statement of financial position consist of:
Current liabilities	-924	-1,341
Noncurrent liabilities	-16,994	-16,419
Net amounts recognized	-17,918	-17,760
Amounts recognized in accumulated OCI, net of tax, consist of:
Net loss	8,273	8,234
Net prior service (credit)	285	106
Net amount recognized	$8,558	$8,340

Pension_and_Other_PostRetireme4

Pension and Other Post-Retirement Benefit Plans - Narrative (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Jan. 02, 2014
Defined Benefit Plans costs
Defined Benefit Plan, Accumulated Benefit Obligation	$21,700,000	$21,800,000		$21,700,000
Annual rate of increase in Pre-65 medical charges	7.25%
Assumption for ultimate decrease in annual medical rates in 2018	5.00%
Expense recognized related to 401(k) employee savings plans	13,700,000	14,600,000	12,000,000
Quoted prices in active markets for identical assets (Level 1) | Mutual Funds
Defined Benefit Plans costs
Fair value of plan assets	5,700,000	6,900,000		5,700,000
Significant other observable inputs (Level 2) | Common Collective Trusts
Defined Benefit Plans costs
Fair value of plan assets	12,600,000	13,200,000		12,600,000
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				400,000
Expected return on plan assets	7.75%	7.75%
Cash contributions to pension plan	723,000	2,639,000	2,900,000
Expected cash payments related to its pensions	600,000
Expected percentage of funding obligations met by cash contributions	80.00%
Benchmark percentage of funding obligations targeted to be met through cash contributions	80.00%
Defined benefit plan, expected future benefit payments in year 2015	2,100,000			2,100,000
Defined benefit plan, expected future benefit payments in year 2017	1,800,000			1,800,000
Defined benefit plan, expected future benefit payments in year 2016	1,900,000			1,900,000
Defined benefit plan, expected future benefit payments in year 2018	1,700,000			1,700,000
Defined benefit plan, expected future benefit payments in year 2019	1,900,000			1,900,000
Defined benefit plan, expected future benefit payments in the five years thereafter	7,700,000			7,700,000
Fair value of plan assets	18,323,000	20,089,000	46,984,000	18,323,000
Pension Benefits | Minimum
Defined Benefit Plans costs
Expected return on plan assets					5.50%
Pension Benefits | Maximum
Defined Benefit Plans costs
Expected return on plan assets					6.25%
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				400,000
Net prior service credit of other post-retirement benefit plans, amortized from accumulated OCI, net of tax, into net periodic benefit cost				-200,000
Cash contributions to pension plan	330,000	328,000
Defined benefit plan, expected future benefit payments in year 2015	1,800,000			1,800,000
Defined benefit plan, expected future benefit payments in year 2017	1,700,000			1,700,000
Defined benefit plan, expected future benefit payments in year 2016	1,700,000			1,700,000
Defined benefit plan, expected future benefit payments in year 2018	1,700,000			1,700,000
Defined benefit plan, expected future benefit payments in year 2019	1,600,000			1,600,000
Defined benefit plan, expected future benefit payments in the five years thereafter	7,600,000			7,600,000
Fair value of plan assets	823,000	493,000	165,000	823,000
Equitable Gas and Homeworks
Defined Benefit Plans costs
Net loss and prior service cost		$17,300,000

Pension_and_Other_PostRetireme5

Pension and Other Post-Retirement Benefit Plans - Schedule of Components of Net Periodic Benefit Cost (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits
Components of net periodic benefit cost:
Service cost	$350	$500	$500
Interest cost	820	1,935	2,448
Expected return on plan assets	-1,377	-3,323	-3,712
Amortization of prior service cost	0	0	0
Recognized net actuarial loss	709	2,306	1,880
Settlement loss and special termination benefits	879	381	725
Subtotal	1,381	1,799	1,841
Net periodic benefit cost of discontinued operations	0	1,552	1,586
Net periodic benefit cost of discontinued operations	1,381	247	255
Other Benefits
Components of net periodic benefit cost:
Service cost	669	905	737
Interest cost	693	1,110	1,427
Expected return on plan assets	0	0	0
Amortization of prior service cost	-446	-845	-845
Recognized net actuarial loss	879	1,760	1,671
Settlement loss and special termination benefits	0	0	0
Subtotal	1,795	2,930	2,990
Net periodic benefit cost of discontinued operations	0	1,356	1,288
Net periodic benefit cost of discontinued operations	$1,795	$1,574	$1,702

Pension_and_Other_PostRetireme6

Pension and Other Post-Retirement Benefit Plans - Schedule of Amount Recognized in Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
Total recognized in OCI, net of tax	$776	($21,501)	$1,085
Pension Benefits
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
Net loss	558	712	261
Net prior service cost	0	0	0
Total recognized in OCI, net of tax	558	712	261
Total recognized in net periodic benefit cost and OCI, net of tax	1,939	959	2,102
Other Benefits
Other changes in plan assets and benefit obligations recognized in OCI, net of tax:
Net loss	39	2,147	494
Net prior service cost	179	416	330
Total recognized in OCI, net of tax	218	2,563	824
Total recognized in net periodic benefit cost and OCI, net of tax	$2,013	$4,137	$3,814

Pension_and_Other_PostRetireme7

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, 2014	Dec. 31, 2013
Pension Benefits
Components of net periodic benefit cost:
Benefit obligations, Discount rate	3.60%	4.00%
Net periodic benefit cost, Discount rate	4.00%	3.25%
Expected return on plan assets	7.75%	7.75%
Other Benefits
Components of net periodic benefit cost:
Benefit obligations, Discount rate	3.60%	4.00%
Net periodic benefit cost, Discount rate	4.00%	3.25%

Pension_and_Other_PostRetireme8

Pension and Other Post-Retirement Benefit Plans - Schedule of Impact of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Compensation and Retirement Disclosure [Abstract]
Increase (decrease) to total of service and interest cost components, One-Percent-Point-Increase	$13	$25	$32
Increase (decrease) to total of service and interest cost components, One-Percentage-Point-Decrease	-14	-26	-32
Increase (decrease) to post-retirement benefit obligation, One-Percentage-Point-Increase	228	220	711
Increase (decrease) to post-retirement benefit obligation, One-Percentage-Point-Decrease	($229)	($223)	($688)

Pension_and_Other_PostRetireme9

Pension and Other Post-Retirement Benefit Plans - Schedule of Entity's Asset Allocation (Details)	22 Months Ended
	Oct. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
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		26.00%	42.00%
Fixed income securities
Components of net periodic benefit cost:
Percentage of Plan Assets		63.00%	29.00%
International broadly diversified equity securities
Components of net periodic benefit cost:
Percentage of Plan Assets		8.00%	7.00%
Alternative fixed income securities
Components of net periodic benefit cost:
Percentage of Plan Assets		0.00%	4.00%
Cash and equivalent investments
Components of net periodic benefit cost:
Percentage of Plan Assets		3.00%	18.00%
Minimum | Domestic broadly diversified equity securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	40.00%
Minimum | Fixed income securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	20.00%
Minimum | International broadly diversified equity securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	5.00%
Minimum | Alternative fixed income securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	0.00%
Minimum | Cash and equivalent investments
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	0.00%
Maximum | Domestic broadly diversified equity securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	60.00%
Maximum | Fixed income securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	50.00%
Maximum | International broadly diversified equity securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	15.00%
Maximum | Alternative fixed income securities
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	10.00%
Maximum | Cash and equivalent investments
Components of net periodic benefit cost:
Target Allocation January 2013 - October 2014	15.00%

Changes_in_Accumulated_Other_C2

Changes in Accumulated Other Comprehensive Income by Component (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Changes in accumulated other comprehensive income (loss)
Balance at the beginning of the period	$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
Losses (gains) reclassified from accumulated OCI, net of tax	15,319		-67,594
Other comprehensive income (loss)	154,791		-54,844		-88,594
Balance at the end of the period	199,494		44,703		99,547
Cash flow hedge, net of tax | Natural gas
Changes in accumulated other comprehensive income (loss)
Balance at the beginning of the period	61,699		138,188
Gains recognized in accumulated OCI, net of tax	156,207	[1]	10,669	[1]
Gain reclassified from accumulated OCI, net of tax, into gain on sale / exchange of assets	-16,735	[1]
Losses (gains) reclassified from accumulated OCI, net of tax	15,950	[1]	-87,158	[1]
Other comprehensive income (loss)	155,422		-76,489
Balance at the end of the period	217,121		61,699
Cash flow hedge, net of tax | Interest rate
Changes in accumulated other comprehensive income (loss)
Balance at the beginning of the period	-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
Losses (gains) reclassified from accumulated OCI, net of tax	145	[1]	144	[1]
Other comprehensive income (loss)	145		144
Balance at the end of the period	-987		-1,132
Pension and other post-retirement benefits liability adjustment, net of tax
Changes in accumulated other comprehensive income (loss)
Balance at the beginning of the period	-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
Losses (gains) reclassified from accumulated OCI, net of tax	-776	[2]	19,420	[2]
Other comprehensive income (loss)	-776		21,501
Balance at the end of the period	($16,640)		($15,864)
[1]	See Note 5 for additional information.
[2]	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 13 for additional information.

Common_Stock_and_Earnings_Per_2

Common Stock and Earnings Per Share (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Reserved, Authorized and Unissued Common Stock
Possible future acquisitions (in shares)	20,457,000																20,457,000
Stock compensation plans (in shares)	16,236,000																16,236,000
Total (in shares)	36,693,000																36,693,000
Basic earnings per common share:
Net income attributable to EQT Corporation	($14,704)	[1]	$98,555	[1]	$110,921	[1]	$192,193	[1]	$115,205	[1]	$88,256	[1]	$86,856	[1]	$100,255	[1]	$386,965		$390,572		$183,395
Average common shares outstanding																	151,553,000		150,574,000		149,619,000
Net income (in dollars per share)	($0.10)	[1]	$0.65	[1]	$0.73	[1]	$1.27	[1]	$0.76	[1]	$0.59	[1]	$0.58	[1]	$0.67	[1]	$2.55		$2.59		$1.23
Diluted earnings per common share:
Net income attributable to EQT Corporation	($14,704)	[1]	$98,555	[1]	$110,921	[1]	$192,193	[1]	$115,205	[1]	$88,256	[1]	$86,856	[1]	$100,255	[1]	$386,965		$390,572		$183,395
Average common shares outstanding																	151,553,000		150,574,000		149,619,000
Potentially dilutive securities:
Stock options and awards (in shares)																	960,000	[2]	1,213,000	[2]	887,000	[2]
Total (in shares)																	152,513,000		151,787,000		150,506,000
Net income (in dollars per share)	($0.10)	[1]	$0.65	[1]	$0.73	[1]	$1.26	[1]	$0.75	[1]	$0.58	[1]	$0.57	[1]	$0.66	[1]	$2.54		$2.57		$1.22
Options to purchase common stock excluded from potentially dilutive securities (in shares)																	0		0		281,528
[1]	The sum of the quarterly data in some cases may not equal the yearly total due to rounding.
[2]	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. Options to purchase common stock which were excluded from potentially dilutive securities because they were anti-dilutive totaled 281,528 shares for the year ended December 31, 2012.

ShareBased_Compensation_Plans_1

Share-Based Compensation Plans - Share-Based Compensation Expense (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$50,627	$58,544	$45,821
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	4,688	3,033	2,007
Non-qualified stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	3,002	3,805	3,580
Other programs, including non-employee director awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	-409	9,154	3,763
2010 Executive Performance Incentive Programs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	0	1,940
2012 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	7,743	6,739	10,633
2013 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	8,208	6,602	0
2014 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	9,104	0	0
2010 Stock Incentive Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	0	4,022
2011 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	13,834	5,286
2011 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	0	3,033
2012 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	0	2,327	11,557
2013 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	4,403	13,050	0
2014 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	11,510	0	0
2014 EQM Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	$2,378	$0	$0

ShareBased_Compensation_Plans_2

Share-Based Compensation Plans - Share-Based Compensation Expense (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Cash received from exercises of all share-based payment arrangements for employees and directors	$19.20	$32.90	$7.90
Income tax benefit by the exercise of nonqualified employee stock options and vesting of restricted share awards	45.9	14.4	15.1
Excess tax benefit			$8.10

ShareBased_Compensation_Plans_3

Share-Based Compensation Plans - Executive Performance Incentive Programs (Narrative) (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013	Mar. 31, 2015	Jan. 01, 2014
2010 Executive Performance Incentive Programs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value, granted (in dollars per share)	$60.09
Expected term	3 years
Risk-free interest rate	1.69%
Number of units distributed		192,744
Aggregate Fair Value of shares, Vested		$6,900,000
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%
Capitalized compensation cost	2,600,000	2,100,000	8,100,000
2012 Executive Performance Incentive Program | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units distributed				307,323
Aggregate Fair Value of shares, Vested				37,900,000
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	5,500,000		5,000,000
Shares outstanding					297,597
Non-vested shares, forfeited	26,534
Shares outstanding, adjusted for forfeitures	271,063
Unrecognized compensation costs on non-vested awards	12,600,000
2013 Executive Performance Incentive Plan | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level	0.00%
2013 Executive Performance Incentive Plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation plan, award as a percentage of target award level	300.00%
2014 Executive Performance Incentive Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted	278,440
Weighted average fair value, granted (in dollars per share)	$167.12
Expected term	3 years
Risk-free interest rate	0.78%
Capitalized compensation cost	4,600,000
Non-vested shares, forfeited	19,210
Shares outstanding, adjusted for forfeitures	259,230
Unrecognized compensation costs on non-vested awards	$27,300,000
Unrecognized compensation costs on non-vested awards, weighted average period of recognition	2 years
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%

ShareBased_Compensation_Plans_4

Share-Based Compensation Plans - 2010 Stock Incentive Award Program (Narrative) (Details) (2010 Stock Incentive Award Program, USD $)	12 Months Ended
	Dec. 31, 2012
2010 Stock Incentive Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units distributed	294,925
Aggregate Fair Value of shares, Vested	$12,600,000

ShareBased_Compensation_Plans_5

Share-Based Compensation Plans - Value Driver Award Programs (Narrative) (Details) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Feb. 29, 2012	Dec. 31, 2012	Feb. 28, 2014	Jan. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
			tranche
2011 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one	50.00%		50.00%
Award vested at end of year two	50.00%		50.00%
Number of tranches			2
Value of vested stock-based award distributed in cash and stock	$15.30	$14.60
2012 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one	50.00%		50.00%
Award vested at end of year two	50.00%		50.00%
Number of tranches			2
Number of units distributed				194,943	204,679
Weighted average fair value, granted (in dollars per share)						$54.79
2013 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one							50.00%
Award vested at end of year two							50.00%
Number of units distributed				306,076
Capitalized compensation cost						2.9	14.1
Shares outstanding						279,761	614,048
Weighted average fair value, granted (in dollars per share)						$58.98
2014 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vested at end of year one						50.00%
Award vested at end of year two						50.00%
Capitalized compensation cost						9.8
Shares outstanding						375,426
Total liability						$21.30

ShareBased_Compensation_Plans_6

Share-Based Compensation Plans - 2011 Volume and Efficiency Program (Narrative) (Details) (2011 EQT Value Driver Award Program, USD $)	1 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Feb. 28, 2014	Dec. 31, 2013	Dec. 31, 2012
2011 EQT Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units distributed	663,350
Weighted average fair value, granted (in dollars per share)	$48.06
Capitalized compensation cost		$2.80	$2.50

ShareBased_Compensation_Plans_7

Share-Based Compensation Plans - Restricted Stock Awards (Narrative) (Details) (Restricted stock awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted	89,500	101,510	103,730
Period after which the shares granted will be fully vested	3 years
Weighted average fair value, granted (in dollars per share)	$94.91	$71	$54
Aggregate Fair Value of shares, Vested	$1,469,604	$4,300,000	$1,600,000
Unrecognized compensation costs on non-vested awards	$9,400,000
Unrecognized compensation costs on non-vested awards, weighted average period of recognition	1 year 6 months

ShareBased_Compensation_Plans_8

Share-Based Compensation Plans - Summary of Restricted Stock Activity (Details) (Restricted stock awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-Vested Shares, Outstanding, Beginning Balance	182,378
Non-Vested Shares, Granted	89,500	101,510	103,730
Non-Vested Shares, Vested	-27,310
Non-Vested Shares, Forfeited	-14,578
Non-Vested Shares, Outstanding, Ending Balance	229,990	182,378
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Fair Value, Outstanding, Beginning Balance (in dollars per share)	$61.98
Weighted Average Fair Value, Granted (in dollars per share)	$94.91	$71	$54
Weighted Average Fair Value, Vested (in dollars per share)	$53.82
Weighted Average Fair Value, Forfeited (in dollars per share)	$75.64
Weighted Average Fair Value, Outstanding, Ending Balance (in dollars per share)	$74.90	$61.98
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value [Abstract]
Aggregate Fair Value, Outstanding, Beginning Balance	$11,302,992
Aggregate Fair Value, Granted	8,494,746
Aggregate Fair Value, Vested	-1,469,604	-4,300,000	-1,600,000
Aggregate Fair Value, Forfeited	-1,102,723
Aggregate Fair Value, Outstanding, Ending Balance	$17,225,411	$11,302,992

ShareBased_Compensation_Plans_9

Share-Based Compensation Plans - Schedule of Valuation Assumptions for Non-Qualified Stock Options (Details) (Non-qualified Stock Options)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Non-qualified Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.72%	0.76%	0.89%
Dividend yield	0.15%	0.22%	1.64%
Volatility factor	24.80%	31.69%	31.44%
Expected term	5 years	5 years	5 years

Recovered_Sheet6

Share-Based Compensation Plans - Non-Qualified Stock Options (Narrative) (Details) (Non-qualified Stock Options, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Non-qualified Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants in period (in shares)	133,500	259,600	278,300
Weighted average grant date fair value (in dollars per share)	$22.25	$16.72	$13.19
Total intrinsic value of options exercised	$14.40	$22.80	$11.80
Unrecognized compensation costs on non-vested awards	$1.90

Recovered_Sheet7

Share-Based Compensation Plans - Summary of Option Activity (Details) (Non-qualified Stock Options, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Non-qualified Stock Options
Non-qualified Stock Options, Shares
Shares, Outstanding, Beginning Balance	1,482,001
Shares, Granted	133,500	259,600	278,300
Shares, Exercised	-277,033
Shares, Forfeited	0
Shares, Outstanding, Ending Balance	1,338,468	1,482,001
Shares, Exercisable	1,079,968
Non-qualified Stock Options, Weighted Average Exercise Price
Weighted Average Exercise Price, Outstanding, Beginning Balance (in dollars per share)	$49.77
Weighted Average Exercise Price, Granted (in dollars per share)	$89.78
Weighted Average Exercise Price, Exercised (in dollars per share)	$48.27
Weighted Average Exercise Price, Forfeited (in dollars per share)	$0
Weighted Average Exercise Price, Outstanding, Ending Balance (in dollars per share)	$54.08	$49.77
Weighted Average Exercise Price, Exercisable (in dollars per share)	$49.09
Non-Qualified Stock Options, Weighted Average Remaining Contractual Term
Weighted Average Remaining Contractual Term, Outstanding, End of Period	6 years 4 months 6 days
Weighted Average Remaining Contractual Term, Exercisable	5 years 9 months 29 days
Non-qualified Stock Options, Aggregate Intrinsic Value
Aggregate Intrinsic Value, Outstanding, End of Period	$30,823,027
Aggregate Intrinsic Value, Exercisable, End of Period	$28,733,027

Recovered_Sheet8

Share-Based Compensation Plans - Non-Employee Directors' Share Based Awards (Narrative) (Details) (Non-employee Directors' Share-Based Awards, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Non-employee Directors' Share-Based Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding	197,778
Shares granted	17,900	25,500	28,140
Weighted average fair value, granted (in dollars per share)	$89.78	$58.98	$53.47

Recovered_Sheet9

Share-Based Compensation Plans - EQM Awards (Narrative) (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
2014 EQM Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding	62,845
Weighted average fair value, granted (in dollars per share)	$58.79
Unrecognized compensation costs on non-vested awards	$0.90
Award vested at end of year one	50.00%
Award vested at end of year two	50.00%
Capitalized compensation cost	0.3
Performance awards | EQM Total Return Programs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding	146,490	142,500
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	2,520
Number of shares granted	139,980
Unrecognized compensation costs on non-vested awards	$0.80
Performance awards | Minimum | EQM Total Return Programs [Member]
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%
Performance awards | Maximum | EQM Total Return Programs [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility factor	72.00%
Phantom units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding	11,759
Weighted average fair value, granted (in dollars per share)	$58.79	$37.92	$24.30
Number of shares granted	2,580	3,790	4,780

Recovered_Sheet10

Share-Based Compensation Plans - 2015 Value Driver Award Programs and 2015 Executive Performance Incentive Program (Narrative) (Details) (Subsequent Event)	12 Months Ended
	Dec. 31, 2015	Jan. 01, 2015
2015 Value Driver Award Program
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted	281,460
Award vested at end of year one		50.00%
Award vested at end of year two		50.00%
2015 Value Driver Award 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 Value Driver Award 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]
Number of shares granted	369,290
Period after which the shares granted will be fully vested	3 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%

Recovered_Sheet11

Share-Based Compensation Plans - 2015 Stock Options (Narrative) (Details) (Subsequent Event, 2015 Stock Options, USD $)	0 Months Ended
	Jan. 01, 2015	Jan. 01, 2015
Subsequent Event | 2015 Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants in period (in shares)	158,200
Term of stock options	10 years
Exercise price (in dollars per share)	$75.70	$75.70
Period after which the shares granted will be fully vested	3 years

Concentrations_of_Credit_Risk_

Concentrations of Credit Risk (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	customer	customer	customer
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 | Accounts receivable
Concentration Risk
Concentration risk	87.00%	82.00%
EQT | Sales revenue goods, net
Concentration Risk
Percentage required for qualification as major customer			10.00%
EQT | Customer concentration | Sales revenue goods, net
Concentration Risk
Number of customers	1	1	0
Concentration risk	12.00%	11.00%

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended			0 Months Ended		1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jul. 24, 2014	Sep. 02, 2014	Sep. 30, 2014
				MMBTU	mi	mi
				mi	MMcf
Operating Leases, Rent
Operating leases, rent expense	$65.60	$56	$45
Amount due in 2014	225.6
Amount due in 2015	83.4
Amount due in 2016	37.4
Amount due in 2017	31.7
Amount due in 2018	16.8
Amount due in 2019	9.6
Amount due thereafter	46.7
Remedial action included in other credits	1.3
OVC Pipeline
Operating Leases, Rent
Gas and Oil Length of Pipeline				36
Term of agreement				20 years
Transmission capacity (in MMBtu per day)				650,000
Mountain Valley Pipeline
Operating Leases, Rent
Gas and Oil Length of Pipeline					300	300
Term of agreement				20 years
Transmission firm capacity (in MMcf per day)					2,000
Pipeline demand charges
Drilling Equipment and Services Supply Agreements [Abstract]
Amount due as of the balance sheet date	4,632.20
Amount due in 2015	205.1
Amount due in 2016	267.8
Amount due in 2017	333.1
Amount due in 2018	353.4
Amount due in 2019	348
Amount due thereafter	3,124.80
Pipeline Demand Charges [Abstract]
Amount due as of the balance sheet date	4,632.20
Drilling equipment and services supply agreements
Drilling Equipment and Services Supply Agreements [Abstract]
Amount due as of the balance sheet date	132
Pipeline Demand Charges [Abstract]
Amount due as of the balance sheet date	$132

Guarantees_Details

Guarantees (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
NORESCO Guarantees, Energy Savings
Undiscounted maximum aggregate payments related to guarantees	$153
Guarantee obligations term	13 years
Mountain Valley Pipeline
Performance guarantee	$130
Percent of obligation to issue new guarantee	33.00%

Interim_Financial_Information_2

Interim Financial Information (Unaudited) (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$703,194	[1]	$578,723	[1]	$526,168	[1]	$661,625	[1]	$493,429	[1]	$479,606	[1]	$473,093	[1]	$415,883	[1]	$2,469,710	$1,862,011	$1,377,222
Operating income	40,330	[1]	231,503	[1]	224,771	[1]	356,791	[1]	181,081	[1]	167,064	[1]	161,980	[1]	144,479	[1]	853,395	654,604	389,629
Amounts attributable to EQT Corporation:
Income from continuing operations	-14,303	[1]	98,555	[1]	109,045	[1]	192,297	[1]	61,933	[1]	86,199	[1]	81,466	[1]	69,131	[1]	385,594	298,729	135,902
Income from discontinued operations	-401	[1]	0	[1]	1,876	[1]	-104	[1]	53,272	[1]	2,057	[1]	5,390	[1]	31,124	[1]	1,371	91,843	47,493
Net income	-14,704	[1]	98,555	[1]	110,921	[1]	192,193	[1]	115,205	[1]	88,256	[1]	86,856	[1]	100,255	[1]	386,965	390,572	183,395
Basic:
Income (loss) from continuing operations (in dollars per share)	($0.10)	[1]	$0.65	[1]	$0.72	[1]	$1.27	[1]	$0.41	[1]	$0.57	[1]	$0.54	[1]	$0.46	[1]	$2.54	$1.98	$0.91
Income from discontinued operations (in dollars per share)	$0	[1]	$0	[1]	$0.01	[1]	$0	[1]	$0.35	[1]	$0.02	[1]	$0.04	[1]	$0.21	[1]	$0.01	$0.61	$0.32
Net income (in dollars per share)	($0.10)	[1]	$0.65	[1]	$0.73	[1]	$1.27	[1]	$0.76	[1]	$0.59	[1]	$0.58	[1]	$0.67	[1]	$2.55	$2.59	$1.23
Diluted:
Income (loss) from continuing operations (in dollars per share)	($0.10)	[1]	$0.65	[1]	$0.72	[1]	$1.26	[1]	$0.40	[1]	$0.57	[1]	$0.54	[1]	$0.46	[1]	$2.53	$1.97	$0.90
Income from discontinued operations (in dollars per share)	$0	[1]	$0	[1]	$0.01	[1]	$0	[1]	$0.35	[1]	$0.01	[1]	$0.03	[1]	$0.20	[1]	$0.01	$0.60	$0.32
Net income (in dollars per share)	($0.10)	[1]	$0.65	[1]	$0.73	[1]	$1.26	[1]	$0.75	[1]	$0.58	[1]	$0.57	[1]	$0.66	[1]	$2.54	$2.57	$1.22
Impairment of long-lived assets	$267,300																$267,339	$0	$0
[1]	The sum of the quarterly data in some cases may not equal the yearly total due to rounding.

Natural_Gas_Producing_Activiti2

Natural Gas Producing Activities (Unaudited) - Costs Incurred Relating to Natural Gas, NGL, and Oil Production Activities (Details) (USD $)	12 Months Ended						1 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Jun. 30, 2013
At December 31:
Capitalized costs	$10,263,547,000	[1]	$8,152,951,000	[1]	$6,750,343,000	[1]
Accumulated depreciation and depletion	2,874,257,000	[1]	2,134,953,000	[1]	1,572,775,000	[1]
Net capitalized costs	7,389,290,000	[1]	6,017,998,000	[1]	5,177,568,000	[1]
Property acquisition:
Proved properties	231,322,000	[1],[2]	90,390,000	[1],[2]	16,965,000	[1],[2]
Unproved properties	493,067,000	[1],[3]	95,861,000	[1],[3]	117,654,000	[1],[3]
Exploration	16,023,000	[1],[4]	4,285,000	[1],[4]	4,827,000	[1],[4]
Development	1,697,501,000	[1]	1,230,301,000	[1]	850,854,000	[1]
Chesapeake
Property acquisition:
Unproved properties							57,200,000
Permian | Range Resources Corporation
Property acquisition:
Unproved properties	317,200,000	[1],[3]
Proved properties, wells	198,200,000
Proved properties, leases	1,100,000
Marcellus | Chesapeake
Property acquisition:
Proved properties							57,000,000
Unproved properties			41,900,000	[1],[3]
Proved properties, wells			57,000,000
Proved properties, leases			$15,300,000
[1]	Amounts exclude capital expenditures for facilities and information technology.
[2]	Amounts include $198.2 million and $1.1 million for the purchase of Permian wells and leases, respectively, acquired in the Range acquisition in 2014 and $57.0 million and $15.3 million for the purchase of Marcellus wells and leases, respectively, acquired in the Chesapeake acquisition in 2013.
[3]	Amounts include $317.2 million for the purchase of Permian leases acquired in the Range acquisition in 2014. Amounts include $41.9 million for the purchase of Marcellus leases acquired in the Chesapeake acquisition in 2013.
[4]	Amounts include capitalizable exploratory costs and exploration expense, excluding impairments.

Natural_Gas_Producing_Activiti3

Natural Gas Producing Activities (Unaudited) - Results of Operations Related to Natural Gas, NGL and Oil Production (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Production costs		$133,488	$108,091	$96,155
Exploration costs		21,716	18,483	10,370
Impairment of long-lived assets	267,300	267,339	0	0
EQT
Revenues:
Affiliated		4,761	5,912	3,433
Nonaffiliated		1,607,969	1,162,745	790,340
Production costs		133,488	108,091	96,155
Exploration costs		21,665	18,483	10,370
Depreciation, depletion and accretion		592,855	578,641	409,628
Impairment of long-lived assets		267,339	0	0
Income tax expense		238,057	183,060	109,660
Results of operations from producing activities (excluding corporate overhead)		$359,326	$280,382	$167,960

Natural_Gas_Producing_Activiti4

Natural Gas Producing Activities (Unaudited) - Reserve Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	well	location	location
	Mcfe	undeveloped_locations	Mcfe
		Mcfe
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Engineer Experience in Years	17 years
Gas and Liquid Carbon Proved Reserves Reviewed Percentage	100.00%
Audit Coverage of Proved Reserves Percentage	80.00%
Audit Coverage of Remaining Properties Percentage	20.00%
Wells per case, operated wells	200
Wells per case, non-operated wells	230
Increase (Decrease) in Natural Gas Equivalent Reserves Due to Change in Prices and Other	301,400,000	191,500,000	754,200,000
Decrease in Natural Gas Equivalent Reserves Due to Change in Prices and Other which was Partially Offset by Negative Revisions		349,000,000
Undeveloped reserves removed	1,047,200,000
Number of Undeveloped Locations and Associated Reserves that were Removed		58
Period undeveloped locations will not be drilled	5 years
Increase (Decrease) in Natural Gas Equivalent Reserves Due to Change in Prices and Other which was Partially Offset by Increased Reserves	845,100,000
Increase in Reserves of Natural Gas Equivalents	3,276,100,000	2,046,600,000	1,655,800,000
Production of Natural Gas Equivalents	488,100,000	367,100,000	261,000,000
Field Increase (Decrease) with Lateral Spacing		1	1
Proved undeveloped reserves	15,300,000
Proved undeveloped reserves, classification term (more than)	5 years
Number of wells drilled in 2014 that will produce in 2015	2

Natural_Gas_Producing_Activiti5

Natural Gas Producing Activities (Unaudited) - Schedule of the Entity's Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	MMcf		MMcf		MMcf
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year	7,561,561		5,985,758		5,347,386
Revision of previous estimates	-228,085		-375,887		-755,788
Purchase of natural gas in place	44,867		472,798		0
Sale of natural gas in place	-198,531		-455		-694
Extensions, discoveries and other additions	3,040,938		1,844,840		1,654,228
Production	-444,796		-365,493		-259,374
End of year	9,775,954		7,561,561		5,985,758
Proved developed reserves:
Beginning of year	3,567,313		2,779,187		2,948,546
End of year	4,257,377		3,567,313		2,779,187
Oil
Proved developed and undeveloped reserves:
Beginning of year	3,956	[1]	3,199	[1]	2,931	[1]
Revision of previous estimates	-905	[1]	270	[1]	265	[1]
Purchase of natural gas in place	2,165	[1]	0	[1]	0	[1]
Sale of natural gas in place	-3	[1]	0	[1]	0	[1]
Extensions, discoveries and other additions	241	[1]	757	[1]	268	[1]
Production	-449	[1]	-270	[1]	-265	[1]
End of year	5,005	[1]	3,956	[1]	3,199	[1]
Proved developed reserves:
Beginning of year	3,892	[1]	3,199	[1]	2,931	[1]
End of year	5,005	[1]	3,892	[1]	3,199	[1]
Cubic Feet Per Thousand Barrel	6,000,000
Natural Gas Liquids
Proved developed and undeveloped reserves:
Beginning of year	127,162	[1]	0	[1]
Revision of previous estimates	-11,306	[1]	94,296	[1]
Purchase of natural gas in place	7,476	[1]	0	[1]
Sale of natural gas in place	-18	[1]	0	[1]
Extensions, discoveries and other additions	38,945	[1]	32,866	[1]
Production	-6,765	[1]	0	[1]
End of year	155,494	[1]	127,162	[1]
Proved developed reserves:
Beginning of year	65,837	[1]	0	[1]
End of year	89,830	[1]	65,837	[1]
Cubic Feet Per Thousand Barrel	6,000,000
[1]	Bbl equals approximately 6 million cubic feet (MMcf).

Natural_Gas_Producing_Activiti6

Natural Gas Producing Activities (Unaudited) - Standard Measure of Discounted Future Cash Flow (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discount Rate to Compute Standard Measure of Future Cash Flow	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	1
Discounted future net cash flows relating to proved oil and gas reserves, change in price of oil sensitivity	10
Discounted future net cash flows relating to proved oil and gas reserves, change in price of natural gas liquids	10
Change in discounted future cash flows for assumed natural gas price change	$4,300,000,000
Change in discounted future cash flows for assumed oil price change	21,800,000
Change in discounted future cash flows for assumed natural gas liquids price change	$551,100,000
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	4.278	3.653	2.793
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	3.191	3.447	2.785
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	4.35	3.693	2.769
Transcontinental Gas Pipe Line 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	4.17	3.521	2.878
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	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	4.243
Utica
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price Used in Computation of Reserves	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	31.92
Marcellus Shale
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price Used in Computation of Additional Oil and Gas Reserves			0.591
Price Used in Computation of Reserves	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 Additional Oil and Gas Reserves			0.764
Price Used in Computation of Reserves	49.47	49.38
Wetzel County
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Price Used in Computation of Additional Oil and Gas Reserves			0.398
Price Used in Computation of Reserves	49.22	51.91
Tennessee Zone 4300 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	2.286	2.842	2.403
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	3.258	3.495	2.782
Price Used in Computation of Reserves	94.99	89.22	82.9

Natural_Gas_Producing_Activiti7

Natural Gas Producing Activities (Unaudited) - Estimated Future Net Cash Flows from Natural Gas and Oil Reserves (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$30,428,815	$25,912,542	$15,250,019
Future production costs	-4,868,079	-4,180,136	-3,070,957
Future development costs	-5,052,195	-4,199,722	-3,082,053
Future income tax expenses	-7,718,407	-6,533,817	-3,324,472
Future net cash flow	12,790,134	10,998,867	5,772,537
10% annual discount for estimated timing of cash flows	-7,980,106	-7,047,588	-3,617,378
Standardized measure of discounted future net cash flows	$4,810,028	$3,951,279	$2,155,159	$3,932,824

Natural_Gas_Producing_Activiti8

Natural Gas Producing Activities (Unaudited) - Summary of Changes in the Standardized Measure of Discounted Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sales and transfers of natural gas and oil produced – net	($1,479,242)	($1,060,566)	($697,618)
Net changes in prices, production and development costs	-1,525,944	-292,533	-3,530,086
Extensions, discoveries and improved recovery, less related costs	2,300,923	1,509,002	917,986
Development costs incurred	1,023,075	1,319,135	548,852
Purchase of minerals in place – net	72,139	348,608	0
Sale of minerals in place – net	-146,476	-252	-807
Revisions of previous quantity estimates	-222,195	106,170	-876,336
Accretion of discount	578,676	343,502	622,072
Net change in income taxes	-529,337	-1,031,105	1,127,272
Timing and other	787,130	554,159	111,000
Net increase (decrease)	858,749	1,796,120	-1,777,665
Beginning of year	3,951,279	2,155,159	3,932,824
End of year	$4,810,028	$3,951,279	$2,155,159